Enterprise Products Partners (EPD) 10-Q 2007 Q1 Quarterly report

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

OR

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

For the transition period from                    to                    .

Commission file number: 1-14323

ENTERPRISE PRODUCTS PARTNERS L.P.

(Exact name of Registrant as Specified in Its Charter)

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

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.

Yesþ          Noo

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 filerþ          Accelerated filero           Non-accelerated filero

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

Yeso          Noþ

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

1

PART I. FINANCIAL INFORMATION.

Item 1.Financial Statements.

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)

	March 31,			December 31,
	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.

2

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS
(Dollars in thousands, except per unit amounts)

	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.

3

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED

COMPREHENSIVE INCOME
(Dollars in thousands)

	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.

4

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Dollars in thousands)

	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.

5

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED PARTNERS’ EQUITY

(See Note 10 for Unit History and Detail of Changes in Limited Partners’ Equity)
(Dollars in thousands)

	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.

6

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

7

          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.

8

     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.

9

     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.

10

          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

(1) Aggregate intrinsic value reflects fully vested unit options at March 31, 2007.

          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

(1)	Determined by dividing the aggregate grant date fair value of awards (including an allowance for forfeitures) by the number of awards issued.
(2)	Aggregate grant date fair value of restricted common unit awards issued during 2007 was $0.4 million based on a grant date market price of our common units of $30.16 per unit and an estimated forfeiture rate of 9.2%.

          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.

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          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

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

          The total fair value of these eleven interest rate swaps at March 31, 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

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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

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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

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

          Depreciation expense for the three months ended March 31, 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.

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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

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

          On occasion, the price we pay to acquire an 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

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     Summarized Financial Information of Unconsolidated Affiliates

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

	Summarized Income Statement Information for the Three Months Ended
	March 31, 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

(1) During the three months ended March 31, 2006, VESCO incurred losses due to the effects of Hurricane Katrina.

     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

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          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

(1)	In accordance with SFAS 6, “Classification of Short-Term Obligations Expected to be Refinanced,” long-term and current maturities of debt reflects the classification of such obligations at March 31, 2007 and December 31, 2006. With respect to Senior Notes E due 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.
(2)	Represents remaining debt obligations assumed in connection with the GulfTerra Merger.
(3)	The March 31, 2007 amount includes $25.0 million related to fair value hedges and a net $4.4 million in unamortized discounts and premiums. The December 31, 2006 amount includes $29.1 million related to fair value hedges and a net $4.4 million in unamortized discounts and premiums.

     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

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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.

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     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.

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          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.

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          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.

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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

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Louisiana; (ii) the south and southeastern United States (primarily in Texas, Louisiana, Mississippi and Alabama); and (iii) certain regions of the central and western United States, including the Rocky Mountains. 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 assigned to each segment on the basis of each asset’s or investment’s principal operations. The principal reconciling difference between consolidated property, plant and equipment and the total value of segment assets is construction-in-progress. Segment assets represent the net book carrying value of facilities and other assets that contribute to gross operating margin of that 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 placed in service. Consolidated intangible assets and goodwill are assigned to each segment based on the classification of the assets to which they relate.

          We consolidate the financial statements of Duncan Energy Partners with those of our own. As a result, our consolidated gross operating margin amounts include the gross operating margin amounts of Duncan Energy Partners on a 100% basis.

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

	For the Three Months
	Ended March 31,
	2007			2006
Revenues(1)	$	3,322,854		$	3,250,074
Less: Operating costs and expenses(1)		(3,124,479	)		(3,046,863	)
Add: Equity in income of unconsolidated affiliates(1)		6,179			4,029
Depreciation, amortization and accretion in operating costs and expenses(2)		119,492			104,816
Operating lease expense paid by EPCO(2)		526			528
Gain on sale of assets in operating costs and expenses(2)		(73	)		(61	)
Total segment gross operating margin	$	324,499		$	312,523

(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.

          A reconciliation of our 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,
	2007			2006
Total segment gross operating margin	$	324,499		$	312,523
Adjustments to reconcile total segment gross operating margin to operating income:
Depreciation, amortization and accretion in operating costs and expenses		(119,492	)		(104,816	)
Operating lease expense paid by EPCO		(526	)		(528	)
Gain on sale of assets in operating costs and expenses		73			61
General and administrative costs		(16,630	)		(13,740	)
Consolidated operating income		187,924			193,500
Other expense, net		(61,430	)		(56,108	)
Income before provision for income taxes, minority interest and cumulative effect of change in accounting principle	$	126,494		$	137,392

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

	Reportable Segments
			Onshore
	NGL		Natural Gas		Offshore					Adjustments
	Pipelines		Pipelines		Pipelines		Petrochemical			and			Consolidated
	& Services		& Services		& Services		Services			Eliminations			Totals
Revenues from third parties:
Three months ended March 31, 2007	$	2,365,118	$	416,230	$	32,983	$	444,281		$	—		$	3,258,612
Three months ended March 31, 2006		2,338,696		413,001		22,352		385,950			—			3,159,999
Revenues from related parties:
Three months ended March 31, 2007		9,903		54,002		328		9			—			64,242
Three months ended March 31, 2006		6,948		82,955		172		—			—			90,075
Intersegment and intrasegment revenues:
Three months ended March 31, 2007		1,122,847		18,569		548		104,997			(1,246,961	)		—
Three months ended March 31, 2006		896,245		28,141		313		82,817			(1,007,516	)		—
Total revenues:
Three months ended March 31, 2007		3,497,868		488,801		33,859		549,287			(1,246,961	)		3,322,854
Three months ended March 31, 2006		3,241,889		524,097		22,837		468,767			(1,007,516	)		3,250,074
Equity in income (loss) of unconsolidated affiliates:
Three months ended March 31, 2007		591		1,029		4,075		484			—			6,179
Three months ended March 31, 2006		1,518		602		1,934		(25	)		—			4,029
Gross operating margin by individual business segment and in total:
Three months ended March 31, 2007		190,694		76,515		19,707		37,583			—			324,499
Three months ended March 31, 2006		170,950		96,803		17,252		27,518			—			312,523
Segment assets:
At March 31, 2007		3,479,690		3,700,783		1,112,518		550,643			1,367,264			10,210,898
At December 31, 2006		3,249,486		3,611,974		734,659		502,345			1,734,083			9,832,547
Investments in and advances to unconsolidated affiliates (see Note 7):
At March 31, 2007		119,860		161,449		299,050		18,279			—			598,638
At December 31, 2006		111,229		124,591		310,136		18,603			—			564,559
Intangible Assets (see Note 8):
At March 31, 2007		408,706		377,994		147,294		46,982			—			980,976
At December 31, 2006		417,950		386,149		152,376		47,480			—			1,003,955
Goodwill (see Note 8):
At March 31, 2007		152,693		282,121		82,135		73,690			—			590,639
At December 31, 2006		152,595		282,121		82,135		73,690			—			590,541

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          The following table summarizes the contribution to consolidated revenues from the sale of NGL, natural gas and petrochemical products for the periods indicated:

	For the Three Months
	Ended March 31,
	2007			2006
NGL Pipelines & Services:
Sale of NGL products	$	2,191,624		$	2,192,016
Percent of consolidated revenues		66	%		67	%
Onshore Natural Gas Pipelines & Services:
Sale of natural gas	$	361,031		$	367,544
Percent of consolidated revenues		11	%		11	%
Petrochemical Services:
Sale of petrochemical products	$	387,752		$	343,350
Percent of consolidated revenues		12	%		11	%

Note 12. Related Party Transactions

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

	For the Three Months
	Ended March 31,
	2007		2006
Revenues from consolidated operations:
EPCO and affiliates	$	8,542	$	5,632
Unconsolidated affiliates		55,700		84,443
Total	$	64,242	$	90,075
Operating costs and expenses:
EPCO and affiliates	$	78,673	$	94,957
Unconsolidated affiliates		5,273		6,686
Total	$	83,946	$	101,643
General and administrative costs:
EPCO and affiliates	$	13,055	$	11,008

Relationship with EPCO and affiliates

          We have an extensive and ongoing relationship with EPCO and its affiliates, which include the following significant entities that are not part of our consolidated group of companies:

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

          We also have an ongoing relationship with Duncan Energy Partners, the financial statements of which are consolidated with those of our own. Our transactions with Duncan Energy Partners are eliminated in consolidation; therefore, they are not part of the totals presented in the preceding table. A description of our relationship with Duncan Energy Partners is presented within this Note 12.

          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, 2007, EPCO and its affiliates beneficially owned 147,129,416 (or 34.0%) of our outstanding common units, which includes 13,454,498 of our

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.

          Jonah Joint Venture with TEPPCO.In August 2006, we formed a joint venture with TEPPCO to be partners in TEPPCO’s Jonah Gas Gathering Company, or Jonah. Jonah owns the Jonah Gas Gathering

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System (“the Jonah Gathering System”), located in the Greater Green River Basin of southwestern Wyoming. The Jonah Gathering System gathers and transports natural gas produced from the Jonah and Pinedale fields to regional natural gas processing plants and major interstate pipelines that deliver natural gas to end-user markets.

          Prior to entering into the Jonah joint venture, we managed the construction of the Phase V expansion and funded the initial construction costs under a letter of intent we signed in February 2006. In connection with the joint venture arrangement, we and TEPPCO will continue the Phase V expansion, which is expected to increase the capacity of the Jonah Gathering System from 1.5 Bcf/d to 2.3 Bcf/d. The Phase V expansion is also expected to significantly reduce system operating pressures, which we anticipate will lead to increased production rates and ultimate reserve recoveries. The first portion of the expansion, which is expected to increase the system gathering capacity to 2.0 Bcf/d, is projected to be completed in the third quarter. The second portion of the expansion is expected to be completed by the end of 2007. We will operate the Jonah Gathering System.

          We manage the Phase V construction project. TEPPCO is entitled to all distributions from the joint venture until specified milestones are achieved, at which point, we will be entitled to receive 50% of the incremental cash flow from portions of the system placed in service as part of the expansion. After subsequent milestones are achieved, we and TEPPCO will share distributions based on a formula that takes into account the respective capital contributions of the parties, including expenditures by TEPPCO prior to the expansion.

          Since August 1, 2006, we and TEPPCO equally share in the construction costs of the Phase V expansion. TEPPCO has reimbursed us $139.3 million for its share of the Phase V costs. At March 31, 2007, we had a receivable from TEPPCO of $14.9 million for additional Phase V costs incurred through March 31, 2007.

          Upon completion of the expansion project and based on the formula in the joint venture partnership agreement, we expect to own an interest in Jonah of approximately 20%, with TEPPCO owning the remaining 80%. At March 31, 2007, we and TEPPCO owned an approximate 17.3% interest and 82.7% interest, respectively, in Jonah. For the three months ended March 31, 2007, our earnings sharing ratio in Jonah was 4.8% compared to TEPPCO’s 95.2%.

          The joint venture is governed by a management committee comprised of two representatives approved by us and two representatives appointed by TEPPCO, each with equal voting power. After an in-depth consideration of all relevant factors, this transaction was approved by the Audit, Conflicts and Governance Committee of our general partner and that of TEPPCO GP.

     EPCO 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 (the “ASA”). We and our general partner, Enterprise GP Holdings and its general partner, Duncan Energy Partners and its general partner, and TEPPCO and its general partner, among other affiliates, are parties to the ASA.

          Under the ASA, we reimburse EPCO for all costs and expenses it incurs in providing management, administrative and operating services to us. The ASA also addresses potential conflicts that may arise among us, Enterprise GP Holdings, Duncan Energy Partners and other affiliates of EPCO.

     Relationship with Duncan Energy Partners

          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. All intercompany transactions between us and Duncan Energy Partners are eliminated in the preparation of our consolidated financial statements. Also, due to common control of the entities by Dan L. Duncan, the initial consolidated

27

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.

          On February 5, 2007, Duncan Energy Partners completed its initial public offering of 14,950,000 common units (including an overallotment amount of 1,950,000 common units) at $21.00 per unit, which generated net proceeds to Duncan Energy Partners of $291.9 million. As consideration for assets contributed and reimbursement for capital expenditures related to these assets, Duncan Energy Partners distributed $260.6 million of these net proceeds to us along with $198.9 million in borrowings under its credit facility and a final amount of 5,351,571 common units of Duncan Energy Partners. Duncan Energy Partners used $38.5 million of net proceeds from the overallotment to redeem 1,950,000 of the 7,301,571 common units it had originally issued to Enterprise Products Partners, resulting in the final amount of 5,351,571 common units beneficially owned by Enterprise Products Partners. We used the cash received from Duncan Energy Partners to temporarily reduce amounts outstanding under our Operating Partnership’s Multi-Year Revolving Credit Facility.

          We contributed 66% of our equity interests in the following subsidiaries to Duncan Energy Partners:

§	Mont Belvieu Caverns, LLC (“Mont Belvieu Caverns”), a recently formed subsidiary, which owns salt dome storage caverns located in Mont Belvieu, Texas that receive, store and deliver NGLs and certain petrochemical products for industrial customers located along the upper Texas Gulf Coast, which has the largest concentration of petrochemical plants and refineries in the United States;
§	Acadian Gas, LLC (“Acadian Gas”), which owns an onshore natural gas pipeline system that gathers, transports, stores and markets natural gas in Louisiana. The Acadian Gas system links natural gas supplies from onshore and offshore Gulf of Mexico developments (including offshore pipelines, continental shelf and deepwater production) with local gas distribution companies, electric generation plants and industrial customers, including those in the Baton Rouge-New Orleans-Mississippi River corridor. A subsidiary of Acadian Gas owns our 49.5% equity interest in Evangeline;
§	Sabine Propylene Pipeline L.P. (“Sabine Propylene”), which transports polymer-grade propylene between Port Arthur, Texas and a pipeline interconnect located in Cameron Parish, Louisiana;
§	Enterprise Lou-Tex Propylene Pipeline L.P. (“Lou-Tex Propylene”), which transports chemical-grade propylene from Sorrento, Louisiana to Mont Belvieu, Texas; and
§	South Texas NGL Pipelines, LLC (“South Texas NGL”), a recently formed subsidiary, which began transporting NGLs from Corpus Christi, Texas to Mont Belvieu, Texas in January 2007. South Texas NGL owns the DEP South Texas NGL Pipeline System.

          In addition to the 34% direct ownership interest we retained in such entities, we also own the 2% general partner interest in Duncan Energy Partners and 26.4% of Duncan Energy Partners’ outstanding common units. Our Operating Partnership directs the business operations of Duncan Energy Partners through its ownership and control of the general partner of Duncan Energy Partners.

          We have significant involvement with all of the subsidiaries of Duncan Energy Partners, including the following types of transactions:

§ We utilize storage services provided by Mont Belvieu Caverns to support our Mont Belvieu fractionation and other businesses;

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§	We buy natural gas from and sell natural gas to Acadian Gas in connection with its normal business activities; and
§	We are currently the sole shipper on the DEP South Texas NGL Pipeline System.

          We may contribute other equity interests in our subsidiaries to Duncan Energy Partners and use the proceeds we receive from Duncan Energy Partners to fund our capital spending program. We have no obligation or commitment to make such contributions to Duncan Energy Partners.

Relationships with Unconsolidated Affiliates

          Our significant related party revenue and expense 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.

          See “Relationship with TEPPCO” within this Note 12 for a description of ongoing transactions involving our Jonah joint venture with TEPPCO.

          For additional information regarding our unconsolidated affiliates, see Note 7.

Note 13. 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 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 performance-based phantom units outstanding during a period; and (iii) the number of incremental common units resulting from the assumed exercise of dilutive unit options outstanding during a period (the “incremental option units”).

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

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          The amount of net income or loss allocated to limited partner interests is net of our general partner’s share of such earnings. The following table presents the allocation of net income to Enterprise Products GP for the periods indicated:

	For the Three Months
	Ended March 31,
	2007			2006
Net income	$	112,045		$	133,777
Less incentive earnings allocations to Enterprise Products GP		(25,260	)		(19,115	)
Net income available after incentive earnings allocation		86,785			114,662
Multiplied by Enterprise Products GP ownership interest		2.0	%		2.0	%
Standard earnings allocation to Enterprise Products GP	$	1,736		$	2,293
Incentive earnings allocation to Enterprise Products GP	$	25,260		$	19,115
Standard earnings allocation to Enterprise Products GP		1,736			2,293
Enterprise Products GP interest in net income	$	26,996		$	21,408

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

	For the Three Months
	Ended March 31,
	2007			2006
Income before change in accounting principle and Enterprise Products GP interest	$	112,045		$	132,302
Cumulative effect of change in accounting principle		—			1,475
Net income		112,045			133,777
Enterprise Products GP interest in net income		(26,996	)		(21,408	)
Net income available to limited partners	$	85,049		$	112,369
BASIC EARNINGS PER UNIT
Numerator
Income before change in accounting principle and Enterprise Products GP interest	$	112,045		$	132,302
Cumulative effect of change in accounting principle		—			1,475
Enterprise Products GP interest in net income		(26,996	)		(21,408	)
Limited partners’ interest in net income	$	85,049		$	112,369
Denominator
Common units		431,633			395,293
Time-vested restricted units		1,110			755
Total		432,743			396,048
Basic earnings per unit
Income before change in accounting principle and Enterprise Products GP interest	$	0.26		$	0.33
Cumulative effect of change in accounting principle		—			—
Enterprise Products GP interest in net income		(0.06	)		(0.05	)
Limited partners’ interest in net income	$	0.20		$	0.28
DILUTED EARNINGS PER UNIT
Numerator
Income before change in accounting principle and Enterprise Products GP interest	$	112,045		$	132,302
Cumulative effect of change in accounting principle		—			1,475
Enterprise Products GP interest in net income		(26,996	)		(21,408	)
Limited partners’ interest in net income	$	85,049		$	112,369
Denominator
Common units		431,633			395,293
Time-vested restricted units		1,110			755
Performance-based restricted units		9			27
Incremental option units		520			248
Total		433,272			396,323
Diluted earnings per unit
Income before change in accounting principle and Enterprise Products GP interest	$	0.26		$	0.33
Cumulative effect of change in accounting principle		—			—
Enterprise Products GP interest in net income		(0.06	)		(0.05	)
Limited partners’ interest in net income	$	0.20		$	0.28

Note 14. Commitments and Contingencies

     Litigation

          On occasion, we are named as a defendant in litigation relating to our normal business activities, including regulatory and environmental matters. Although we are insured against various business risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings as a

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result of our ordinary business activities. We are unaware of any significant litigation, pending or threatened, that could have a significant adverse effect on our financial position, cash flows or results of operations.

     On September 18, 2006, Peter Brinckerhoff, a purported unitholder of TEPPCO, filed a complaint in the Court of Chancery of New Castle County in the State of Delaware, in his individual capacity, as a putative class action on behalf of other unitholders of TEPPCO, and derivatively on behalf of TEPPCO, concerning, among other things, certain transactions involving TEPPCO and us or our affiliates. The complaint names as defendants (i) TEPPCO, its current and certain former directors, and certain of its affiliates; (ii) us and certain of our affiliates, including the parent company of our general partner; (iii) EPCO, Inc.; and (iv) Dan L. Duncan.

     The complaint alleges, among other things, that the defendants have caused TEPPCO to enter into certain transactions with us or our affiliates that are unfair to TEPPCO or otherwise unfairly favored us or our affiliates over TEPPCO. These transactions are alleged to include the joint venture to further expand the Jonah Gathering System entered into by TEPPCO and one of our affiliates in August 2006 and the sale by TEPPCO to one of our affiliates of the Pioneer gas processing plant in March 2006. The complaint seeks (i) rescission of these transactions or an award of rescissory damages with respect thereto; (ii) damages for profits and special benefits allegedly obtained by defendants as a result of the alleged wrongdoings in the complaint; and (iii) awarding plaintiff costs of the action, including fees and expenses of his attorneys and experts. We believe this lawsuit is without merit and intend to vigorously defend against it. See Note 12 for additional information regarding our relationship with TEPPCO.

     On February 13, 2007, our Operating Partnership received notice from the U.S. Department of Justice (“DOJ”) that it was the subject of a criminal investigation related to an ammonia release in Kingman County, Kansas on October 27, 2004 from a pressurized anhydrous ammonia pipeline owned by a third party, Magellan Ammonia Pipeline, L.P. (“Magellan”). Our Operating Partnership is the operator of this pipeline. On February 14, 2007, our Operating Partnership received a letter from the Environment and Natural Resources Division (“ENRD”) of the DOJ regarding this incident and a previous release of ammonia on September 27, 2004 from the same pipeline. The ENRD has indicated that it may pursue civil damages against our Operating Partnership and Magellan as a result of these incidents. Based on this correspondence from the ENRD, the statutory maximum amount of civil fines that could be assessed against our Operating Partnership and Magellan is up to $17.4 million in the aggregate. Our Operating Partnership is cooperating with the DOJ and is pursuing a resolution acceptable to all parties. Our Operating Partnership is seeking defense and indemnity under the pipeline operating agreement between it and Magellan. At this time, we do not believe that a final resolution of either the criminal investigation by the DOJ or the civil claims by the ENRD will have a material impact on our consolidated financial position, results of operations or cash flows.

     On October 25, 2006, a rupture in the Magellan Ammonia Pipeline resulted in the release of ammonia near Clay Center, Kansas. The pipeline has been repaired and environmental remediation tasks related to this incident have been completed. At this time, we do not believe that this incident will have a material impact on our consolidated financial position, results of operations or cash flows.

     Several lawsuits have been filed by municipalities and other water suppliers against a number of manufacturers of reformulated gasoline containing methyl tertiary butyl ether. In general, such suits have not named manufacturers of this product as defendants, and there have been no such lawsuits filed against our subsidiary that owns an octane-additive production facility. It is possible, however, that former manufacturers such as our subsidiary could ultimately be added as defendants in such lawsuits or in new lawsuits.

Operating Leases

     We lease certain property, plant and equipment under noncancelable and cancelable operating leases. Our significant lease agreements involve (i) the lease of underground caverns for the storage of natural gas and NGLs, (ii) leased office space with an affiliate of EPCO, and (iii) land held pursuant to

32

right-of-way agreements. In general, our material lease agreements have original terms that range from 14 to 20 years and include renewal options that could extend the agreements for up to an additional 20 years. Lease expense is charged to operating costs and expenses on a straight line basis over the period of expected economic benefit. Contingent rental payments are expensed as incurred.

     Lease and rental expense included in operating costs and expenses was $8.1 million and $9.7 million during the three months ended March 31, 2007 and 2006, respectively. There have been no material changes in our operating lease commitments since December 31, 2006.

Contractual Obligations

     With the exception of the debt incurred by Duncan Energy Partners in connection with its initial public offering, there have been no significant changes in our consolidated schedule of maturities of long-term debt since those reported in our annual report on Form 10-K for the year ended December 31, 2006. See Note 9 for additional information regarding the debt obligations of Duncan Energy Partners.

Performance Guaranty

     In December 2004, a subsidiary of ours entered into the Independence Hub Agreement (the “Agreement”) with six oil and natural gas producers. The Agreement, as amended, obligates our subsidiary to construct the Independence Hub offshore platform and to process 1 Bcf/d of natural gas and condensate for the producers.

     We guaranteed to the producers the construction-related performance of our subsidiary up to an amount of $340.8 million. This figure represents the maximum amount we would have to pay the producers in the remote circumstance where they must finish construction of the platform because our subsidiary failed to do so. This guarantee will remain in place until the earlier of (i) the date all guaranteed obligations terminate or expire, or have been paid or otherwise performed or discharged in full, (ii) upon mutual written consent of us, the producers and our joint venture partner in the platform project or (iii) mechanical completion of the platform. Mechanical completion of the Independence Hub platform is expected to occur in May 2007.

     In accordance with FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” we recorded the fair value of the performance guaranty using an expected present value approach. Given the remote probability that we would have been required to perform under the guaranty, we had estimated the fair value of the performance guaranty at approximately $1.2 million, which is a component of other current liabilities on our Consolidated Balance Sheets at March 31, 2007 and December 31, 2006.

Other Claims

     As part of our normal business activities with joint venture partners and certain customers and suppliers, we occasionally make claims against such parties or have claims made against us as a result of disputes related to contractual agreements or similar arrangements. As of March 31, 2007, our contingent claims against such parties were approximately $2 million and claims against us were approximately $34 million. These matters are in various stages of assessment and the ultimate outcome of such disputes cannot be reasonably estimated. However, in our opinion, the likelihood of a material adverse outcome related to disputes against us is remote. Accordingly, accruals for loss contingencies related to these matters, if any, that might result from the resolution of such disputes have not been reflected in our consolidated financial statements.

Note 15. Significant Risks and Uncertainties – Weather-Related Risks

     The following is a discussion of the general status of our insurance claims related to recent significant storm events. To the extent we include any estimate or range of estimates regarding the dollar

33

value of damages, please be aware that a change in our estimates may occur as additional information becomes available.

     Hurricane Ivan insurance claims.We have submitted business interruption insurance claims for our estimated losses caused by Hurricane Ivan. During the three months ended March 31, 2007 and 2006, we received $0.4 million and $10.2 million, respectively, of nonrefundable cash proceeds from such claims. We are continuing our efforts to collect residual balances and expect to complete the process during 2007. To the extent we receive nonrefundable cash proceeds from business interruption insurance claims, they are recorded as a gain in our Unaudited Condensed Statements of Consolidated Operations in the period of receipt.

     We received $1.1 million and $24.1 million during the three months ended March 31, 2007 and March 31, 2006, respectively, related to property damage claims arising from Hurricane Ivan.

     Hurricanes Katrina and Rita insurance claims.Hurricanes Katrina and Rita, both significant storms, affected certain of our Gulf Coast assets in August and September of 2005, respectively. With respect to these storms, we have $77.7 million of estimated property damage claims outstanding at March 31, 2007, that we believe are probable of collection during the periods 2007 through 2009. We are pursuing collection of our property damage and business interruption claims related to Hurricanes Katrina and Rita.

Note 16. Supplemental Cash Flow Information

     Our Unaudited Condensed Statements of Consolidated Cash Flows are prepared using the indirect method. The indirect method derives net cash flows from operating activities by adjusting net income to remove (i) the effects of all deferrals of past operating cash receipts and payments, such as changes during the period in inventory, deferred income and similar transactions, (ii) the effects of all accruals of expected future operating cash receipts and cash payments, such as changes during the period in receivables and payables, (iii) the effects of all items classified as investing or financing cash flows, such as gains or losses on sale of property, plant and equipment or extinguishment of debt, and (iv) other non-cash amounts such as depreciation, amortization and changes in the fair market value of financial instruments.

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

	For the Three Months
	Ended March 31,
	2007			2006
Decrease (increase) in:
Accounts and notes receivable	$	8,641		$	355,049
Inventories		(35,298	)		84,191
Prepaid and other current assets		5,969			12,482
Other assets		2,314			7,866
Increase (decrease) in:
Accounts payable		(57,289	)		(85,314	)
Accrued gas payable		163,514			(174,960	)
Accrued expenses		119,918			44,029
Accrued interest		(10,814	)		40
Other current liabilities		(26,701	)		2,615
Other long-term liabilities		(1,351	)		1,086
Net effect of changes in operating accounts	$	168,903		$	247,084

     Third parties may be obligated to reimburse us for all or a portion of expenditures on certain of our capital projects. The majority of such arrangements are associated with projects related to pipeline construction and production well tie-ins. We received $39.1 million and $12.2 million as contributions in aid of our construction costs during the three months ended March 31, 2007 and 2006, respectively.

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Note 17. Condensed Financial Information of Operating Partnership

     The Operating Partnership conducts substantially all of our business. Currently, we have no independent operations and no material assets outside those of our Operating Partnership. The Operating Partnership consolidates the financial statements of Duncan Energy Partners with those of its own.

     We guarantee the consolidated debt obligations of our Operating Partnership, with the exception of the Dixie revolving credit facility, Duncan Energy Partners’ credit facility and the senior subordinated notes 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. See Note 9 for additional information regarding our consolidated debt obligations.

     The reconciling items between our consolidated financial statements and those of our Operating Partnership are insignificant. The following table presents condensed consolidated balance sheet data for the Operating Partnership at the dates indicated:

	March 31,		December 31,
	2007		2006
ASSETS
Current assets	$	1,968,896	$	1,915,937
Property, plant and equipment, net		10,210,898		9,832,547
Investments in and advances to unconsolidated affiliates, net		598,638		564,559
Intangible assets, net		980,976		1,003,955
Goodwill		590,639		590,541
Deferred tax asset		2,301		1,632
Other assets		71,208		74,103
Total	$	14,423,556	$	13,983,274
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	$	2,052,754	$	1,986,444
Long-term debt		5,448,685		5,295,590
Other long-term liabilities		102,228		99,845
Minority interest		438,683		136,249
Partners’ equity		6,381,206		6,465,146
Total	$	14,423,556	$	13,983,274
Total Operating Partnership debt obligations guaranteed by us	$	5,294,000	$	5,314,000

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

	For the Three Months
	Ended March 31,
	2007			2006
Revenues	$	3,322,854		$	3,250,074
Costs and expenses		3,139,730			3,058,646
Equity in income of unconsolidated affiliates		6,179			4,029
Operating income		189,303			195,457
Other expense		(61,964	)		(56,512	)
Income before provision for income taxes, minority interest and change in accounting principle		127,339			138,945
Provision for income taxes		(8,779	)		(2,892	)
Income before minority interest and change in accounting principle		118,560			136,053
Minority interest		(5,743	)		(2,199	)
Income before change in accounting principle		112,817			133,854
Cumulative effect of change in accounting principle		—			1,475
Net income	$	112,817		$	135,329

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

For the three months ended March 31, 2007 and 2006.

     The following information should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and our accompanying notes included under Item 1 of this quarterly report on Form 10-Q and with the information contained within our annual report on Form 10-K for the year ended December 31, 2006. Our discussion and analysis includes the following:

§	Overview of Business.
§	Results of Operations – Discusses material quarter-to-quarter variances in our Unaudited Condensed Statements of Consolidated Operations.
§	Liquidity and Capital Resources – Addresses available sources of liquidity and analyzes cash flows.
§	Critical Accounting Policies – Presents accounting policies that are among the most significant to the portrayal of our financial condition and results of operations.
§	Other Items – Includes information related to contractual obligations, off-balance sheet arrangements, related party transactions, recent accounting pronouncements and similar disclosures.

     This discussion contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us. When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “intend,” “could,” “believe,” “may” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our general partner believe that such expectations reflected in such forward-looking statements are reasonable, neither we nor our general partner can give any assurances that such expectations will prove to be correct. Such statements are subject to a variety of risks, uncertainties and assumptions as described in more detail in Item 1A, “Risk Factors,” included in our annual report onForm 10-K for 2006. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. You should not put undue reliance on any forward-looking statements.

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

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

     Our financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”).

     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, including Duncan Energy Partners L.P. (“Duncan Energy Partners”).

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     In addition, references to “TEPPCO” mean TEPPCO Partners, L.P., a publicly traded Delaware limited partnership, which is an affiliate of us. References to “TEPPCO GP” refer to Texas Eastern Products Pipeline Company LLC, which is the general partner of TEPPCO and wholly owned by a private company subsidiary of EPCO, Inc. (“EPCO”).

Overview of Business

     We are a North American midstream energy company providing a wide range of services to producers and consumers of natural gas, natural gas liquids (“NGLs”), crude oil, and certain petrochemicals. In addition, we are an industry leader in the development of pipeline and other midstream energy infrastructure in the continental United States and Gulf of Mexico. We are a publicly traded Delaware limited partnership formed in 1998, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.”

     Our midstream energy asset network links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the United States, Canada and the Gulf of Mexico with domestic consumers and international markets. 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 conduct substantially all of our business through 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 listed on the NYSE under the ticker symbol “EPE.” We, Enterprise Products GP and Enterprise GP Holdings are affiliates and under common control of Dan L. Duncan, the Chairman and the controlling shareholder of EPCO.

Recent Developments

     The following information highlights our significant developments since January 1, 2007 through the date of this filing.

§	In March 2007, we announced the successful installation of our Independence Hub platform at its deepwater site in the Mississippi Canyon of the eastern Gulf of Mexico. As a result of this event, the Independence Hub platform has started earning demand revenues.
§	In March 2007, we announced the formation of a natural gas services and marketing businesses similar to our existing NGL and petrochemical marketing businesses. This new group will be the focal point for all of our existing natural gas supply and marketing activities, which currently include producer wellhead services, facility fuel procurement, pipeline and storage capacity optimization, and a full range of market customer delivery arrangements. This initiative is expected to broaden our role in the natural gas markets by linking our extensive U.S. natural gas pipeline and storage assets, thus providing customers with value-added solutions and reducing our operating costs through enhanced fuel procurement practices.
§	In February 2007, Duncan Energy Partners, a consolidated subsidiary of ours, completed an underwritten initial public offering of 14,950,000 of its common units. We formed Duncan Energy Partners as a Delaware limited partnership to acquire ownership interests in certain of our midstream energy businesses. For additional information regarding Duncan Energy Partners, see “Other Items – Initial Public Offering of Duncan Energy Partners” included within this Item 2.

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Capital Spending

     We are committed to the long-term growth and viability of Enterprise Products Partners. Part of our business strategy involves expansion through business combinations, growth capital projects and investments in joint ventures. We believe we are positioned to continue to grow our system of assets through the construction of new facilities and to capitalize on expected future production increases from such areas as the Piceance Basin of western Colorado, the Greater Green River Basin in Wyoming, the Barnett Shale in North Texas, and the deepwater Gulf of Mexico.

     Management continues to analyze potential acquisitions, joint ventures and similar transactions with businesses that operate in complementary markets or geographic regions. In recent years, major oil and gas companies have sold non-strategic assets in the midstream energy sector in which we operate. We expect this trend to continue, and expect independent oil and natural gas companies to consider similar divestitures.

     Based on information currently available, we estimate our consolidated capital spending for the remainder of 2007 (i.e., the second, third and fourth quarters) will approximate $1.4 billion, which includes estimated expenditures of $1.3 billion for growth capital projects and acquisitions and $0.1 billion for sustaining capital expenditures. For information regarding selected major growth capital projects, please see “Capital Spending” under Item 7 of the annual report on Form 10-K for the year ended December 31, 2006.

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

     Our success in raising capital, including the formation of joint ventures to share costs and risks, continues to be a principal factor that determines how much we can spend. We believe our access to capital resources is sufficient to meet the demands of our current and future operating growth needs, and although we currently intend to make the forecasted expenditures discussed above, we may adjust the timing and amounts of projected expenditures in response to changes in capital markets.

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

	For the Three Months Ended
	March 31,
	2007			2006
Capital spending for business combinations:
Additional ownership interests in Dixie Pipeline Company (“Dixie”) and other	$	312		$	—
Total		312			—
Capital spending for property, plant and equipment:
Growth capital projects, net		567,406			279,994
Sustaining capital projects		7,484			24,624
Total		574,890			304,618
Capital spending attributable to unconsolidated affiliates:
Investments in and advances to unconsolidated affiliates		(44,487	)		(53,148	)
Total		(44,487	)		(53,148	)
Total capital spending	$	530,715		$	251,470

     Our capital spending for growth capital projects (as presented in the preceding table) are net of amounts we received from third parties as contributions in aid of our construction costs. Such contributions were $39.1 million and $12.2 million for the three months ended March 31, 2007 and 2006, respectively.

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On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with projects related to pipeline construction and production well tie-ins.

     At March 31, 2007, we had $454.9 million in outstanding purchase commitments. These commitments primarily relate to growth capital projects in the Rocky Mountains that are expected to be placed in service in 2007 and the Shenzi Oil Export Pipeline Project, which is expected to be completed in 2009.

     We own a 50.0% interest in Cameron Highway Oil Pipeline Company (“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 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 Series A notes and $16.3 million of related make-whole premiums and accrued interest.

     In March 2007, we announced the successful installation of our Independence Hub platform at its deepwater site in the Mississippi Canyon of the eastern Gulf of Mexico. As a result of this event, the Independence Hub platform has started earning demand revenues. With the installation now complete, control of the Independence Hub will be transferred to Anadarko Petroleum Corporation as platform operator. Production from the fields served by the Independence Hub platform is expected to begin in the second half of 2007.

Pipeline Integrity Costs

     Our NGL, petrochemical and natural gas pipelines are subject to pipeline safety programs administered by the U.S. Department of Transportation, through its Office of Pipeline Safety. During the three months ended March 31, 2007 and 2006, we spent approximately $18.7 million and $18.6 million, respectively, to comply with these programs, of which $8.3 million and $5.9 million, respectively, was recorded as an operating expense and the remaining $10.4 million and $12.7 million, respectively, was capitalized.

     We expect our net cash outlay for pipeline integrity program expenditures to approximate $29.6 million for the remainder of 2007. Our forecast is net of certain costs we expect to recover from El Paso in connection with an indemnification agreement. During the remainder of 2007, we expect to recover $31.1 million from El Paso related to our 2006 expenditures, which leaves a remainder of $5.4 million reimbursable by El Paso for 2007 pipeline integrity costs.

Results of Operations

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

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management uses in evaluating segment results. The GAAP financial 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 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. Intercompany accounts and transactions are eliminated in consolidation.

     We include earnings from equity method 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 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. As circumstances dictate, we may increase our ownership interest in equity investments, which could result in their subsequent consolidation into our operations.

     Our consolidated gross operating margin amounts include the gross operating margin amounts of Duncan Energy Partners on a 100% basis. Volumetric data associated with the operations of Duncan Energy Partners are also included on a 100% basis in our consolidated statistical data.

     For additional information regarding our business segments, see Note 11 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

Selected Price and Volumetric Data

     The following table illustrates selected quarterly industry index prices for natural gas, crude oil and selected NGL and petrochemical products for the periods presented.

															Polymer		Refinery
	Natural								Normal				Natural		Grade		Grade
	Gas,		Crude Oil,		Ethane,		Propane,		Butane,		Isobutane,		Gasoline,		Propylene,		Propylene,
	$/MMBtu		$/barrel		$/gallon		$/gallon		$/gallon		$/gallon		$/gallon		$/pound		$/pound
	(1)		(2)		(1)		(1)		(1)		(1)		(1)		(1)		(1)
2006
1st Quarter	$	9.01	$	63.35	$	0.57	$	0.94	$	1.20	$	1.27	$	1.38	$	0.45	$	0.40
2nd Quarter	$	6.80	$	70.53	$	0.68	$	1.05	$	1.22	$	1.26	$	1.52	$	0.50	$	0.44
3rd Quarter	$	6.58	$	70.44	$	0.76	$	1.10	$	1.28	$	1.30	$	1.53	$	0.51	$	0.46
4th Quarter	$	6.56	$	60.03	$	0.62	$	0.95	$	1.11	$	1.12	$	1.31	$	0.44	$	0.35
2006 Averages	$	7.24	$	66.09	$	0.66	$	1.01	$	1.20	$	1.24	$	1.44	$	0.47	$	0.41
2007
1st Quarter	$	6.77	$	58.02	$	0.59	$	0.97	$	1.13	$	1.22	$	1.37	$	0.45	$	0.40

(1)

Natural gas, NGL, polymer grade propylene and refinery grade propylene prices represent an average of various commercial index prices including Oil Price Information Service (“OPIS”) and Chemical Market Associates, Inc. (“CMAI”). Natural gas price is representative of Henry-Hub I-FERC. NGL prices are representative of Mont Belvieu Non-TET pricing. Refinery grade propylene represents an average of CMAI spot prices. Polymer-grade propylene represents average CMAI contract pricing.

(2)

Crude oil price is representative of an index price for West Texas Intermediate.

40

     The following table presents our significant average throughput, production and processing volumetric data. These statistics are reported on a net basis, taking into account our ownership interests in certain joint ventures, and reflect the periods in which we owned an interest in such operations.

	For the Three Months
	Ended March 31,
	2007		2006
NGL Pipelines & Services, net:
NGL transportation volumes (MBPD)		1,607		1,443
NGL fractionation volumes (MBPD)		351		255
Equity NGL production (MBPD)		70		58
Fee-based natural gas processing (MMcf/d)		2,401		1,807
Onshore Natural Gas Pipelines & Services, net:
Natural gas transportation volumes (BBtus/d)		6,086		6,052
Offshore Pipelines & Services, net:
Natural gas transportation volumes (BBtus/d)		1,384		1,476
Crude oil transportation volumes (MBPD)		153		113
Platform gas processing (Mcf/d)		162		157
Platform oil processing (MBPD)		20		7
Petrochemical Services, net:
Butane isomerization volumes (MBPD)		95		84
Propylene fractionation volumes (MBPD)		61		52
Octane additive production volumes (MBPD)		7		4
Petrochemical transportation volumes (MBPD)		102		87
Total, net:
NGL, crude oil and petrochemical transportation volumes (MBPD)		1,862		1,643
Natural gas transportation volumes (BBtus/d)		7,470		7,528
Equivalent transportation volumes (MBPD)(1)		3,828		3,624

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

Comparison of Results of Operations

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

	For the Three Months
	Ended March 31,
	2007		2006
Revenues	$	3,322,854	$	3,250,074
Operating costs and expenses		3,124,479		3,046,863
General and administrative costs		16,630		13,740
Equity in income of unconsolidated affiliates		6,179		4,029
Operating income		187,924		193,500
Interest expense		63,358		58,077
Net income		112,045		133,777

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

	For the Three Months
	Ended March 31,
	2007		2006
Gross operating margin by segment:
NGL Pipelines & Services	$	190,694	$	170,950
Onshore Natural Gas Pipelines & Services		76,515		96,803
Offshore Pipelines & Services		19,707		17,252
Petrochemical Services		37,583		27,518
Total segment gross operating margin	$	324,499	$	312,523

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     For a reconciliation of non-GAAP gross operating margin to GAAP operating income and further to GAAP income before provision for income taxes, minority interest and the cumulative effect of change in accounting principle, see “Other Items — Non-GAAP reconciliations” included within this Item 2.

     The following table summarizes the contribution to consolidated revenues from the sale of NGL, natural gas and petrochemical products during the periods indicated (dollars in thousands):

	For the Three Months
	Ended March 31,
	2007			2006
NGL Pipelines & Services:
Sale of NGL products	$	2,191,624		$	2,192,016
Percent of consolidated revenues		66	%		67	%
Onshore Natural Gas Pipelines & Services:
Sale of natural gas	$	361,031		$	367,544
Percent of consolidated revenues		11	%		11	%
Petrochemical Services:
Sale of petrochemical products	$	387,752		$	343,350
Percent of consolidated revenues		12	%		11	%

     As noted in the following section, changes in our revenues quarter-to-quarter are explained in part by changes in energy commodity prices.

     Comparison of Three Months Ended March 31, 2007 with Three Months Ended March 31, 2006

     Consolidated revenues increased $72.8 million quarter-to-quarter to $3.3 billion for the first quarter of 2007. The quarter-to-quarter increase in consolidated revenues is primarily due to (i) the addition of revenues from businesses we acquired or assets we placed in-service after the first quarter of 2006 and (ii) higher petrochemical sales volumes during the first quarter of 2007 relative to the first quarter of 2006. Consolidated revenues increased $29.9 million quarter-to-quarter due to the addition of revenues from acquired businesses and newly constructed assets. Higher petrochemical sales volumes accounted for a $44.4 million increase in consolidated revenues associated with our petrochemical marketing activities.

     Operating costs and expenses were $3.1 billion for the first quarter of 2007 versus $3.0 billion for the first quarter of 2006. The $77.6 million quarter-to-quarter increase in consolidated operating costs and expenses is primarily due to higher cost of sales associated with our petrochemical marketing activities. The cost of sales of our petrochemical products increased $59.0 million quarter-to-quarter primarily due to an increase in volumes sold. The first quarter of 2007 includes $39.6 million of consolidated operating costs and expenses attributable to businesses we acquired or assets we placed in-service after the first quarter of 2006. The increase in costs and expenses quarter-to-quarter was partially off-set by an $18.6 million decrease in the cost of natural gas sales, which was primarily due to lower sales prices during the first quarter of 2007 relative to the first quarter of 2006. General and administrative costs increased $2.9 million quarter-to-quarter.

     Changes in our revenues and costs and expenses quarter-to-quarter are explained in part by changes in energy commodity prices. The weighted-average indicative market price for NGLs was $0.95 per gallon during the first quarter of 2007 versus $0.94 per gallon during the first quarter of 2006. Our determination of the weighted-average indicative market price for NGLs is based on U.S. Gulf Coast prices for such products at Mont Belvieu, Texas, which is the primary industry hub for domestic NGL production. The market price of natural gas (as measured at Henry Hub) averaged $6.77 per MMBtu during the first quarter of 2007 versus $9.01 per MMBtu during the first quarter of 2006. Polymer grade and refinery grade propylene index prices averaged $0.45 per pound and $0.40 per pound, respectively, for the first quarter of 2007 and 2006. For additional historical energy commodity pricing information, see the table on page 40.

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     Equity earnings from our unconsolidated affiliates were $6.2 million for the first quarter of 2007 compared to $4.0 million for the first quarter of 2006. The first quarter of 2007 includes $1.0 million of equity earnings from Jonah. In addition, an increase in volumes from offshore production led to a collective $2.0 million increase quarter-to-quarter in equity earnings from Poseidon and Deepwater Gateway. Equity earnings from Promix, which received additional volumes during the first quarter of 2006 while our Norco NGL fractionator was shut-in, decreased $1.6 million quarter-to-quarter.

     Operating income for the first quarter of 2007 was $187.9 million compared to $193.5 million for the first quarter of 2006. Collectively, the aforementioned changes in revenues, costs and expenses and equity earnings contributed to the $5.6 million decrease in operating income quarter-to-quarter.

     Interest expense increased $5.3 million quarter-to-quarter primarily due to our issuance of junior notes in 2006 and an increase in interest rates charged on our variable rate debt. Our average debt principal outstanding was $5.4 billion in the first quarter of 2007 compared to $4.7 billion in the first quarter of 2006. Provision for income taxes increased $5.9 million primarily due to the Texas Margin Tax. For more information regarding the Texas Margin Tax, see Note 2 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

     As a result of items noted in the previous paragraphs, our consolidated net income decreased $21.8 million quarter-to-quarter to $112.0 million in the first quarter of 2007 compared to $133.8 million in the first quarter of 2006. Net income for the first quarter of 2006 includes a $1.5 million non-cash benefit we recognized for the cumulative effect of change in accounting principle. For additional information regarding this cumulative effect of change in accounting principle, see Note 2 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

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

     NGL Pipelines & Services. Gross operating margin from this business segment was $190.7 million for the first quarter of 2007 compared to $171.0 million for the first quarter of 2006. The first quarter of 2007 includes $1.4 million of proceeds from business interruption insurance claims compared to $8.3 million of proceeds during the first quarter of 2006. Gross operating margin from our NGL pipelines and related storage business was $78.9 million for the first quarter of 2007 compared to $69.0 million for the first quarter of 2006. Total NGL transportation volumes increased to 1,607 MBPD during the first quarter of 2007 from 1,443 MBPD during the first quarter of 2006. The $9.9 million quarter-to-quarter increase in gross operating margin from this business is primarily due to higher NGL transportation volumes during the first quarter of 2007 relative to the same quarter in 2006. Also, segment gross operating margin for the first quarter of 2007 includes $4.9 million from the DEP South Texas NGL Pipeline, which was placed in-service in January 2007.

     Gross operating margin from NGL fractionation was $25.6 million for the first quarter of 2007 compared to $17.0 million for the first quarter of 2006. Fractionation volumes increased from 255 MBPD during the first quarter of 2006 to 351 MBPD during the first quarter of 2007. The $8.6 million quarter-to-quarter increase in gross operating margin is largely due to increased fractionation volumes at our Norco NGL fractionator. This facility suffered a reduction of volumes in the first quarter of 2006 due to the effects of Hurricane Katrina. Also, our Mont Belvieu NGL fractionator benefited from a 15 MBPD expansion project that was completed during the second quarter of 2006.

     Gross operating margin from our natural gas processing and related NGL marketing business was $86.2 million for the first quarter of 2007 compared to $84.9 million for the first quarter of 2006, a quarter-to-quarter increase of $1.3 million. Gross operating margin for the first quarter of 2007 includes $2.9 million from processing contracts we acquired in connection with the Encinal acquisition in July 2006 and $1.2 million from the Pioneer plant, which we acquired from TEPPCO in March 2006. In general, strong regional demand for NGLs led to higher sales margins during the first quarter of 2006 relative to the first quarter of 2007. Fee-based processing volumes increased to 2.4 Bcf/d during the first quarter of 2007 from

43

1.8 Bcf/d during the first quarter of 2006. Likewise, equity NGL production increased to 70 MBPD during the first quarter of 2007 from 58 MBPD during the first quarter of 2006.

     Onshore Natural Gas Pipelines & Services. Gross operating margin from this business segment was $76.5 million for the first quarter of 2007 compared to $96.8 million for the first quarter of 2006. Our onshore natural gas transportation volumes were 6,086 BBtu/d during the first quarter of 2007 compared to 6,052 BBtu/d for the first quarter of 2006. Gross operating margin from our onshore natural gas pipelines decreased $15.7 million quarter-to-quarter primarily due to lower revenues from our San Juan Gathering System, Permian Basin Gathering Systems and Texas Intrastate System. A significant portion of the gathering contracts on the San Juan Gathering System have fees that are based on natural gas index prices, which were higher during the first quarter of 2006 relative to the first quarter of 2007. The decrease in gross operating margin quarter-to-quarter from our Texas Intrastate System is primarily due to lower average transportation fees charged to shippers. Also, gathering volumes on our Permian Basin Gathering Systems were lower in the first quarter of 2007 relative to the first quarter of 2006.

     Gross operating margin for the first quarter of 2007 includes $1.0 million from the Piceance Creek Gathering System, which we acquired in December 2006 and placed in-service in January 2007. The Piceance Creek Gathering System contributed 287 BBtu/d of gathering volumes during the first quarter of 2007. The first quarter of 2007 also includes $1.0 million of equity earnings from Jonah.

     In addition, gross operating margin from our natural gas storage business decreased $4.6 million quarter-to-quarter largely due to mechanical problems associated with three storage caverns located at our Wilson natural gas storage facility in Texas. As a result, these wells were out of service for the first quarter of 2007. We expect that two of the storage caverns at our Wilson facility will return to service in the second quarter of 2007.

     Offshore Pipelines & Services. Gross operating margin from this business segment was $19.7 million for the first quarter of 2007 compared to $17.3 million for the first quarter of 2006. Gross operating margin from our offshore platforms was $13.9 million for the first quarter of 2007 compared to $8.5 million for the first quarter of 2006. The first quarter of 2006 includes $1.9 million of proceeds from business interruption insurance claims. Gross operating margin for the first quarter of 2007 includes $4.0 million from our Independence Hub platform, which began earning demand fee revenues in March 2007. We expect to earn additional fee-based revenues in the second half of 2007 when the Independence Hub platform begins processing natural gas from production fields in the Atwater Valley, DeSoto Canyon, Lloyd Ridge and Mississippi Canyon areas of the Gulf of Mexico. In addition, equity earnings from Deepwater Gateway, which owns the Marco Polo platform, increased $1.3 million quarter-to-quarter primarily due to higher processing volumes.

     Gross operating margin from our offshore crude oil pipelines was $4.0 million for the first quarter of 2007 versus $1.6 million for the first quarter of 2006. Our Marco Polo and Constitution oil pipelines posted higher crude oil transportation volumes during the first quarter of 2007 due to increased production activity by our customers. Collectively, gross operating margin from the Marco Polo and Constitution oil pipelines improved $2.7 million quarter-to-quarter. Total offshore crude oil transportation volumes were 153 MBPD during the first quarter of 2007 versus 113 MBPD during the first quarter of 2006.

     Gross operating margin from our offshore natural gas pipelines was $9.3 million for the first quarter of 2007 compared to $8.8 million for the first quarter of 2006. Offshore natural gas transportation volumes were 1,384 BBtu/d during the first quarter of 2007 versus 1,476 BBtu/d during the first quarter of 2006. The $0.5 million increase in gross operating margin quarter-to-quarter is primarily due to improved results on our Phoenix Gathering System. The Phoenix Gathering System was shut-in during the first quarter of 2006 due to Hurricane Katrina.

     As a result of industry losses associated with significant storms in recent years, insurance costs for offshore operations have increased dramatically. Insurance costs for our offshore assets were $7.6 million for the first quarter of 2007 compared to $1.6 million for the first quarter of 2006.

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     Petrochemical Services. Gross operating margin from this business segment was $37.6 million for the first quarter of 2007 compared to $27.5 million for the first quarter of 2006. The $10.1 million quarter-to-quarter increase in gross operating margin is primarily due to improved results from our octane enhancement business, which benefited from higher isooctane sales volumes and lower maintenance costs in the first quarter of 2007 relative to the first quarter of 2006. Gross operating margin from this business was a loss of $1.2 million for the first quarter of 2007 compared to a loss of $11.1 million for the first quarter of 2006. Our octane enhancement facility was idle during part of the first quarter of 2007 and 2006 for its planned annual turnaround and maintenance activities, which are scheduled during the winter months when demand for motor gasoline and motor gasoline additives are at seasonal lows.

     Gross operating margin from butane isomerization was $20.8 million for the first quarter of 2007 compared to $18.1 million for the first quarter of 2006. The quarter-to-quarter increase of $2.7 million is primarily due to higher processing volumes and lower fuel costs. Butane isomerization volumes increased to 95 MBPD during the first quarter of 2007 from 84 MBPD during the first quarter of 2006. Gross operating margin from our propylene fractionation and pipeline activities was $18.0 million for the first quarter of 2007 versus $20.5 million for the first quarter of 2006. The quarter-to-quarter decrease in gross operating margin of $2.5 million is primarily due to weaker polymer grade propylene sales margins during the first quarter of 2007 compared to the first quarter of 2006. Petrochemical transportation volumes were 102 MBPD during the first quarter of 2007 compared to 87 MBPD during the first quarter of 2006.

   Significant Risks and Uncertainties — Weather-Related Risks

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

     Hurricane Ivan insurance claims.We have submitted business interruption insurance claims for our estimated losses caused by Hurricane Ivan. During the three months ended March 31, 2007 and 2006, we received $0.4 million and $10.2 million, respectively, of nonrefundable cash proceeds from such claims. We are continuing our efforts to collect residual balances and expect to complete the process during 2007. To the extent we receive nonrefundable cash proceeds from business interruption insurance claims, they are recorded as a gain in our Unaudited Condensed Statements of Consolidated Operations in the period of receipt.

     We received $1.1 million and $24.1 million during the three months ended March 31, 2007 and March 31, 2006, respectively, related to property damage claims arising from Hurricane Ivan.

     Hurricanes Katrina and Rita insurance claims.Hurricanes Katrina and Rita, both significant storms, affected certain of our Gulf Coast assets in August and September of 2005, respectively. With respect to these storms, we have $77.7 million of estimated property damage claims outstanding at March 31, 2007, that we believe are probable of collection during the periods 2007 through 2009. We are pursuing collection of our property damage and business interruption claims related to Hurricanes Katrina and Rita.

Liquidity and Capital Resources

     Our primary cash requirements, in addition to normal operating expenses and debt service, are for working capital, capital expenditures, business acquisitions and distributions to our partners. We expect to fund our short-term needs for such items as operating expenses and sustaining capital expenditures with operating cash flows and short-term revolving credit arrangements. Capital expenditures for long-term needs resulting from internal growth projects and business acquisitions are expected to be funded by a variety of sources (either separately or in combination) including net cash flows provided by operating activities, borrowings under credit facilities, the issuance of additional equity and debt securities and proceeds from divestitures of ownership interest in assets to affiliates or third parties. We expect to fund

45

cash distributions to partners primarily with operating cash flows. Our debt service requirements are expected to be funded by operating cash flows and/or refinancing arrangements.

     At March 31, 2007, we had $58.2 million of unrestricted cash on hand and approximately $823.2 million of available credit under our Operating Partnership’s Multi-Year Revolving Credit Facility. At March 31, 2007, there was approximately $131.0 million of available credit under Duncan Energy Partners’ Credit Facility. In total, we had approximately $5.5 billion in principal outstanding under consolidated debt agreements at March 31, 2007.

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

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

   Registration Statements

     We may issue equity or debt securities to assist us in meeting our liquidity and capital spending requirements. Duncan Energy Partners may do likewise in meeting its liquidity and capital spending requirements. We have a universal shelf registration statement on file with the U.S. Securities and Exchange Commission (“SEC”) registering the issuance of $4.0 billion of equity and debt securities. After taking into account the past issuance of securities under this universal registration statement, we can issue approximately $2.1 billion of additional securities under this registration statement as of May 1, 2007.

     In February 2007, Duncan Energy Partners completed its initial public offering of 14,950,000 common units, the majority of proceeds from which were distributed to us. Duncan Energy Partners may issue additional amounts of equity in the future in connection with other acquisitions. For additional information regarding Duncan Energy Partners, see “Other Items — Initial Public Offering of Duncan Energy Partners” included within this Item 2.

     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 a related plan. The issuance of these units generated $12.5 million in net proceeds.

   Credit Ratings of Operating Partnership

     At May 1, 2007, the investment-grade credit ratings of our Operating Partnership’s debt securities were Baa3 by Moody’s Investor Services; BBB- by Fitch Ratings; and BBB- by Standard and Poor’s. All three ratings services have assigned to us a “stable outlook” with respect to their judgment of our future business performance.

46

     Debt Obligations

          For detailed information regarding our consolidated debt obligations and those of our unconsolidated affiliates, see Note 9 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report. The following table summarizes our consolidated debt obligations at the dates indicated (dollars in thousands):

	March 31,			December 31,
	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

(1)	In accordance with Statement of Financial Accounting Standards (“SFAS”) 6, “Classification of Short-Term Obligations Expected to be Refinanced,” long-term and current maturities of debt reflects the classification of such obligations at March 31, 2007 and December 31, 2006. With respect to Senior Notes E due 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.
(2)	Represents remaining debt obligations assumed in connection with the GulfTerra Merger.
(3)	The March 31, 2007 amount includes $25.0 million related to fair value hedges and a net $4.4 million in unamortized discounts and premiums. The December 31, 2006 amount includes $29.1 million related to fair value hedges and a net $4.4 million in unamortized discounts and premiums.

          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 respects to the debt of Duncan Energy Partners.

          Duncan Energy Partners’ debt obligation. 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. 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. For additional information regarding the debt obligation of Duncan Energy Partners, see Note 9 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

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          Debt obligations of unconsolidated affiliates.The following table summarizes the debt obligations of our unconsolidated affiliates (on a 100% basis to the joint venture) at March 31, 2007 and our ownership interest in each entity on that date (dollars in thousands):

	Our
	Ownership
	Interest			Total
Cameron Highway		50.0	%	$	415,000
Poseidon		36.0	%		91,000
Evangeline		49.5	%		25,650
Total				$	531,650

          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.

     Cash Flows from Operating, Investing and Financing Activities

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

	For the Three Months
	Ended March 31,
	2007		2006
Net cash flows provided by operating activities	$	420,751	$	494,276
Net cash used in investing activities		614,921		348,645
Net cash provided by (used in) financing activities		231,126		(152,738	)

          Net cash flows provided by operating activities is largely dependent on earnings from our business activities. As a result, these cash flows are exposed to certain risks. We operate predominantly in the midstream energy industry. We provide services for producers and consumers of natural gas, NGLs and crude oil. The products that we process, sell or transport are principally used as fuel for residential, agricultural and commercial heating; feedstocks in petrochemical manufacturing; and in the production of motor gasoline. Reduced demand for our services or products by industrial customers, whether because of general economic conditions, reduced demand for the end products made with our products or increased competition from other service providers or producers due to pricing differences or other reasons could have a negative impact on our earnings and thus the availability of cash from operating activities.

          Cash used in investing activities primarily represents expenditures for capital projects, business combinations, asset purchases and investments in unconsolidated affiliates. Cash provided by (or used in) financing activities generally consists of borrowings and repayments of debt, distributions to partners and proceeds from the issuance of equity securities. Amounts presented in our Unaudited Condensed Statements of Consolidated Cash Flows for borrowings and repayments under debt agreements are influenced by the magnitude of cash receipts and payments under our revolving credit facilities.

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

          Comparison of Three Months Ended March 31, 2007 withThree Months Ended March 31, 2006

          Operating activities. Net cash flows from operating activities for the three months ended March 31, 2007 decreased $73.5 million from that recorded for the three months ended March 31, 2006. The following information highlights significant factors that influenced the quarter-to-quarter change in net cash flows from operating activities:

§	Cash flows from operating activities are influenced by the timing of cash receipts and disbursements. Our accounts receivable and accounts payable liquidity metrics for the three months ended March 31, 2007 continue to evidence the strength of our underlying cash flows and approximate our liquidity metrics for the year ended December 31, 2006. However, metrics for the first quarter of 2007 were slightly weaker than those of the first quarter of 2006, which were influenced by the timing of cash receipts and payments following the initial stages of the GulfTerra Merger. Specifically, as to cash receipts, the average collection period for accounts receivable for the three months ended March 31, 2007 was five days slower when compared to the same period in 2006, with the related turnover rate decreasing 14% quarter-to-quarter. In addition, as to cash disbursements, our payable turnover rate decreased 19% quarter-to-quarter. These timing-related factors contributed to an approximate $60.1 million decrease in net cash receipts quarter-to-quarter.
§	Gross operating margin for the three months ended March 31, 2007 increased $12.0 million over that recorded for the three months ended March 31, 2006. The increase in gross operating margin is discussed under “Results of Operations” within this Item 2.
§	Net cash disbursements for interest and other expense items increased $16.3 million quarter-to-quarter. On a weighted-average basis, average debt outstanding increased approximately $0.7 billion quarter-over-quarter primarily due to our capital spending program.
§	Cash distributions from unconsolidated affiliates increased $8.7 million quarter-to-quarter primarily due to higher distributions paid by Deepwater Gateway and Poseidon. In general, distributions from our offshore projects were negatively affected during the first quarter of 2006 due to the lingering effects of Hurricanes Katrina and Rita on production volumes.

          Investing activities. Net cash used in investing activities was $614.9 million for the three months ended March 31, 2007 compared to $348.6 million for the three months ended March 31, 2006. The $266.3 million increase in cash payments is primarily due to a $297.2 million increase in capital expenditures quarter-to-quarter. For additional information regarding our capital spending program, see “Overview of Business – Capital Spending” within this Item 2.

          Financing activities. Net cash provided by financing activities was $231.1 million for the three months ended March 31, 2007 compared to net cash used in financing activities of $152.7 million for the same period during 2006. The following information highlights significant factors that influenced the quarter-to-quarter change in net cash provided by (or used in) financing activities:

§ Net borrowings under our consolidated debt agreements were $149 million during the first quarter of 2007. We made net repayments of $410 million under our consolidated debt agreements during the first quarter of 2006 primarily due to the application of $430 million in net proceeds from our March 2006 equity offering to temporarily reduce amounts outstanding under the Multi-Year Revolving Credit Facility. Our borrowing amounts during both quarterly periods were significantly influenced by our capital spending program.

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§	Contributions from minority interests increased $288.5 million quarter-to-quarter primarily due to the net proceeds received from Duncan Energy Partners’ initial public offering. On February 5, 2007, Duncan Energy Partners completed its initial public offering of 14,950,000 common units (including an overallotment amount of 1,950,000 common units) at $21.00 per unit, which generated net proceeds to Duncan Energy Partners of $291.9 million. As consideration for assets contributed and reimbursement for capital expenditures related to these assets, Duncan Energy Partners distributed $260.6 million of these net proceeds to us along with $198.9 million in borrowings under its credit facility and a final amount of 5,351,571 common units of Duncan Energy Partners. We used the cash received from Duncan Energy Partners to temporarily reduce amounts outstanding under our Operating Partnership’s Multi-Year Revolving Credit Facility.
	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 respects to the debt of Duncan Energy Partners. Duncan Energy Partners has entered into a $300.0 million revolving credit facility. At the closing of its initial public offering, Duncan Energy Partners made an initial drawing of $200.0 million under this facility to fund the $198.9 million cash distribution to the Operating Partnership and the remainder to pay debt issuance costs.
§	Net proceeds from the issuance of our limited partner interests were $17.0 million for the three months ended March 31, 2007 compared to $440.9 million for the three months ended March 31, 2006. Net proceeds from underwritten equity offerings were $430.0 million during the first quarter of 2006 reflecting the sale of 18,400,000 units.
§	Cash distributions to partners increased $39.6 million quarter-to-quarter due to an increase in our common units outstanding and quarterly cash distribution rates.

Critical Accounting Policies

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

          In general, there have been no significant changes in our critical accounting policies since December 31, 2006. For a detailed discussion of these policies, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies” in our annual report on Form 10-K for the year ended December 31, 2006. The following describes the estimation risk underlying our most significant financial statement items:

     Depreciation methods and estimated useful lives of property, plant and equipment

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

          At March 31, 2007 and December 31, 2006, the net book value of our property, plant and equipment was $10.2 billion and $9.8 billion, respectively. For additional information regarding our property, plant and equipment, see Note 6 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

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     Measuring recoverability of long-lived assets and equity method investments

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

          Equity method investments are evaluated for impairment whenever events or changes in circumstances indicate that there is a possible loss in value for the investment other than a temporary decline. The carrying value of an equity method investment is not recoverable if it exceeds the sum of discounted estimated cash flows expected to be derived from the investment. This estimate of discounted cash flows is based on a number of assumptions including discount rates; probabilities assigned to different cash flow scenarios; anticipated margins and volumes and estimated useful life of the investment. A significant change in these underlying assumptions could result in our recording an impairment charge.

     Amortization methods and estimated useful lives of qualifying intangible assets

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

          At March 31, 2007 and December 31, 2006, the carrying value of our intangible asset portfolio was $981.0 million and $1.0 billion, respectively. For additional information regarding our intangible assets, see Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

     Methods we employ to measure the fair value of goodwill

          Goodwill represents the excess of the purchase prices we paid for certain businesses over their respective fair values and is primarily comprised of $385.9 million associated with the GulfTerra Merger. We do not amortize goodwill; however, we test our goodwill (at the reporting unit level) for impairment during the second quarter of each fiscal year, and more frequently, if circumstances indicate it is more likely than not that the fair value of goodwill is below its carrying amount. Our goodwill testing involves the determination of a reporting unit’s fair value, which is predicated on our assumptions regarding the future economic prospects of the reporting unit. Our estimates of such prospects (i.e., cash flows) are based on a number of assumptions including anticipated margins and volumes of the underlying assets or asset group. A significant change in these underlying assumptions could result in our recording an impairment charge.

          At March 31, 2007 and December 31, 2006,the carrying value of our goodwill was $590.6 million and $590.5 million, respectively. For additional information regarding our goodwill, see Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

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

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

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     Reserves for environmental matters

          Each of our business segments is subject to federal, state and local laws and regulations governing environmental quality and pollution control. Such laws and regulations may, in certain instances, require us to remediate current or former operating sites where specified substances have been released or disposed of. We accrue reserves for environmental matters when our assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. Our assessments are based on studies, as well as site surveys, to determine the extent of any environmental damage and the necessary requirements to remediate this damage. Future environmental developments, such as increasingly strict environmental laws and additional claims for damages to property, employees and other persons resulting from current or past operations, could result in substantial additional costs beyond our current reserves.

          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.

          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. We follow the provisions of AICPA Statement of Position 96-1, which provides key guidance on recognition, measurement and disclosure of remediation liabilities. We have recorded our best estimate of the cost of remediation activities.

     Natural gas imbalances

          In the pipeline transportation business, natural gas imbalances frequently result from differences in gas volumes received from and delivered to our customers. Such differences occur when a customer delivers more or less gas into our pipelines than is physically redelivered back to them during a particular time period. The vast majority of our settlements are through in-kind arrangements whereby incremental volumes are delivered to a customer (in the case of an imbalance payable) or received from a customer (in the case of an imbalance receivable). Such in-kind deliveries are on-going and take place over several months. In some cases, settlements of imbalances built up over a period of time are ultimately cashed out and are generally negotiated at values which approximate average market prices over a period of time. As a result, for gas imbalances that are ultimately settled over future periods, we estimate the value of such current assets and liabilities using average market prices, which is representative of the estimated value of the imbalances upon final settlement. Changes in natural gas prices may impact our estimates.

          At March 31, 2007 and December 31, 2006, our imbalance receivables, net of allowance for doubtful accounts were $77.3 million and $97.8 million, respectively, and are reflected as a component of “Accounts and notes receivable – trade” on our Unaudited Condensed Consolidated Balance Sheets. At March 31, 2007 and December 31, 2006, our imbalance payables were $51.7 million and $51.2 million, respectively, and are reflected as a component of “Accrued gas payables” on our Unaudited Condensed Consolidated Balance Sheets.

Other Items

     Initial Public Offering of Duncan Energy Partners

          In September 2006, we formed a consolidated subsidiary, Duncan Energy Partners, to acquire, own and operate a diversified portfolio of midstream energy assets. On February 5, 2007, this subsidiary completed its initial public offering of 14,950,000 common units (including an overallotment amount of 1,950,000 common units) at $21.00 per unit, which generated net proceeds to Duncan Energy Partners of $291.9 million. As consideration for assets contributed and reimbursement for capital expenditures related to these assets, Duncan Energy Partners distributed $260.6 million of these net proceeds to us along with $198.9 million in borrowings under its credit facility and a final amount of 5,351,571 common units of

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Duncan Energy Partners. Duncan Energy Partners used $38.5 million of net proceeds from the overallotment to redeem 1,950,000 of the 7,301,571 common units it had originally issued to Enterprise Products Partners, resulting in the final amount of 5,351,571 common units beneficially owned by Enterprise Products Partners. We used the cash received from Duncan Energy Partners to temporarily reduce amounts outstanding under our Multi-Year Revolving Credit Facility.

          In summary, we contributed 66% of our equity interests in the following subsidiaries to Duncan Energy Partners:

§	Mont Belvieu Caverns, LLC (“Mont Belvieu Caverns”), a recently formed subsidiary, which owns salt dome storage caverns located in Mont Belvieu, Texas that receive, store and deliver NGLs and certain petrochemical products for industrial customers located along the upper Texas Gulf Coast, which has the largest concentration of petrochemical plants and refineries in the United States;
§	Acadian Gas, LLC (“Acadian Gas”), which owns an onshore natural gas pipeline system that gathers, transports, stores and markets natural gas in Louisiana. The Acadian Gas system links natural gas supplies from onshore and offshore Gulf of Mexico developments (including offshore pipelines, continental shelf and deepwater production) with local gas distribution companies, electric generation plants and industrial customers, including those in the Baton Rouge-New Orleans-Mississippi River corridor. A subsidiary of Acadian Gas owns a 49.5% equity interest in Evangeline Gas Pipeline, L.P. (“Evangeline”);
§	Sabine Propylene Pipeline L.P. (“Sabine Propylene”), which transports polymer-grade propylene between Port Arthur, Texas and a pipeline interconnect located in Cameron Parish, Louisiana;
§	Enterprise Lou-Tex Propylene Pipeline L.P. (“Lou-Tex Propylene”), which transports chemical-grade propylene from Sorrento, Louisiana to Mont Belvieu, Texas; and
§	South Texas NGL Pipelines, LLC (“South Texas NGL”), a recently formed subsidiary, which began transporting NGLs from Corpus Christi, Texas to Mont Belvieu, Texas in January 2007. South Texas NGL owns the DEP South Texas NGL Pipeline System.

          In addition, to the 34% ownership interest we retained in each of these entities, we also own the 2% general partner interest in Duncan Energy Partners and 26.4% of Duncan Energy Partners’ outstanding common units. Our Operating Partnership directs the business operations of Duncan Energy Partners through its ownership and control of the general partner of Duncan Energy Partners.

          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. 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.

          We have significant continuing involvement with all of the subsidiaries of Duncan Energy Partners, including the following types of transactions:

§	We utilize storage services provided by Mont Belvieu Caverns to support our Mont Belvieu fractionation and other businesses;
§	We buy natural gas from and sell natural gas to Acadian Gas in connection with its normal business activities; and
§	We are currently the sole shipper on the DEP South Texas NGL Pipeline System.

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          We may contribute other equity interests in our subsidiaries to Duncan Energy Partners and use the proceeds we receive from Duncan Energy Partners to fund our capital spending program. We have no obligation or commitment to make such contributions to Duncan Energy Partners.

     Contractual Obligations

          With the exception of the debt incurred by Duncan Energy Partners in connection with its initial public offering, there have been no significant changes in our schedule of maturities of long-term debt since those reported in our annual report on Form 10-K for the year ended December 31, 2006. See Note 9 of the Notes to the Unaudited Condensed Consolidated Financial Statements under Item 1 of this quarterly report for additional information regarding the debt obligations of Duncan Energy Partners.

     Off-Balance Sheet Arrangements

          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 Series A notes and $16.3 million of related make-whole premiums and accrued interest.

          Apart from the planned repayment of Cameron Highway’s Series A notes, there have been no significant changes with regards to our off-balance sheet arrangements since those reported in our annual report on Form 10-K for the year ended December 31, 2006.

     Summary of Related Party Transactions

          The following table summarizes our related party transactions for the periods indicated (dollars in thousands).

	For the Three Months
	Ended March 31,
	2007		2006
Revenues from consolidated operations:
EPCO and affiliates	$	8,542	$	5,632
Unconsolidated affiliates		55,700		84,443
Total	$	64,242	$	90,075
Operating costs and expenses:
EPCO and affiliates	$	78,673	$	94,957
Unconsolidated affiliates		5,273		6,686
Total	$	83,946	$	101,643
General and administrative costs:
EPCO and affiliates	$	13,055	$	11,008

          For additional information regarding our related party transactions, see Note 12 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

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

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

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

          On February 5, 2007, our consolidated subsidiary, Duncan Energy Partners, completed an underwritten initial public offering of its common units. Duncan Energy Partners was formed in September 2006 as a Delaware limited partnership to, among other things, acquire ownership interests in certain of our midstream energy businesses. For additional information regarding Duncan Energy Partners, see “Other Items – Initial Public Offering of Duncan Energy Partners” within this section.

     Non-GAAP reconciliations

          A reconciliation of our measurement of total non-GAAP gross operating margin to GAAP operating income and income before provision for income taxes, minority interest and the cumulative effect of change in accounting principle follows (dollars in thousands):

	For the Three Months
	Ended March 31,
	2007			2006
Total non-GAAP segment gross operating margin	$	324,499		$	312,523
Adjustments to reconcile total non-GAAP gross operating margin to GAAP operating income:
Depreciation, amortization and accretion in operating costs and expenses		(119,492	)		(104,816	)
Retained lease expense, net in operating costs and expenses		(526	)		(528	)
Gain on sale of assets in operating costs and expenses		73			61
General and administrative costs		(16,630	)		(13,740	)
GAAP consolidated operating income		187,924			193,500
Other net expense, primarily interest expense		(61,430	)		(56,108	)
GAAP income before provision for income taxes, minority interest and the cumulative effect of change in accounting principle	$	126,494		$	137,392

          EPCO subleases to us certain equipment located at our Mont Belvieu facility and 100 railcars for $1 per year (the “retained leases”). These subleases are part of the administrative services agreement that we executed with EPCO in connection with our formation in 1998. EPCO holds this equipment pursuant to operating leases for which it has retained the corresponding cash lease payment obligation. We record the full value of such lease payments made by EPCO as a non-cash related party operating expense, with the offset to partners’ equity recorded as a general contribution to our partnership. Apart from the partnership interests we granted to EPCO at our formation, EPCO does not receive any additional ownership rights as a result of its contribution to us of the retained leases.

     Cumulative effect of change in accounting principle

          Net income for the first quarter of 2006 includes a non-cash benefit of $1.5 million related to the cumulative effect of a change in accounting principle resulting from our adoption of SFAS 123(R) on January 1, 2006.

     Recent Accounting Pronouncements

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

§	SFAS 157, “Fair Value Measurements,” and
§	SFAS 159, “Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115.”

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

Item 3.Quantitative and Qualitative Disclosures about Market Risk.

          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) the 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 rate borrowings under various 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.

     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

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

          The total fair value of these eleven interest rate swaps at March 31, 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.

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

	Resulting	Swap Fair Value at
Scenario	Classification	March 31, 2007			April 25, 2007
FV assuming no change in underlying interest rates	Asset (Liability)	$	(24,991	)	$	(25,202	)
FV assuming 10% increase in underlying interest rates	Asset (Liability)		(51,622	)		(52,036	)
FV assuming 10% decrease in underlying interest rates	Asset (Liability)		1,640			1,631

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     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 debt during 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. 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.

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

		Commodity Financial Instrument
	Resulting	Portfolio FV
Scenario	Classification	March 31, 2007		April 30, 2007
FV assuming no change in underlying commodity prices	Asset (Liability)	$	241	$	(109	)
FV assuming 10% increase in underlying commodity prices	Asset (Liability)		171		(1,912	)
FV assuming 10% decrease in underlying commodity prices	Asset (Liability)		311		1,693

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

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had $1.3 million of such contracts outstanding that settled in April 2007. A 10% increase or decrease in the underlying exchange rate would have a nominal effect on our earnings.

Item 4.Controls and Procedures.

          Our management, with the participation of the chief executive officer (“CEO”) and chief financial officer (“CFO”) of Enterprise Products GP, has evaluated the effectiveness of our disclosure controls and procedures, including internal controls over financial reporting, as of the end of the period covered by this report. Based on their evaluation, the CEO and CFO of Enterprise Products GP have concluded that our disclosure controls and procedures are effective to ensure that material information relating to our partnership is made known to management on a timely basis. Our CEO and CFO noted no material weaknesses in the design or operation of our internal controls over financial reporting that are likely to adversely affect our ability to record, process, summarize and report financial information. Also, they detected no fraud involving management or employees who have a significant role in our internal controls over financial reporting.

          There have been no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) that have not been evaluated by management and no other factors that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.

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

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

PART II. OTHER INFORMATION.

Item 1.Legal Proceedings.

          See Part I, Item 1, Financial Statements, Note 14, “Commitments and Contingencies – Litigation,” of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report, which is incorporated herein by reference.

Item 1A.Risk Factors.

          In general, there have been no significant changes in our risk factors since December 31, 2006. For a detailed discussion of our risk factors, please read Item 1A “Risk Factors,” in our annual report on Form 10-K for the year ended December 31, 2006.

Item 2.Unregistered Sales of Equity Securities and Use of Proceeds.

          We did not repurchase any of our common units during the three months ended March 31, 2007. As of March 31, 2007, we and our affiliates are authorized to repurchase up to 618,400 common units under the December 1998 common unit repurchase program.

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Item 3.Defaults Upon Senior Securities.

          None.

Item 4.Submission of Matters to a Vote of Security Holders.

          None.

Item 5.Other Information.

          None.

Item 6.Exhibits.

Exhibit
Number	Exhibit*
2.1	Purchase and Sale Agreement between Coral Energy, LLC and Enterprise Products Operating L.P. dated September 22, 2000 (incorporated by reference to Exhibit 10.1 to Form 8-K filed September 26, 2000).
2.2	Purchase and Sale Agreement dated January 16, 2002 by and between Diamond-Koch, L.P. and Diamond-Koch III, L.P. and Enterprise Products Texas Operating L.P. (incorporated by reference to Exhibit 10.1 to Form 8-K filed February 8, 2002).
2.3	Purchase and Sale Agreement dated January 31, 2002 by and between D-K Diamond-Koch, L.L.C., Diamond-Koch, L.P. and Diamond-Koch III, L.P. as Sellers and Enterprise Products Operating L.P. as Buyer (incorporated by reference to Exhibit 10.2 to Form 8-K filed February 8, 2002).
2.4	Purchase Agreement by and between E-Birchtree, LLC and Enterprise Products Operating L.P. dated July 31, 2002 (incorporated by reference to Exhibit 2.2 to Form 8-K filed August 12, 2002).
2.5	Purchase Agreement by and between E-Birchtree, LLC and E-Cypress, LLC dated July 31, 2002 (incorporated by reference to Exhibit 2.1 to Form 8-K filed August 12, 2002).
2.6	Merger Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form 8-K filed December 15, 2003).
2.7	Amendment No. 1 to Merger Agreement, dated as of August 31, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form 8-K filed September 7, 2004).
2.8	Parent Company Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.2 to Form 8-K filed December 15, 2003).
2.9	Amendment No. 1 to Parent Company Agreement, dated as of April 19, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.1 to the Form 8-K filed April 21, 2004).
2.10	Second Amended and Restated Limited Liability Company Agreement of GulfTerra Energy Company, L.L.C., adopted by GulfTerra GP Holding Company, a Delaware corporation, and Enterprise Products GTM, LLC, a Delaware limited liability company, as of December 15, 2003, (incorporated by reference to Exhibit 2.3 to Form 8-K filed December 15, 2003).
2.11	Amendment No. 1 to Second Amended and Restated Limited Liability Company Agreement of GulfTerra Energy Company, L.L.C. adopted by Enterprise Products GTM, LLC as of September 30, 2004 (incorporated by reference to Exhibit 2.11 to Registration Statement on Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).

59

Exhibit
Number	Exhibit*
2.12	Purchase and Sale Agreement (Gas Plants), dated as of December 15, 2003, by and between El Paso Corporation, El Paso Field Services Management, Inc., El Paso Transmission, L.L.C., El Paso Field Services Holding Company and Enterprise Products Operating L.P. (incorporated by reference to Exhibit 2.4 to Form 8-K filed December 15, 2003).
3.1	Fifth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated effective as of August 8, 2005 (incorporated by reference to Exhibit 3.1 to Form 8-K filed August 10, 2005).
3.2	Fourth Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC, dated as of February 13, 2006 (incorporated by reference to Exhibit 3.1 to Form 8-K filed February 16, 2006).
3.3	Amended and Restated Agreement of Limited Partnership of Enterprise Products Operating L.P. dated as of July 31, 1998 (restated to include all agreements through December 10, 2003)(incorporated by reference to Exhibit 3.1 to Form 8-K filed July 1, 2005).
3.4	Certificate of Incorporation of Enterprise Products OLPGP, Inc., dated December 3, 2003 (incorporated by reference to Exhibit 3.5 to Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).
3.5	Bylaws of Enterprise Products OLPGP, Inc., dated December 8, 2003 (incorporated by reference to Exhibit 3.6 to Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).
3.6	Certificate of Limited Partnership of Duncan Energy Partners L.P. (incorporated by reference to Exhibit 3.1 to Duncan Energy Partners L.P. Form S-1 Registration Statement, Reg. No. 333-138371, filed November 2, 2006).
4.1	Indenture dated as of March 15, 2000, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and First Union National Bank, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed March 10, 2000).
4.2	First Supplemental Indenture dated as of January 22, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Registration Statement on Form S-4, Reg. No. 333-102776, filed January 28, 2003).
4.3	Global Note representing $350 million principal amount of 6.375% Series B Senior Notes due 2013 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Registration Statement on Form S-4, Reg. No. 333-102776, filed January 28, 2003).
4.4	Second Supplemental Indenture dated as of February 14, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 10-K filed March 31, 2003).
4.5	Global Note representing $500 million principal amount of 6.875% Series B Senior Notes due 2033 with attached Guarantee (incorporated by reference to Exhibit 4.8 to Form 10-K filed March 31, 2003).
4.6	Global Notes representing $450 million principal amount of 7.50% Senior Notes due 2011 (incorporated by reference to Exhibit 4.1 to Form 8-K filed January 25, 2001).
4.7	Form of Common Unit certificate (incorporated by reference to Exhibit 4.1 to Registration Statement on Form S-1/A; File No. 333-52537, filed July 21, 1998).
4.8	Contribution Agreement dated September 17, 1999 (incorporated by reference to Exhibit “B” to Schedule 13D filed September 27, 1999 by Tejas Energy, LLC).
4.9	Registration Rights Agreement dated September 17, 1999 (incorporated by reference to Exhibit “E” to Schedule 13D filed September 27, 1999 by Tejas Energy, LLC).
4.10	Unitholder Rights Agreement dated September 17, 1999 (incorporated by reference to Exhibit “C” to Schedule 13D filed September 27, 1999 by Tejas Energy, LLC).
4.11	Amendment No. 1, dated September 12, 2003, to Unitholder Rights Agreement dated September 17, 1999 (incorporated by reference to Exhibit 4.1 to Form 8-K filed September 15, 2003).
4.12	Agreement dated as of March 4, 2005 among Enterprise Products Partners L.P., Shell US Gas & Power LLC and Kayne Anderson MLP Investment Company (incorporated by reference to Exhibit 4.31 to Form S-3 Registration Statement, Reg. No. 333-123150, filed March 4, 2005).
4.13	$750 Million Multi-Year Revolving Credit Agreement dated as of August 25, 2004, among Enterprise Products Operating L.P., the Lenders party thereto, Wachovia Bank, National Association, as Administrative Agent, Citibank, N.A. and JPMorgan Chase Bank, as Co-

60

Exhibit
Number	Exhibit*
	Syndication Agents, and Mizuho Corporate Bank, Ltd., SunTrust Bank and The Bank of Nova Scotia, as Co-Documentation Agents (incorporated by reference to Exhibit 4.1 to Form 8-K filed on August 30, 2004).
4.14	Guaranty Agreement dated as of August 25, 2004, by Enterprise Products Partners L.P. in favor of Wachovia Bank, National Association, as Administrative Agent for the several lenders that are or become parties to the Credit Agreement included as Exhibit 4.13, above (incorporated by reference to Exhibit 4.2 to Form 8-K filed on August 30, 2004).
4.15	First Amendment dated October 5, 2005, to Multi-Year Revolving Credit Agreement dated as of August 25, 2004, among Enterprise Products Operating L.P., the Lenders party thereto, Wachovia Bank, National Association, as Administrative Agent, Citibank, N.A. and JPMorgan Chase Bank, as CO-Syndication Agents, and Mizuho Corporate Bank, Ltd., SunTrust Bank and The Bank of Nova Scotia, as Co-Documentation Agents (incorporated by reference to Exhibit 4.3 to Form 8-K filed on October 7, 2005).
4.16	$2.25 Billion 364-Day Revolving Credit Agreement dated as of August 25, 2004, among Enterprise Products Operating L.P., the Lenders party thereto, Wachovia Bank, National Association, as Administrative Agent, Citicorp North America, Inc. and Lehman Commercial Paper Inc., as Co-Syndication Agents, JPMorgan Chase Bank, UBS Loan Finance LLC and Morgan Stanley Senior Funding, Inc., as Co-Documentation Agents, Wachovia Capital Markets, LLC, Citigroup Global Markets Inc. and Lehman Brothers Inc., as Joint Lead Arrangers and Joint Book Runners (incorporated by reference to Exhibit 4.3 to Form 8-K filed on August 30, 2004).
4.17	Guaranty Agreement dated as of August 25, 2004, by Enterprise Products Partners L.P. in favor of Wachovia Bank, National Association, as Administrative Agent for the several lenders that are or become parties to the Credit Agreement included as Exhibit 4.16, above (incorporated by reference to Exhibit 4.4 to Form 8-K filed on August 30, 2004).
4.18	Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed on October 6, 2004).
4.19	First Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed on October 6, 2004).
4.20	Second Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed on October 6, 2004).
4.21	Third Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed on October 6, 2004).
4.22	Fourth Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.5 to Form 8-K filed on October 6, 2004).
4.23	Global Note representing $500 million principal amount of 4.000% Series B Senior Notes due 2007 with attached Guarantee (incorporated by reference to Exhibit 4.14 to Form S-3 Registration Statement Reg. No. 333-123150 filed on March 4, 2005).
4.24	Global Note representing $500 million principal amount of 5.600% Series B Senior Notes due 2014 with attached Guarantee (incorporated by reference to Exhibit 4.17 to Form S-3 Registration Statement Reg. No. 333-123150 filed on March 4, 2005).
4.25	Global Note representing $150 million principal amount of 5.600% Series B Senior Notes due 2014 with attached Guarantee (incorporated by reference to Exhibit 4.18 to Form S-3 Registration Statement Reg. No. 333-123150 filed on March 4, 2005).
4.26	Global Note representing $350 million principal amount of 6.650% Series B Senior Notes due 2034 with attached Guarantee (incorporated by reference to Exhibit 4.19 to Form S-3 Registration Statement Reg. No. 333-123150 filed on March 4, 2005).

61

Exhibit
Number	Exhibit*
4.27	Global Note representing $500 million principal amount of 4.625% Series B Senior Notes due 2009 with attached Guarantee (incorporated by reference to Exhibit 4.27 to Form 10-K for the year ended December 31, 2004 filed on March 15, 2005).
4.28	Fifth Supplemental Indenture dated as of March 2, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed on March 3, 2005).
4.29	Sixth Supplemental Indenture dated as of March 2, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed on March 3, 2005).
4.30	Global Note representing $250,000,000 principal amount of 5.00% Series B Senior Notes due 2015 with attached Guarantee (incorporated by reference to Exhibit 4.31 to Form 10-Q filed on November 4, 2005).
4.31	Global Note representing $250,000,000 principal amount of 5.75% Series B Senior Notes due 2035 with attached Guarantee (incorporated by reference to Exhibit 4.32 to Form 10-Q filed on November 4, 2005).
4.32	Registration Rights Agreement dated as of March 2, 2005, among Enterprise Products Partners, L.P., Enterprise Products Operating L.P. and the Initial Purchasers named therein (incorporated by reference to Exhibit 4.6 to Form 8-K filed on March 3, 2005).
4.33	Assumption Agreement dated as of September 30, 2004 between Enterprise Products Partners L.P. and GulfTerra Energy Partners, L.P. relating to the assumption by Enterprise of GulfTerra’s obligations under the GulfTerra Series F2 Convertible Units (incorporated by reference to Exhibit 4.4 to Form 8-K/A-1 filed on October 5, 2004).
4.34	Statement of Rights, Privileges and Limitations of Series F Convertible Units, included as Annex A to Third Amendment to the Second Amended and Restated Agreement of Limited Partnership of GulfTerra Energy Partners, L.P., dated May 16, 2003 (incorporated by reference to Exhibit 3.B.3 to Current Report on Form 8-K of GulfTerra Energy Partners, L.P., file no. 001-11680, filed with the Commission on May 19, 2003).
4.35	Unitholder Agreement between GulfTerra Energy Partners, L.P. and Fletcher International, Inc. dated May 16, 2003 (incorporated by reference to Exhibit 4.L to Current Report on Form 8-K of GulfTerra Energy Partners, L.P., file no. 001-11680, filed with the Commission on May 19, 2003).
4.36	Indenture dated as of May 17, 2001 among GulfTerra Energy Partners, L.P., GulfTerra Energy Finance Corporation, the Subsidiary Guarantors named therein and the Chase Manhattan Bank, as Trustee (filed as Exhibit 4.1 to GulfTerra’s Registration Statement on Form S-4 filed June 25, 2001, Registration Nos. 333-63800 through 333-63800-20); First Supplemental Indenture dated as of April 18, 2002 (filed as Exhibit 4.E.1 to GulfTerra’s 2002 First Quarter Form 10-Q); Second Supplemental Indenture dated as of April 18, 2002 (filed as Exhibit 4.E.2 to GulfTerra’s 2002 First Quarter Form 10-Q); Third Supplemental Indenture dated as of October 10, 2002 (filed as Exhibit 4.E.3 to GulfTerra’s 2002 Third Quarter Form 10-Q); Fourth Supplemental Indenture dated as of November 27, 2002 (filed as Exhibit 4.E.1 to GulfTerra’s Current Report on Form 8-K dated March 19, 2003); Fifth Supplemental Indenture dated as of January 1, 2003 (filed as Exhibit 4.E.2 to GulfTerra’s Current Report on Form 8-K dated March 19, 2003); Sixth Supplemental Indenture dated as of June 20, 2003 (filed as Exhibit 4.E.1 to GulfTerra’s 2003 Second Quarter Form 10-Q, file no. 001-11680).
4.37	Seventh Supplemental Indenture dated as of August 17, 2004 (filed as Exhibit 4.E.1 to GulfTerra’s Current Report on Form 8-K filed on August 19, 2004, file no. 001-11680).
4.38	Indenture dated as of November 27, 2002 by and among GulfTerra Energy Partners, L.P., GulfTerra Energy Finance Corporation, the Subsidiary Guarantors named therein and JPMorgan Chase Bank, as Trustee (filed as Exhibit 4.1 to GulfTerra’s Current Report of Form 8-K dated December 11, 2002); First Supplemental Indenture dated as of January 1, 2003 (filed as Exhibit 4.1.1 to GulfTerra’s Current Report on Form 8-K dated March 19, 2003); Second Supplemental Indenture dated as of June 20, 2003 (filed as Exhibit 4.1.1 to GulfTerra’s 2003 Second Quarter Form 10-Q, file no. 001-11680).
4.39	Third Supplemental Indenture dated as of August 17, 2004 (filed as Exhibit 4.1.1 to GulfTerra’s Current Report on Form 8-K filed on August 19, 2004, file no. 001-11680).

62

Exhibit
Number	Exhibit*
4.40	Indenture dated as of March 24, 2003 by and among GulfTerra Energy Partners, L.P., GulfTerra Energy Finance Corporation, the Subsidiary Guarantors named therein and JPMorgan Chase Bank, as Trustee dated as of March 24, 2003 (filed as Exhibit 4.K to GulfTerra’s Quarterly Report on Form 10-Q dated May 15, 2003); First Supplemental Indenture dated as of June 30, 2003 (filed as Exhibit 4.K.1 to GulfTerra’s 2003 Second Quarter Form 10-Q, file no. 001-11680).
4.41	Second Supplemental Indenture dated as of August 17, 2004 (filed as Exhibit 4.K.1 to GulfTerra’s Current Report on Form 8-K filed on August 19, 2004, file no. 001-11680).
4.42	Amended and Restated Credit Agreement dated as of June 29, 2005, among Cameron Highway Oil Pipeline Company, the Lenders party thereto, and SunTrust Bank, as Administrative Agent and Collateral Agent (incorporated by reference to Exhibit 4.1 to Form 8-K filed on July 1, 2005).
4.43	Seventh Supplemental Indenture dated as of June 1, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.46 to Form 10-Q filed November 4, 2005).
4.44	Global Note representing $500,000,000 principal amount of 4.95% Senior Notes due 2010 with attached Guarantee (incorporated by reference to Exhibit 4.47 to Form 10-Q filed November 4, 2005).
4.45	Note Purchase Agreement dated as of December 15, 2005 among Cameron Highway Oil Pipeline Company and the Note Purchasers listed therein (incorporated by reference to Exhibit 4.1 to Form 8-K filed December 21, 2005.)
4.46	Second Amendment dated June 22,2006, to Multi-Year Revolving Credit Agreement dated as of August 25, 2004 among Enterprise Products Operating L.P., the Lenders party thereto, Wachovia Bank, National Association, as Administrative Agent, Citibank, N.A. and JPMorgan Chase Bank, as Co-Syndication Agents and Mizuho Corporate Bank, LTD., SunTrust Bank and The Bank of Nova Scotia, as Co-Documentation Agents (incorporated by reference to Exhibit 4.6 to Form 10-Q filed August 8, 2006).
4.47	Third Amendment dated January 5, 2007, to Multi-Year Revolving Credit Agreement dated as of August 25, 2004 among Enterprise Products Operating L.P., the Lenders party thereto, Wachovia Bank, National Association, as Administrative Agent, Citibank, N.A. and JPMorgan Chase Bank, as Co-Syndication Agents and Mizuho Corporate Bank, LTD, SunTrust Bank and The Bank of Nova Scotia, as Co-Documentation Agents. (incorporated by reference to Exhibit 4.47 to Form 10-K filed February 28, 2006).
4.48	Eighth Supplemental Indenture dated as of July 18, 2006 to Indenture dated October 4, 2004 among Enterprise Products Operating L.P., as issuer, Enterprise Products Partners L.P., as parent guarantor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to exhibit 4.2 to Form 8-K filed July 19, 2006).
4.49	Form of Junior Note, including Guarantee (incorporated by reference to Exhibit 4.3 to Form 8-K file July 19, 2006).
4.50	Purchase Agreement, dated as of July 12, 2006 between Cerrito Gathering Company, Ltd., Cerrito Gas Marketing, Ltd., Encinal Gathering, Ltd., as Sellers, Lewis Energy Group, L.P. as Guarantor, and Enterprise Products Partners L.P., as buyer (incorporated by reference to Exhibit 4.6 to Form 10-Q filed August 8, 2006).
4.51	Purchase Agreement dated as of July 12, 2006 between Cerrito Gathering Company, Ltd., Cerrito Gas Marketing, Ltd., Encinal Gathering, Ltd., as Sellers, Lewis Energy Group, L.P., as Guarantor, and Enterprise Products Partners L.P., as Buyer (incorporated by reference to Exhibit 4.6 to Form 10-Q filed August 8, 2006).
10.1	Fourth Amended and Restated Administrative Services Agreement by and among EPCO, Inc., Enterprise Products Partners L.P., Enterprise Products Operating L.P., Enterprise Products GP, LLC, Enterprise Products OLPGP, Inc., Enterprise GP Holdings L.P., EPE Holdings, LLC, DEP Holdings, LLC, Duncan Energy Partners L.P., DEP OLPGP, LLC, DEP Operating Partnership L.P., TEPPCO Partners, L.P., Texas Eastern Products Pipeline Company, LLC, TE Products Pipeline Company, Limited Partnership, TEPPCO Midstream Companies, L.P., TCTM, L.P. and TEPPCO GP, Inc. dated January 30, 2007, but effective as of February 5, 2007 (incorporated by reference to Exhibit 10 to Form 8-K filed February 5, 2007 by Duncan Energy Partners).
10.2	Amendment No. 1 to the Fourth Amended and Restated Administrative Services Agreement dated February 28, 2007 (incorporated by reference to Exhibit 10.8 to Form 10-K filed February 28, 2006).

63

Exhibit
Number	Exhibit*
10.3	Omnibus Agreement, dated as of February 5, 2007 by and among Enterprise Products Operating L.P., DEP Holdings, LLC, Duncan Energy Partners L.P., DEP OLPGP, LLC, DEP Operating Partnership, L.P., Enterprise Lou-Tex Propylene Pipeline L.P., Sabine Propylene Pipeline L.P., Acadian Gas, LLC, Mont Belvieu Caverns, LLC, South Texas NGL Pipelines, LLC (incorporated by reference to Exhibit 10.19 to Form 8-K filed February 5, 2007 by Duncan Energy Partners).
10.4	Contribution, Conveyance And Assumption Agreement dated as of February 5, 2007, by and among Enterprise Products Operating L.P., DEP Holdings, LLC, Duncan Energy Partners L.P., DEP OLPGP, LLC and DEP Operating Partnership, L.P. (incorporated by reference to Exhibit 1.1 to Form 8-K filed February 5, 2007 by Duncan Energy Partners).
31.1#	Sarbanes-Oxley Section 302 certification of Robert G. Phillips for Enterprise Products Partners L.P. for the March 31, 2007 quarterly report on Form 10-Q.
31.2#	Sarbanes-Oxley Section 302 certification of Michael A. Creel for Enterprise Products Partners L.P. for the March 31, 2007 quarterly report on Form 10-Q.
32.1#	Section 1350 certification of Robert G. Phillips for the March 31, 2007 quarterly report on Form 10-Q.
32.2#	Section 1350 certification of Michael A. Creel for the March 31, 2007 quarterly report on Form 10-Q.

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

64

SIGNATURES

          Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this quarterly report on Form 10-Q to be signed on its behalf by the undersigned thereunto duly authorized, in the City of Houston, State of Texas on May 4, 2007.

ENTERPRISE PRODUCTS PARTNERS L.P.
(A Delaware Limited Partnership)
By:	Enterprise Products GP, LLC, as General Partner
By:	/s/ Michael J. Knesek
Name:	Michael J. Knesek
Title:	Senior Vice President, Controller and Principal Accounting Officer of the general partner

65

Index to Exhibits

Exhibit
Number	Exhibit*
2.1	Purchase and Sale Agreement between Coral Energy, LLC and Enterprise Products Operating L.P. dated September 22, 2000 (incorporated by reference to Exhibit 10.1 to Form 8-K filed September 26, 2000).
2.2	Purchase and Sale Agreement dated January 16, 2002 by and between Diamond-Koch, L.P. and Diamond-Koch III, L.P. and Enterprise Products Texas Operating L.P. (incorporated by reference to Exhibit 10.1 to Form 8-K filed February 8, 2002).
2.3	Purchase and Sale Agreement dated January 31, 2002 by and between D-K Diamond-Koch, L.L.C., Diamond-Koch, L.P. and Diamond-Koch III, L.P. as Sellers and Enterprise Products Operating L.P. as Buyer (incorporated by reference to Exhibit 10.2 to Form 8-K filed February 8, 2002).
2.4	Purchase Agreement by and between E-Birchtree, LLC and Enterprise Products Operating L.P. dated July 31, 2002 (incorporated by reference to Exhibit 2.2 to Form 8-K filed August 12, 2002).
2.5	Purchase Agreement by and between E-Birchtree, LLC and E-Cypress, LLC dated July 31, 2002 (incorporated by reference to Exhibit 2.1 to Form 8-K filed August 12, 2002).
2.6	Merger Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form 8-K filed December 15, 2003).
2.7	Amendment No. 1 to Merger Agreement, dated as of August 31, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form 8-K filed September 7, 2004).
2.8	Parent Company Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.2 to Form 8-K filed December 15, 2003).
2.9	Amendment No. 1 to Parent Company Agreement, dated as of April 19, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.1 to the Form 8-K filed April 21, 2004).
2.10	Second Amended and Restated Limited Liability Company Agreement of GulfTerra Energy Company, L.L.C., adopted by GulfTerra GP Holding Company, a Delaware corporation, and Enterprise Products GTM, LLC, a Delaware limited liability company, as of December 15, 2003, (incorporated by reference to Exhibit 2.3 to Form 8-K filed December 15, 2003).
2.11	Amendment No. 1 to Second Amended and Restated Limited Liability Company Agreement of GulfTerra Energy Company, L.L.C. adopted by Enterprise Products GTM, LLC as of September 30, 2004 (incorporated by reference to Exhibit 2.11 to Registration Statement on Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).

66

Exhibit
Number	Exhibit*
2.12	Purchase and Sale Agreement (Gas Plants), dated as of December 15, 2003, by and between El Paso Corporation, El Paso Field Services Management, Inc., El Paso Transmission, L.L.C., El Paso Field Services Holding Company and Enterprise Products Operating L.P. (incorporated by reference to Exhibit 2.4 to Form 8-K filed December 15, 2003).
3.1	Fifth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated effective as of August 8, 2005 (incorporated by reference to Exhibit 3.1 to Form 8-K filed August 10, 2005).
3.2	Third Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC, dated as of August 29, 2005 (incorporated by reference to Exhibit 3.1 to Form 8-K filed September 1, 2005).
3.3	Amended and Restated Agreement of Limited Partnership of Enterprise Products Operating L.P. dated as of July 31, 1998 (restated to include all agreements through December 10, 2003)(incorporated by reference to Exhibit 3.1 to Form 8-K filed July 1, 2005).
3.4	Certificate of Incorporation of Enterprise Products OLPGP, Inc., dated December 3, 2003 (incorporated by reference to Exhibit 3.5 to Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).
3.5	Bylaws of Enterprise Products OLPGP, Inc., dated December 8, 2003 (incorporated by reference to Exhibit 3.6 to Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).
3.6	Certificate of Limited Partnership of Duncan Energy Partners L.P. (incorporated by reference to Exhibit 3.1 to Duncan Energy Partners L.P. Form S-1 Registration Statement, Reg. No. 333-138371, filed November 2, 2006).
4.1	Indenture dated as of March 15, 2000, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and First Union National Bank, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed March 10, 2000).
4.2	First Supplemental Indenture dated as of January 22, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Registration Statement on Form S-4, Reg. No. 333-102776, filed January 28, 2003).
4.3	Global Note representing $350 million principal amount of 6.375% Series B Senior Notes due 2013 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Registration Statement on Form S-4, Reg. No. 333-102776, filed January 28, 2003).
4.4	Second Supplemental Indenture dated as of February 14, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 10-K filed March 31, 2003).
4.5	Global Note representing $500 million principal amount of 6.875% Series B Senior Notes due 2033 with attached Guarantee (incorporated by reference to Exhibit 4.8 to Form 10-K filed March 31, 2003).
4.6	Global Notes representing $450 million principal amount of 7.50% Senior Notes due 2011 (incorporated by reference to Exhibit 4.1 to Form 8-K filed January 25, 2001).
4.7	Form of Common Unit certificate (incorporated by reference to Exhibit 4.1 to Registration Statement on Form S-1/A; File No. 333-52537, filed July 21, 1998).
4.8	Contribution Agreement dated September 17, 1999 (incorporated by reference to Exhibit “B” to Schedule 13D filed September 27, 1999 by Tejas Energy, LLC).
4.9	Registration Rights Agreement dated September 17, 1999 (incorporated by reference to Exhibit “E” to Schedule 13D filed September 27, 1999 by Tejas Energy, LLC).
4.10	Unitholder Rights Agreement dated September 17, 1999 (incorporated by reference to Exhibit “C” to Schedule 13D filed September 27, 1999 by Tejas Energy, LLC).
4.11	Amendment No. 1, dated September 12, 2003, to Unitholder Rights Agreement dated September 17, 1999 (incorporated by reference to Exhibit 4.1 to Form 8-K filed September 15, 2003).
4.12	Agreement dated as of March 4, 2005 among Enterprise Products Partners L.P., Shell US Gas & Power LLC and Kayne Anderson MLP Investment Company (incorporated by reference to Exhibit 4.31 to Form S-3 Registration Statement, Reg. No. 333-123150, filed March 4, 2005).
4.13	$750 Million Multi-Year Revolving Credit Agreement dated as of August 25, 2004, among Enterprise Products Operating L.P., the Lenders party thereto, Wachovia Bank, National Association, as Administrative Agent, Citibank, N.A. and JPMorgan Chase Bank, as Co-

67

Exhibit
Number	Exhibit*
	Syndication Agents, and Mizuho Corporate Bank, Ltd., SunTrust Bank and The Bank of Nova Scotia, as Co-Documentation Agents (incorporated by reference to Exhibit 4.1 to Form 8-K filed on August 30, 2004).
4.14	Guaranty Agreement dated as of August 25, 2004, by Enterprise Products Partners L.P. in favor of Wachovia Bank, National Association, as Administrative Agent for the several lenders that are or become parties to the Credit Agreement included as Exhibit 4.13, above (incorporated by reference to Exhibit 4.2 to Form 8-K filed on August 30, 2004).
4.15	First Amendment dated October 5, 2005, to Multi-Year Revolving Credit Agreement dated as of August 25, 2004, among Enterprise Products Operating L.P., the Lenders party thereto, Wachovia Bank, National Association, as Administrative Agent, Citibank, N.A. and JPMorgan Chase Bank, as CO-Syndication Agents, and Mizuho Corporate Bank, Ltd., SunTrust Bank and The Bank of Nova Scotia, as Co-Documentation Agents (incorporated by reference to Exhibit 4.3 to Form 8-K filed on October 7, 2005).
4.16	$2.25 Billion 364-Day Revolving Credit Agreement dated as of August 25, 2004, among Enterprise Products Operating L.P., the Lenders party thereto, Wachovia Bank, National Association, as Administrative Agent, Citicorp North America, Inc. and Lehman Commercial Paper Inc., as Co-Syndication Agents, JPMorgan Chase Bank, UBS Loan Finance LLC and Morgan Stanley Senior Funding, Inc., as Co-Documentation Agents, Wachovia Capital Markets, LLC, Citigroup Global Markets Inc. and Lehman Brothers Inc., as Joint Lead Arrangers and Joint Book Runners (incorporated by reference to Exhibit 4.3 to Form 8-K filed on August 30, 2004).
4.17	Guaranty Agreement dated as of August 25, 2004, by Enterprise Products Partners L.P. in favor of Wachovia Bank, National Association, as Administrative Agent for the several lenders that are or become parties to the Credit Agreement included as Exhibit 4.16, above (incorporated by reference to Exhibit 4.4 to Form 8-K filed on August 30, 2004).
4.18	Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed on October 6, 2004).
4.19	First Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed on October 6, 2004).
4.20	Second Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed on October 6, 2004).
4.21	Third Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed on October 6, 2004).
4.22	Fourth Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.5 to Form 8-K filed on October 6, 2004).
4.23	Global Note representing $500 million principal amount of 4.000% Series B Senior Notes due 2007 with attached Guarantee (incorporated by reference to Exhibit 4.14 to Form S-3 Registration Statement Reg. No. 333-123150 filed on March 4, 2005).
4.24	Global Note representing $500 million principal amount of 5.600% Series B Senior Notes due 2014 with attached Guarantee (incorporated by reference to Exhibit 4.17 to Form S-3 Registration Statement Reg. No. 333-123150 filed on March 4, 2005).
4.25	Global Note representing $150 million principal amount of 5.600% Series B Senior Notes due 2014 with attached Guarantee (incorporated by reference to Exhibit 4.18 to Form S-3 Registration Statement Reg. No. 333-123150 filed on March 4, 2005).
4.26	Global Note representing $350 million principal amount of 6.650% Series B Senior Notes due 2034 with attached Guarantee (incorporated by reference to Exhibit 4.19 to Form S-3 Registration Statement Reg. No. 333-123150 filed on March 4, 2005).

68

Exhibit
Number	Exhibit*
4.27	Global Note representing $500 million principal amount of 4.625% Series B Senior Notes due 2009 with attached Guarantee (incorporated by reference to Exhibit 4.27 to Form 10-K for the year ended December 31, 2004 filed on March 15, 2005).
4.28	Fifth Supplemental Indenture dated as of March 2, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed on March 3, 2005).
4.29	Sixth Supplemental Indenture dated as of March 2, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed on March 3, 2005).
4.30	Global Note representing $250,000,000 principal amount of 5.00% Series B Senior Notes due 2015 with attached Guarantee (incorporated by reference to Exhibit 4.31 to Form 10-Q filed on November 4, 2005).
4.31	Global Note representing $250,000,000 principal amount of 5.75% Series B Senior Notes due 2035 with attached Guarantee (incorporated by reference to Exhibit 4.32 to Form 10-Q filed on November 4, 2005).
4.32	Registration Rights Agreement dated as of March 2, 2005, among Enterprise Products Partners, L.P., Enterprise Products Operating L.P. and the Initial Purchasers named therein (incorporated by reference to Exhibit 4.6 to Form 8-K filed on March 3, 2005).
4.33	Assumption Agreement dated as of September 30, 2004 between Enterprise Products Partners L.P. and GulfTerra Energy Partners, L.P. relating to the assumption by Enterprise of GulfTerra’s obligations under the GulfTerra Series F2 Convertible Units (incorporated by reference to Exhibit 4.4 to Form 8-K/A-1 filed on October 5, 2004).
4.34	Statement of Rights, Privileges and Limitations of Series F Convertible Units, included as Annex A to Third Amendment to the Second Amended and Restated Agreement of Limited Partnership of GulfTerra Energy Partners, L.P., dated May 16, 2003 (incorporated by reference to Exhibit 3.B.3 to Current Report on Form 8-K of GulfTerra Energy Partners, L.P., file no. 001-11680, filed with the Commission on May 19, 2003).
4.35	Unitholder Agreement between GulfTerra Energy Partners, L.P. and Fletcher International, Inc. dated May 16, 2003 (incorporated by reference to Exhibit 4.L to Current Report on Form 8-K of GulfTerra Energy Partners, L.P., file no. 001-11680, filed with the Commission on May 19, 2003).
4.36	Indenture dated as of May 17, 2001 among GulfTerra Energy Partners, L.P., GulfTerra Energy Finance Corporation, the Subsidiary Guarantors named therein and the Chase Manhattan Bank, as Trustee (filed as Exhibit 4.1 to GulfTerra’s Registration Statement on Form S-4 filed June 25, 2001, Registration Nos. 333-63800 through 333-63800-20); First Supplemental Indenture dated as of April 18, 2002 (filed as Exhibit 4.E.1 to GulfTerra’s 2002 First Quarter Form 10-Q); Second Supplemental Indenture dated as of April 18, 2002 (filed as Exhibit 4.E.2 to GulfTerra’s 2002 First Quarter Form 10-Q); Third Supplemental Indenture dated as of October 10, 2002 (filed as Exhibit 4.E.3 to GulfTerra’s 2002 Third Quarter Form 10-Q); Fourth Supplemental Indenture dated as of November 27, 2002 (filed as Exhibit 4.E.1 to GulfTerra’s Current Report on Form 8-K dated March 19, 2003); Fifth Supplemental Indenture dated as of January 1, 2003 (filed as Exhibit 4.E.2 to GulfTerra’s Current Report on Form 8-K dated March 19, 2003); Sixth Supplemental Indenture dated as of June 20, 2003 (filed as Exhibit 4.E.1 to GulfTerra’s 2003 Second Quarter Form 10-Q, file no. 001-11680).
4.37	Seventh Supplemental Indenture dated as of August 17, 2004 (filed as Exhibit 4.E.1 to GulfTerra’s Current Report on Form 8-K filed on August 19, 2004, file no. 001-11680).
4.38	Indenture dated as of November 27, 2002 by and among GulfTerra Energy Partners, L.P., GulfTerra Energy Finance Corporation, the Subsidiary Guarantors named therein and JPMorgan Chase Bank, as Trustee (filed as Exhibit 4.1 to GulfTerra’s Current Report of Form 8-K dated December 11, 2002); First Supplemental Indenture dated as of January 1, 2003 (filed as Exhibit 4.1.1 to GulfTerra’s Current Report on Form 8-K dated March 19, 2003); Second Supplemental Indenture dated as of June 20, 2003 (filed as Exhibit 4.1.1 to GulfTerra’s 2003 Second Quarter Form 10-Q, file no. 001-11680).
4.39	Third Supplemental Indenture dated as of August 17, 2004 (filed as Exhibit 4.1.1 to GulfTerra’s Current Report on Form 8-K filed on August 19, 2004, file no. 001-11680).

69

Exhibit
Number	Exhibit*
4.40	Indenture dated as of March 24, 2003 by and among GulfTerra Energy Partners, L.P., GulfTerra Energy Finance Corporation, the Subsidiary Guarantors named therein and JPMorgan Chase Bank, as Trustee dated as of March 24, 2003 (filed as Exhibit 4.K to GulfTerra’s Quarterly Report on Form 10-Q dated May 15, 2003); First Supplemental Indenture dated as of June 30, 2003 (filed as Exhibit 4.K.1 to GulfTerra’s 2003 Second Quarter Form 10-Q, file no. 001-11680).
4.41	Second Supplemental Indenture dated as of August 17, 2004 (filed as Exhibit 4.K.1 to GulfTerra’s Current Report on Form 8-K filed on August 19, 2004, file no. 001-11680).
4.42	Amended and Restated Credit Agreement dated as of June 29, 2005, among Cameron Highway Oil Pipeline Company, the Lenders party thereto, and SunTrust Bank, as Administrative Agent and Collateral Agent (incorporated by reference to Exhibit 4.1 to Form 8-K filed on July 1, 2005).
4.43	Seventh Supplemental Indenture dated as of June 1, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.46 to Form 10-Q filed November 4, 2005).
4.44	Global Note representing $500,000,000 principal amount of 4.95% Senior Notes due 2010 with attached Guarantee (incorporated by reference to Exhibit 4.47 to Form 10-Q filed November 4, 2005).
4.45	Note Purchase Agreement dated as of December 15, 2005 among Cameron Highway Oil Pipeline Company and the Note Purchasers listed therein (incorporated by reference to Exhibit 4.1 to Form 8-K filed December 21, 2005.)
4.46	Second Amendment dated June 22,2006, to Multi-Year Revolving Credit Agreement dated as of August 25, 2004 among Enterprise Products Operating L.P., the Lenders party thereto, Wachovia Bank, National Association, as Administrative Agent, Citibank, N.A. and JPMorgan Chase Bank, as Co-Syndication Agents and Mizuho Corporate Bank, LTD., SunTrust Bank and The Bank of Nova Scotia, as Co-Documentation Agents (incorporated by reference to Exhibit 4.6 to Form 10-Q filed August 8, 2006).
4.47	Third Amendment dated January 5, 2007, to Multi-Year Revolving Credit Agreement dated as of August 25, 2004 among Enterprise Products Operating L.P., the Lenders party thereto, Wachovia Bank, National Association, as Administrative Agent, Citibank, N.A. and JPMorgan Chase Bank, as Co-Syndication Agents and Mizuho Corporate Bank, LTD, SunTrust Bank and The Bank of Nova Scotia, as Co-Documentation Agents. (incorporated by reference to Exhibit 4.47 to Form 10-K filed February 28, 2006).
4.48	Eighth Supplemental Indenture dated as of July 18, 2006 to Indenture dated October 4, 2004 among Enterprise Products Operating L.P., as issuer, Enterprise Products Partners L.P., as parent guarantor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to exhibit 4.2 to Form 8-K filed July 19, 2006).
4.49	Form of Junior Note, including Guarantee (incorporated by reference to Exhibit 4.3 to Form 8-K file July 19, 2006).
4.50	Purchase Agreement, dated as of July 12, 2006 between Cerrito Gathering Company, Ltd., Cerrito Gas Marketing, Ltd., Encinal Gathering, Ltd., as Sellers, Lewis Energy Group, L.P. as Guarantor, and Enterprise Products Partners L.P., as buyer (incorporated by reference to Exhibit 4.6 to Form 10-Q filed August 8, 2006).
4.51	Purchase Agreement dated as of July 12, 2006 between Cerrito Gathering Company, Ltd., Cerrito Gas Marketing, Ltd., Encinal Gathering, Ltd., as Sellers, Lewis Energy Group, L.P., as Guarantor, and Enterprise Products Partners L.P., as Buyer (incorporated by reference to Exhibit 4.6 to Form 10-Q filed August 8, 2006).
10.1	Fourth Amended and Restated Administrative Services Agreement by and among EPCO, Inc., Enterprise Products Partners L.P., Enterprise Products Operating L.P., Enterprise Products GP, LLC, Enterprise Products OLPGP, Inc., Enterprise GP Holdings L.P., EPE Holdings, LLC, DEP Holdings, LLC, Duncan Energy Partners L.P., DEP OLPGP, LLC, DEP Operating Partnership L.P., TEPPCO Partners, L.P., Texas Eastern Products Pipeline Company, LLC, TE Products Pipeline Company, Limited Partnership, TEPPCO Midstream Companies, L.P., TCTM, L.P. and TEPPCO GP, Inc. dated January 30, 2007, but effective as of February 5, 2007 (incorporated by reference to Exhibit 10 to Form 8-K filed February 5, 2007 by Duncan Energy Partners).
10.2	Amendment No. 1 to the Fourth Amended and Restated Administrative Services Agreement dated February 28, 2007 (incorporated by reference to Exhibit 10.8 to Form 10-K filed February 28, 2006).

70

Exhibit
Number	Exhibit*
10.3	Omnibus Agreement, dated as of February 5, 2007 by and among Enterprise Products Operating L.P., DEP Holdings, LLC, Duncan Energy Partners L.P., DEP OLPGP, LLC, DEP Operating Partnership, L.P., Enterprise Lou-Tex Propylene Pipeline L.P., Sabine Propylene Pipeline L.P., Acadian Gas, LLC, Mont Belvieu Caverns, LLC, South Texas NGL Pipelines, LLC (incorporated by reference to Exhibit 10.19 to Form 8-K filed February 5, 2007 by Duncan Energy Partners).
10.4	Contribution, Conveyance And Assumption Agreement dated as of February 5, 2007, by and among Enterprise Products Operating L.P., DEP Holdings, LLC, Duncan Energy Partners L.P., DEP OLPGP, LLC and DEP Operating Partnership, L.P. (incorporated by reference to Exhibit 1.1 to Form 8-K filed February 5, 2007 by Duncan Energy Partners).
31.1#	Sarbanes-Oxley Section 302 certification of Robert G. Phillips for Enterprise Products Partners L.P. for the March 31, 2007 quarterly report on Form 10-Q.
31.2#	Sarbanes-Oxley Section 302 certification of Michael A. Creel for Enterprise Products Partners L.P. for the March 31, 2007 quarterly report on Form 10-Q.
32.1#	Section 1350 certification of Robert G. Phillips for the March 31, 2007 quarterly report on Form 10-Q.
32.2#	Section 1350 certification of Michael A. Creel for the March 31, 2007 quarterly report on Form 10-Q.

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

71