Edgar Filing: ENTERPRISE PRODUCTS PARTNERS L P

epdform10q_033109.htm

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, 2009

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.

Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes o No ¨

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

Large accelerated filer þ	Accelerated filer o
Non-accelerated filer o (Do not check if a smaller reporting company)	Smaller reporting company o

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

Yes o No þ

There were 455,590,244 common units, including 1,952,400 restricted common units, of Enterprise Products Partners L.P. outstanding at May 1, 2009. These common units trade on the New York Stock Exchange under the ticker symbol “EPD.”

Table of Contents

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 Equity	6
	Notes to Unaudited Condensed Consolidated Financial Statements:
	1. Partnership Organization	7
	2. General Accounting Matters	8
	3. Accounting for Equity Awards	9
	4. Derivative Instruments and Hedging Activities	11
	5. Inventories	19
	6. Property, Plant and Equipment	20
	7. Investments in and Advances to Unconsolidated Affiliates	21
	8. Intangible Assets and Goodwill	22
	9. Debt Obligations	23
	10. Equity and Distributions	25
	11. Business Segments	27
	12. Related Party Transactions	31
	13. Earnings Per Unit	35
	14. Commitments and Contingencies	36
	15. Significant Risks and Uncertainties – Weather-Related Risks	38
	16. Supplemental Cash Flow Information	39
	17. Condensed Financial Information of EPO	39
	18. Subsequent Events	40
Item 2.	Management’s Discussion and Analysis of Financial Condition
	and Results of Operations.	42
Item 3.	Quantitative and Qualitative Disclosures about Market Risk.	58
Item 4.	Controls and Procedures.	59

PART II. OTHER INFORMATION.
Item 1.	Legal Proceedings.	60
Item 1A.	Risk Factors.	60
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	61
Item 3.	Defaults upon Senior Securities.	61
Item 4.	Submission of Matters to a Vote of Security Holders.	61
Item 5.	Other Information.	61
Item 6.	Exhibits.	61

Signatures		66

Table of Contents

PART I. FINANCIAL INFORMATION.

Item 1. Financial Statements.

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

	March 31,			December 31,
ASSETS	2009			2008
Current assets:
Cash and cash equivalents	$	41.5		$	35.4
Restricted cash		244.5			203.8
Accounts and notes receivable – trade, net of allowance for doubtful accounts of $14.8 at March 31, 2009 and $15.1 at December 31, 2008		1,084.4			1,185.5
Accounts receivable – related parties		55.0			61.6
Inventories		520.0			362.8
Derivative assets (see Note 4)		241.3			202.8
Prepaid and other current assets		103.9			111.8
Total current assets		2,290.6			2,163.7
Property, plant and equipment, net		13,505.7			13,154.8
Investments in and advances to unconsolidated affiliates		935.6			949.5
Intangible assets, net of accumulated amortization of $451.1 at March 31, 2009 and $429.9 at December 31, 2008		834.4			855.4
Goodwill		706.9			706.9
Deferred tax asset		0.7			0.4
Other assets		161.4			126.8
Total assets	$	18,435.3		$	17,957.5

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable – trade	$	397.0		$	300.5
Accounts payable – related parties		22.0			39.6
Accrued product payables		1,079.0			1,142.4
Accrued expenses		56.8			48.8
Accrued interest		110.6			151.9
Derivative liabilities (see Note 4)		339.0			287.2
Other current liabilities		281.4			252.7
Total current liabilities		2,285.8			2,223.1
Long-term debt: (see Note 9)
Senior debt obligations – principal		8,015.9			7,813.4
Junior subordinated notes – principal		1,232.7			1,232.7
Other		58.7			62.3
Total long-term debt		9,307.3			9,108.4
Deferred tax liabilities		67.3			66.1
Other long-term liabilities		79.6			81.3
Commitments and contingencies
Equity: (see Note 10)
Enterprise Products Partners L.P. partners’ equity:
Limited Partners:
Common units (453,637,844 units outstanding at March 31, 2009 and 439,354,731 units outstanding at December 31, 2008)		6,289.1			6,036.9
Restricted common units (1,952,400 units outstanding at March 31, 2009 and 2,080,600 units outstanding at December 31, 2008)		28.2			26.2
General partner		128.8			123.6
Accumulated other comprehensive loss		(138.4	)		(97.2	)
Total Enterprise Products Partners L.P. partners’ equity		6,307.7			6,089.5
Noncontrolling interest		387.6			389.1
Total equity		6,695.3			6,478.6
Total liabilities and equity	$	18,435.3		$	17,957.5

See Notes to Unaudited Condensed Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS

(Dollars in millions, except per unit amounts)

	For the Three Months
	Ended March 31,
	2009			2008
Revenues:
Third parties	$	3,178.6		$	5,383.8
Related parties		244.5			300.7
Total revenues (see Note 11)		3,423.1			5,684.5
Costs and expenses:
Operating costs and expenses:
Third parties		2,831.6			5,134.6
Related parties		209.7			176.6
Total operating costs and expenses		3,041.3			5,311.2
General and administrative costs:
Third parties		5.2			3.5
Related parties		17.8			17.7
Total general and administrative costs		23.0			21.2
Total costs and expenses		3,064.3			5,332.4
Equity in earnings of unconsolidated affiliates		13.4			14.6
Operating income		372.2			366.7
Other income (expense):
Interest expense		(120.4	)		(91.9	)
Interest income		0.6			1.6
Other, net		0.1			(0.7	)
Total other expense, net		(119.7	)		(91.0	)
Income before provision for income taxes		252.5			275.7
Provision for income taxes		(15.2	)		(3.7	)
Net income		237.3			272.0
Net income attributable to noncontrolling interest		(12.0	)		(12.4	)
Net income attributable to Enterprise Products Partners L.P.	$	225.3		$	259.6

Net income allocated to:
Limited partners	$	186.3		$	225.2
General partner	$	39.0		$	34.4

Basic and diluted earnings per unit (see Note 13)	$	0.41		$	0.51

See Notes to Unaudited Condensed Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED

COMPREHENSIVE INCOME

(Dollars in millions)

	For the Three Months
	Ended March 31,
	2009			2008

Net income	$	237.3		$	272.0
Other comprehensive income (loss):
Cash flow hedges:
Commodity derivative instrument gains (losses) during period		(62.0	)		88.8
Reclassification adjustment for losses included in net income related to commodity derivative instruments		32.2			4.2
Interest rate derivative instrument losses during period		(0.7	)		(26.0	)
Reclassification adjustment for (gains) losses included in net income related to interest rate derivative instruments		0.9			(1.6	)
Foreign currency derivative losses		(10.6	)		(1.2	)
Total cash flow hedges		(40.2	)		64.2
Foreign currency translation adjustment		(0.4	)		(0.4	)
Change in funded status of pension and postretirement plans, net of tax		--			(0.3	)
Total other comprehensive income (loss)		(40.6	)		63.5
Comprehensive income		196.7			335.5
Comprehensive income attributable to noncontrolling interest		(12.6	)		(8.6	)
Comprehensive income attributable to Enterprise Products Partners L.P.	$	184.1		$	326.9

See Notes to Unaudited Condensed Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Dollars in millions)

	For the Three Months
	Ended March 31,
	2009			2008
Operating activities:
Net income	$	237.3		$	272.0
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		154.1			135.9
Equity in earnings of unconsolidated affiliates		(13.4	)		(14.6	)
Distributions received from unconsolidated affiliates		22.9			28.6
Operating lease expense paid by EPCO, Inc.		0.2			0.5
Gain from asset sales and related transactions		(0.2	)		(0.1	)
Deferred income tax expense		0.9			(0.9	)
Changes in fair market value of derivative instruments		(12.0	)		0.7
Effect of pension settlement recognition		(0.1	)		(0.1	)
Net effect of changes in operating accounts (see Note 16)		(171.6	)		(156.9	)
Net cash flows provided by operating activities		218.1			265.1
Investing activities:
Capital expenditures		(392.5	)		(624.1	)
Contributions in aid of construction costs		6.4			6.8
Decrease (increase) in restricted cash		(40.7	)		64.5
Investments in unconsolidated affiliates		(6.4	)		(7.4	)
Advances from (to) unconsolidated affiliates		4.8			(8.5	)
Other proceeds from investing activities		4.1			0.1
Cash used in investing activities		(424.3	)		(568.6	)
Financing activities:
Borrowings under debt agreements		861.6			1,509.0
Repayments of debt		(663.1	)		(936.0	)
Debt issuance costs		(1.2	)		--
Distributions paid to partners		(279.7	)		(251.9	)
Distributions paid to noncontrolling interest		(14.1	)		(16.1	)
Net proceeds from issuance of common units		310.8			18.3
Monetization of interest rate derivative instruments - treasury locks		--			6.3
Cash provided by financing activities		214.3			329.6
Effect of exchange rate changes on cash		(2.0	)		(0.2	)
Net change in cash and cash equivalents		8.1			26.1
Cash and cash equivalents, January 1		35.4			39.7
Cash and cash equivalents, March 31	$	41.5		$	65.6

See Notes to Unaudited Condensed Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY

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

(Dollars in millions)

	Enterprise Products Partners L.P.
							Accumulated
							Other
	Limited			General			Comprehensive			Noncontrolling
	Partners			Partner			Loss			Interest			Total
Balance, December 31, 2008	$	6,063.1		$	123.6		$	(97.2	)	$	389.1		$	6,478.6
Net income		186.3			39.0			--			12.0			237.3
Operating leases paid by EPCO, Inc.		0.2			--			--			--			0.2
Cash distributions to partners		(239.5	)		(40.1	)		--			--			(279.6	)
Unit option reimbursements to EPCO, Inc.		(0.1	)		--			--			--			(0.1	)
Distributions paid to noncontrolling interest (see Note 10)		--			--			--			(14.1	)		(14.1	)
Non-cash distributions		(2.0	)		--			--			--			(2.0	)
Net proceeds from issuance of common units		304.5			6.2			--			--			310.7
Proceeds from exercise of unit options		0.1			--			--			--			0.1
Amortization of equity awards		4.7			0.1			--			--			4.8
Foreign currency translation adjustment		--			--			(0.4	)		--			(0.4	)
Cash flow hedges		--			--			(40.8	)		0.6			(40.2	)
Balance, March 31, 2009	$	6,317.3		$	128.8		$	(138.4	)	$	387.6		$	6,695.3

	Enterprise Products Partners L.P.
							Accumulated
							Other
	Limited			General			Comprehensive			Noncontrolling
	Partners			Partner			Income			Interest			Total
Balance, December 31, 2007	$	5,992.9		$	122.3		$	19.1		$	427.8		$	6,562.1
Net income		225.2			34.4			--			12.4			272.0
Operating leases paid by EPCO, Inc.		0.5			--			--			--			0.5
Cash distributions to partners		(217.5	)		(34.3	)		--			--			(251.8	)
Unit option reimbursements to EPCO, Inc.		(0.1	)		--			--			--			(0.1	)
Distributions paid to noncontrolling interest (see Note 10)		--			--			--			(16.1	)		(16.1	)
Non-cash distributions		(1.3	)		--			--			--			(1.3	)
Net proceeds from issuance of common units		17.6			0.4			--			--			18.0
Proceeds from exercise of unit options		0.3			--			--			--			0.3
Amortization of equity awards		3.6			0.1			--			--			3.7
Foreign currency translation adjustment		--			--			(0.4	)		--			(0.4	)
Change in funded status of pension and postretirement plans		--			--			(0.3	)		--			(0.3	)
Cash flow hedges		--			--			68.0			(3.8	)		64.2
Balance, March 31, 2008	$	6,021.2		$	122.9		$	86.4		$	420.3		$	6,650.8

See Notes to Unaudited Condensed Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 millions of dollars.

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 LLC (“EPO”). We are owned 98% by our limited partners and 2% by Enterprise Products GP, LLC (our general partner, referred to as “EPGP”). EPGP is owned 100% by Enterprise GP Holdings L.P. (“Enterprise GP Holdings”), a publicly traded limited partnership, 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, all of the membership interests of which are owned by Dan L. Duncan. We, EPGP, Enterprise GP Holdings, EPE Holdings and Dan Duncan LLC are affiliates and under the common control of Dan L. Duncan, the Group Co-Chairman and controlling shareholder of EPCO.

References to “TEPPCO” mean TEPPCO Partners, L.P., a publicly traded limited partnership, the common 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 Enterprise GP Holdings.

References to “Energy Transfer Equity” mean the business and operations of Energy Transfer Equity, L.P. and its consolidated subsidiaries. References to “LE GP” mean LE GP, LLC, which is the general partner of Energy Transfer Equity. Enterprise GP Holdings owns a noncontrolling interest in both LE GP and Energy Transfer Equity. Enterprise GP Holdings accounts for its investments in LE GP and Energy Transfer Equity using the equity method of accounting.

References to “Employee Partnerships” mean EPE Unit L.P. (“EPE Unit I”), EPE Unit II, L.P. (“EPE Unit II”), EPE Unit III, L.P. (“EPE Unit III”), Enterprise Unit L.P. (“Enterprise Unit”) and EPCO Unit L.P. (“EPCO Unit”), collectively, all of which are privately-held affiliates of EPCO.

For financial reporting purposes, we consolidate the financial statements of Duncan Energy Partners L.P. (“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, DEP Holdings, LLC (“DEP GP”). 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 noncontrolling interest in our consolidated financial statements. The borrowings of Duncan Energy Partners are presented as part of our consolidated debt; however, neither Enterprise Products Partners L.P. nor EPO have any obligation for the payment of interest or repayment of borrowings incurred by Duncan Energy Partners.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Basis of Presentation

Effective January 1, 2009, we adopted the provisions of Statement of Financial Accounting Standards (“SFAS”) 160, Noncontrolling Interests in Consolidated Financial Statements. SFAS 160 established accounting and reporting standards for noncontrolling interests, which were previously identified as minority interest in our financial statements. This new standard requires, among other things, that (i) noncontrolling interests be presented as a component of equity on our consolidated balance sheet (i.e., elimination of the “mezzanine” presentation previously used for minority interest); (ii) elimination of minority interest amounts as a deduction in deriving net income or loss and, as a result, that net income or loss be allocated between controlling and noncontrolling interests; and (iii) comprehensive income or loss to be allocated between controlling and noncontrolling interest. Earnings per unit amounts are not affected by these changes. See Note 10 for additional information regarding noncontrolling interest.

The consolidated financial statements included in this Quarterly Report on Form 10-Q have been retrospectively adjusted to reflect the changes required by SFAS 160. As a result, net income reported for the first quarter of 2008 in these financial statements is higher than that disclosed previously; however, the allocation of such net income results in our unitholders, general partner and noncontrolling interests (i.e., the former minority interest) receiving the same amounts as they did previously.

Our results of operations for the three months ended March 31, 2009 are not necessarily indicative of results expected for the full year.

Essentially all of our assets, liabilities, revenues and expenses are recorded at EPO’s level in our consolidated financial statements. Enterprise Products Partners L.P. acts as guarantor of certain of EPO’s debt obligations. See Note 17 for condensed consolidated financial information of EPO.

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 U.S. generally accepted accounting principles (“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 and notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2008 (Commission File No. 1-14323).

Note 2. General Accounting Matters

Estimates

Preparing our financial statements in conformity with GAAP requires management to make estimates and assumptions that affect amounts presented in the financial statements (i.e. assets, liabilities, revenue and expenses) and disclosures about contingent assets and liabilities. 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.

Recent Accounting Developments

The following information summarizes recently issued accounting guidance since those reported in our Annual Report on Form 10-K for the year ended December 31, 2008 that will or may affect our future financial statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

In April 2009, the Financial Accounting Standards Board (“FASB”) issued new guidance in the form of FASB Staff Positions (“FSPs”) in an effort to clarify certain fair value accounting rules. FSP Financial Accounting Standard (“FAS”) 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly, establishes a process to determine whether a market is not active and a transaction is not distressed. FSP FAS 157-4 states that companies should look at several factors and use judgment to ascertain if a formerly active market has become inactive. When estimating fair value, FSP FAS 157-4 requires companies to place more weight on observable transactions determined to be orderly and less weight on transactions for which there is insufficient information to determine whether the transaction is orderly (entities do not have to incur undue cost and effort in making this determination). The FASB also issued FSP FAS 107-1 and APB 28-1, Interim Disclosures About Fair Value of Financial Instruments. This FSP requires that companies provide qualitative and quantitative information about fair value estimates for all financial instruments not measured on the balance sheet at fair value in each interim report. Previously, this was only an annual requirement. We will adopt these FSPs effective July 1, 2009. We do not expect that this new guidance will have a material impact on our financial statements.

Restricted Cash

Restricted cash represents amounts held in connection with our commodity derivative instruments portfolio and New York Mercantile Exchange (“NYMEX”) physical natural gas purchases. Additional cash may be restricted to maintain our positions as commodity prices fluctuate or deposit requirements change. At March 31, 2009 and December 31, 2008, our restricted cash amounts were $244.5 million and $203.8 million, respectively. See Note 4 for additional information regarding derivative instruments and hedging activities.

Note 3. Accounting for Equity Awards

We account for equity awards in accordance with SFAS 123(R), Share-Based Payment. Such awards were not material to our consolidated financial position, results of operation or cash flows for all periods presented. The amount of equity-based compensation allocable to our businesses was $2.9 million and $2.8 million for the three months ended March 31, 2009 and 2008, respectively.

Certain key employees of EPCO participate in long-term incentive compensation plans managed by EPCO. The compensation expense we record related to equity awards is based on an allocation of the total cost of such incentive plans to EPCO. We record our pro rata share of such costs based on the percentage of time each employee spends on our consolidated business activities.

EPCO 1998 Long-Term Incentive Plan

The EPCO 1998 Long-Term Incentive Plan (“EPCO 1998 Plan”) provides for the issuance of up to 7,000,000 of our common units. After giving effect to the issuance or forfeiture of option awards and restricted unit awards through March 31, 2009, a total of 1,273,924 additional common units could be issued under the EPCO 1998 Plan.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unit option awards. The following table presents option activity under the EPCO 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, 2008		2,168,500		$	26.32
Granted (2)		30,000			20.08
Exercised		(10,000	)		9.00
Forfeited		(365,000	)		26.38
Outstanding at March 31, 2009		1,823,500			26.30		5.0	$	0.7
Options exercisable at
March 31, 2009		418,500			21.14		4.1	$	0.7

(1) Aggregate intrinsic value reflects fully vested unit options at March 31, 2009. (2) Aggregate grant date fair value of these unit options issued during 2009 was $0.2 million based on the following assumptions: (i) a grant date market price of our common units of $20.08 per unit; (ii) expected life of options of 5.0 years; (iii) risk-free interest rate of 1.8%; (iv) expected distribution yield on our common units of 10%; and (v) expected unit price volatility on our common units of 72.8%.

The total intrinsic value of option awards exercised during each of the three months ended March 31, 2009 and 2008 was $0.1 million. At March 31, 2009, the estimated total unrecognized compensation cost related to nonvested unit option awards granted under the EPCO 1998 Plan was $1.5 million. We expect to recognize this cost over a weighted-average period of 2.2 years. We will recognize our share of these costs in accordance with the EPCO administrative services agreement (the “ASA”) (see Note 12).

During the three months ended March 31, 2009 and 2008, we received cash of $0.1 million and $0.3 million, respectively, from the exercise of option awards granted under the EPCO 1998 Plan. Conversely, our option-related reimbursements to EPCO during each of these periods were $0.1 million.

Restricted unit awards. The following table summarizes information regarding our restricted unit awards under the EPCO 1998 Plan for the periods indicated:

				Weighted-
				Average Grant
	Number of			Date Fair Value
	Units			per Unit (1)
Restricted units at December 31, 2008		2,080,600
Granted (2)		19,000		$	17.99
Vested		(11,000	)		26.95
Forfeited		(136,200	)		29.37
Restricted units at March 31, 2009		1,952,400

(1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. The weighted-average grant date fair value per unit for forfeited and vested awards is determined before an allowance for forfeitures. (2) Aggregate grant date fair value of restricted unit awards issued during 2009 was $0.3 million based on grant date market prices of our common units ranging from $20.08 to $22.06 per unit and an estimated forfeiture rate ranging between 4.6% and 17%.

The total fair value of restricted unit awards that vested during the three months ended March 31, 2009 was $0.3 million. At March 31, 2009, the estimated total unrecognized compensation cost related to nonvested restricted unit awards granted under the EPCO 1998 Plan was $30.1 million, which we expect to recognize over a weighted-average period of 2.1 years. We will recognize our share of such costs in accordance with the ASA.

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Phantom unit awards and distribution equivalent rights. No phantom unit awards or distribution equivalent rights have been issued as of March 31, 2009 under the EPCO 1998 Plan.

Enterprise Products 2008 Long-Term Incentive Plan

The Enterprise Products 2008 Long-Term Incentive Plan (“EPD 2008 LTIP”) provides for the issuance of up to 10,000,000 of our common units. After giving effect to the issuance or forfeiture of option awards through March 31, 2009, a total of 8,600,000 additional common units could be issued under the EPD 2008 LTIP.

Unit option awards. The following table presents unit option activity under the EPD 2008 LTIP for the periods indicated:

						Weighted-
				Weighted-		Average
				Average		Remaining
	Number of			Strike Price		Contractual
	Units			(dollars/unit)		Term (in years)
Outstanding at December 31, 2008		795,000		$	30.93
Granted (1)		695,000			22.06
Forfeited		(90,000	)		30.93
Outstanding at March 31, 2009		1,400,000			26.53		5.3

(1) Aggregate grant date fair value of these unit options issued during 2009 was $3.8 million based on the following assumptions: (i) a grant date market price of our common units of $22.06 per unit; (ii) expected life of options of 5.0 years; (iii) risk-free interest rate of 1.8%; (iv) expected distribution yield on our common units of 10%; (v) expected unit price volatility on our common units of 72%; and (vi) an estimated forfeiture rate of 17%.

At March 31, 2009, the estimated total unrecognized compensation cost related to nonvested unit option awards granted under the EPD 2008 LTIP was $4.8 million. We expect to recognize our share of this cost over a weighted-average period of 3.7 years in accordance with the ASA.

Phantom unit awards. There were a total of 4,400 phantom units outstanding at March 31, 2009 under the EPD 2008 LTIP. These awards cliff vest in 2011. At March 31, 2009 and December 31, 2008, we had an immaterial amount of accrued liability for compensation related to these phantom unit awards.

Employee Partnerships

As of March 31, 2009, the estimated combined unrecognized compensation cost related to the five Employee Partnerships was $42.2 million. We will recognize our share of these costs in accordance with the ASA over a weighted-average period of 4.7 years.

DEP GP Unit Appreciation Rights

At March 31, 2009 and December 31, 2008, we had a total of 90,000 outstanding unit appreciation rights (“UARs”) granted to non-employee directors of DEP GP that cliff vest in 2012. If a director resigns prior to vesting, his UAR awards are forfeited. At March 31, 2009 and December 31, 2008, we had an immaterial amount of accrued liability for compensation related to these UARs.

Note 4. Derivative Instruments and Hedging Activities

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interest rates, commodity prices or currency values. Typical derivative instruments include futures, forward contracts, swaps and other instruments with similar characteristics. Substantially all of our derivatives are used for non-trading activities.

SFAS 133, Accounting for Derivative Instruments and Hedging Activities, requires companies to recognize derivative instruments at fair value as either assets or liabilities on the balance sheet. While the standard requires that all derivatives be reported at fair value on the balance sheet, changes in fair value of the derivative instruments will be reported in different ways depending on the nature and effectiveness of the hedging activities to which they are related. After meeting specified conditions, a qualified derivative may be specifically designated as a total or partial hedge of:

§	Changes in the fair value of a recognized asset or liability, or an unrecognized firm commitment - In a fair value hedge, all gains and losses (of both the derivative instrument and the hedged item) are recognized in income during the period of change.

§	Variable cash flows of a forecasted transaction - In a cash flow hedge, the effective portion of the hedge is reported in other comprehensive income and is reclassified into earnings when the forecasted transaction affects earnings.

§	Foreign currency exposure, such as through an unrecognized firm commitment.

An effective hedge is one in which the change in fair value of a derivative instrument can be expected to offset 80% to 125% of changes in the fair value of a hedged item at inception and throughout the life of the hedging relationship. The effective portion of a hedge is the amount by which the derivative instrument exactly offsets the change in fair value of the hedged item during the reporting period. Conversely, ineffectiveness represents the change in the fair value of the derivative instrument that does not exactly offset the change in the fair value of the hedged item. Any ineffectiveness associated with a hedge is recognized in earnings immediately. Ineffectiveness can be caused by, among other things, changes in the timing of forecasted transactions or a mismatch of terms between the derivative instrument and the hedged item.

On January 1, 2009, we adopted the disclosure requirements of SFAS 161, Disclosures About Derivative Financial Instruments and Hedging Activities. SFAS 161 requires enhanced qualitative and quantitative disclosure requirements regarding derivative instruments. This footnote reflects the new disclosure standard.

Interest Rate Derivative Instruments

We utilize interest rate swaps, treasury locks and similar derivative instruments to manage our exposure to changes in the interest rates of certain consolidated debt agreements. This strategy is a component in controlling our cost of capital associated with such borrowings.

The following table summarizes our interest rate derivative instruments outstanding at March 31, 2009, all of which were designated as hedging instruments under SFAS 133:

	Number and Type of	Notional	Period of	Rate	Accounting
Hedged Transaction	Derivative Employed	Amount	Hedge	Swap	Treatment
Enterprise Products Partners:
Senior Notes C	1 fixed-to-floating swap	$100.0	1/04 to 2/13	6.4% to 3.5%	Fair value hedge
Senior Notes G	3 fixed-to-floating swaps	$300.0	10/04 to 10/14	5.6% to 5.3%	Fair value hedge
Duncan Energy Partners:
Variable-interest rate borrowings	3 floating-to-fixed swaps	$175.0	9/07 to 9/10	1.2% to 4.6%	Cash flow hedge

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At times, we may use treasury lock derivative instruments to hedge the underlying U.S. treasury rates related to forecasted issuances of debt. As cash flow hedges, gains or losses on these instruments are recorded in other comprehensive income and amortized to earnings using the effective interest method over the estimated term of the underlying fixed-rate debt. During March 2008, we terminated treasury locks having a combined notional value of $350.0 million and recognized an aggregate loss of $20.7 million loss in other comprehensive income during the first quarter of 2008.

In the first quarter of 2009, we entered into two forward starting interest rate swaps to hedge the underlying benchmark interest payments related to the forecasted issuances of debt.

	Number and Type of	Notional	Period of	Average Rate	Accounting
Hedged Transaction	Derivative Employed	Amount	Hedge	Locked	Treatment
Enterprise Products Partners:
Future debt offering	1 forward starting swap	$50.0	6/10 to 6/20	3.293%	Cash flow hedge
Future debt offering	1 forward starting swap	$150.0	2/11 to 2/21	3.4615%	Cash flow hedge

For information regarding consolidated fair value amounts and gains and losses on interest rate derivative instruments and related hedged items, see “Tabular Presentation of Fair Value Amounts, and Gains and Losses on Derivative Instruments and Related Hedged Items” within this Note 4.

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Commodity Derivative Instruments

The prices of natural gas, NGLs and certain petrochemical products are subject to fluctuations in response to changes in supply, demand, general market uncertainty and a variety of additional factors that are beyond our control. In order to manage the price risk associated with such products, we enter into commodity derivative instruments such as forwards, basis swaps and futures contracts. The following table summarizes our commodity derivative instruments outstanding at March 31, 2009:

	Volume (1)		Accounting
Derivative Purpose	Current	Long-Term (2)	Treatment
Derivatives designated as hedging instruments under SFAS 133:
Enterprise Products Partners:
Natural gas processing:
Forecasted natural gas purchases for plant thermal reduction (“PTR”) (3)	44.0 Bcf	n/a	Cash flow hedge
Forecasted NGL sales	3.2 MMBbls	n/a	Cash flow hedge
Octane enhancement:
Forecasted purchases of natural gas liquids	0.2 MMBbls	n/a	Cash flow hedge
Natural gas liquids inventory management activities	n/a	0.1 MMBbls	Cash flow hedge
Forecasted sales of octane enhancement products	1.7 MMBbls	n/a	Cash flow hedge
Natural gas marketing:
Natural gas storage inventory management activities	2.3 Bcf	n/a	Fair value hedge
NGL marketing:
Forecasted purchases of NGLs and related hydrocarbon products	3.1 MMBbls	n/a	Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products	2.5 MMBbls	1.2 MMBbls	Cash flow hedge

Derivatives not designated as hedging instruments under SFAS 133:
Enterprise Products Partners:
Natural gas risk management activities (4,5)	244.1 Bcf	n/a	Mark-to-market
Duncan Energy Partners:
Natural gas risk management activities (5)	1.8 Bcf	n/a	Mark-to-market
(1) Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflect the absolute value of derivative notional volumes. (2) The maximum term for derivatives reflected in the long-term column is December 2010. (3) PTR represents the British thermal unit (“Btu”) equivalent of the NGLs extracted from natural gas by a processing plant, and includes the natural gas used as plant fuel to extract those liquids, plant flare and other shortages. See the discussion below for the primary objective of this strategy. (4) Volume includes approximately 63.7 billion cubic feet (“Bcf”) of physical derivative instruments that are predominantly index plus a premium or minus a discount. (5) Reflects the use of derivative instruments to manage risks associated with natural gas pipeline, processing and storage assets.

The table above does not include additional hedges of forecasted NGL sales executed under contracts that have been designated as normal purchase and sale agreements under SFAS 133. At March 31, 2009, the volume hedged under these contracts was 11.7 million barrels (“MMBbls”).

Certain of our derivative instruments do not meet the hedge accounting requirements of SFAS 133 and are accounted for as economic hedges using mark-to-market accounting.

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Our predominant hedging strategy is a program to hedge a portion of our margin from natural gas processing. The objective of this strategy is to hedge a level of gross margins associated with the NGL forward sales contracts (i.e., NGL sales revenues less actual costs for PTR and the gain or loss on the PTR hedge) by locking in the cost of natural gas used for PTR through the use of commodity derivative instruments. This program consists of:

§	the forward sale of a portion of our expected equity NGL production at fixed prices through 2009, and

§	the purchase, using commodity derivative instruments, of the amount of natural gas expected to be consumed as PTR in the production of such equity NGL production.

At March 31, 2009, this program had hedged future estimated gross margins (before plant operating expenses) of $347.7 million on 14.9 MMBbls of forecasted NGL forward sales transactions extending through 2009.

For information regarding consolidated fair value amounts and gains and losses on commodity derivative instruments and related hedged items, see “Tabular Presentation of Fair Value Amounts, and Gains and Losses on Derivative Instruments and Related Hedged Items” within this Note 4.

Foreign Currency Derivative Instruments

We are exposed to foreign currency exchange risk in connection with our NGL marketing activities in Canada. As a result, we could be adversely affected by fluctuations in currency rates between the U.S. dollar and Canadian dollar. In order to manage this risk, we may enter into foreign exchange purchase contracts to lock in the exchange rate. Prior to 2009, these derivative instruments were accounted for using mark-to-market accounting. Beginning with the first quarter of 2009, these transactions were accounted for as cash flow hedges.

In addition, we were exposed to foreign currency exchange risk in connection with a term loan denominated in Japanese yen (see Note 9). We entered into this loan agreement in November 2008 and the loan matured in March 2009. The derivative instrument used to hedge this risk was accounted for as a cash flow hedge and settled upon repayment of the loan.

We had one foreign currency derivative instrument with a notional amount of $1.7 million Canadian outstanding at March 31, 2009. The fair market value of this instrument was de minimis at March 31, 2009.

For information regarding consolidated fair value amounts and gains and losses on foreign currency derivative instruments and related hedged items, see “Tabular Presentation of Fair Value Amounts, and Gains and Losses on Derivative Instruments and Related Hedged Items” within this Note 4.

Credit-Risk Related Contingent Features in Derivative Instruments

A limited number of our commodity derivative instruments include provisions related to credit ratings and/or adequate assurance clauses. A credit rating provision provides for a counterparty to demand immediate full or partial payment to cover a net liability position upon the loss of a stipulated credit rating. An adequate assurance clause provides for a counterparty to demand immediate full or partial payment to cover a net liability position should reasonable grounds for insecurity arise with respect to contractual performance by either party. At March 31, 2009, the aggregate fair value of our over-the-counter derivative instruments in a net liability position was $0.1 million however this position was not subject to credit rating contingent features or adequate assurance clauses. The potential for derivatives with contingent features to enter a net liability position may change in the future as positions and prices fluctuate.

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Tabular Presentation of Fair Value Amounts, and Gains and Losses on

Derivative Instruments and Related Hedged Items

The following table provides a balance sheet overview of our derivative assets and liabilities at the dates indicated:

	Asset Derivatives						Liability Derivatives
	March 31, 2009			December 31, 2008			March 31, 2009			December 31, 2008
	Balance Sheet	Fair		Balance Sheet	Fair		Balance Sheet	Fair		Balance Sheet	Fair
	Location	Value		Location	Value		Location	Value		Location	Value
Derivatives designated as hedging instruments under SFAS 133
Interest rate derivatives	Derivative assets	$	7.0	Derivative assets	$	7.8	Derivative liabilities	$	4.6	Derivative liabilities	$	5.9
Interest rate derivatives	Other assets		38.5	Other assets		39.0	Other liabilities		4.5	Other liabilities		3.9
Total interest rate derivatives			45.5			46.8			9.1			9.8
Commodity derivatives	Derivative assets		152.2	Derivative assets		150.5	Derivative liabilities		263.2	Derivative liabilities		253.5
Commodity derivatives	Other assets		2.3	Other assets		--	Other liabilities		--	Other liabilities		0.2
Total commodity derivatives (1)			154.5			150.5			263.2			253.7
Foreign currency derivatives (2)	Derivative assets		--	Derivative assets		9.3	Derivative liabilities		--	Derivative liabilities		--
Total derivatives designated as hedging instruments		$	200.0		$	206.6		$	272.3		$	263.5

Derivatives not designated as hedging instruments under SFAS 133
Commodity derivatives	Derivative assets	$	82.1	Derivative assets	$	35.2	Derivative liabilities	$	71.2	Derivative liabilities	$	27.7
Commodity derivatives	Other assets		--	Other assets		--	Other liabilities		0.3	Other liabilities		--
Total commodity derivatives			82.1			35.2			71.5			27.7
Foreign currency derivatives	Derivative assets		--	Derivative assets		--	Derivative liabilities		--	Derivative liabilities		0.1
Total derivatives not designated as hedging instruments		$	82.1		$	35.2		$	71.5		$	27.8

(1) Represent commodity derivative instrument transactions that either have not settled or have settled and not been invoiced. Settled and invoiced transactions are reflected in either accounts receivable or accounts payable depending on the outcome of the transaction. (2) Relates to the hedging of our exposure to fluctuations in the foreign currency exchange rate related to our Canadian NGL marketing subsidiary.

The following table presents the effect of our derivative instruments designated as fair value hedges under SFAS 133 on our condensed consolidated statements of operations for the periods presented:

Derivatives in SFAS 133	Gain Recognized in					Gain/(Loss) Recognized in
Fair Value	Income on Derivative					Income on Hedged Item
Hedging Relationships	Amount				Location	Amount						Location
	For the Three Months					For the Three Months
	Ended March 31,					Ended March 31,
	2009		2008			2009			2008
Interest rate derivatives	$	45.5	$	47.5	Interest expense	$	(44.8	)	$	(48.3	)	Interest expense
Commodity derivatives		0.3		--	Revenue		0.1			--		Revenue
Total	$	45.8	$	47.5		$	(44.7	)	$	(48.3	)

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	Change in Value
Derivatives	Recognized in OCI on
in SFAS 133 Cash Flow	Derivative
Hedging Relationships	(Effective Portion)
	For the Three Months
	Ended March 31,
	2009			2008
Interest rate derivatives	$	(0.7	)	$	(26.0	)
Commodity derivatives – Revenue		(10.0	)		7.0
Commodity derivatives – Operating costs and expenses		(52.0	)		81.8
Foreign currency derivatives		(10.6	)		(1.2	)
Total	$	(73.3	)	$	61.6

		Amount of Gain/(Loss)
Derivatives	Location of Gain/(Loss)	Reclassified from AOCI
in SFAS 133 Cash Flow	Reclassified from AOCI	to Income
Hedging Relationships	into Income (Effective Portion)	(Effective Portion)
		For the Three Months
		Ended March 31,
		2009			2008
Interest rate derivatives	Interest expense	$	(0.9	)	$	1.6
Commodity derivatives	Revenue		15.3			(3.0	)
Commodity derivatives	Operating costs and expenses		(47.5	)		(1.2	)
Total		$	(33.1	)	$	(2.6	)

	Location of Gain/(Loss)	Amount of Gain/(Loss)
Derivatives	Recognized in Income	Recognized in Income on
in SFAS 133 Cash Flow	on Ineffective Portion	Ineffective Portion of
Hedging Relationships	of Derivative	Derivative
		For the Three Months
		Ended March 31,
		2009			2008
Commodity derivatives	Revenue	$	--		$	0.5
Commodity derivatives	Operating costs and expenses		(1.1	)		2.3
Total		$	(1.1	)	$	2.8

Over the next twelve months, we expect to reclassify $3.4 million of accumulated other comprehensive loss attributable to interest rate derivative instruments to earnings as an increase to interest expense. Likewise, we expect to reclassify $184.9 million of accumulated other comprehensive loss attributable to commodity derivative instruments to earnings as an increase in operating costs and expenses and $38.8 million as an increase in revenues.

The following table presents the effect of our derivative instruments not designated as hedging instruments under SFAS 133 on our condensed consolidated statements of operations for the periods presented:

Derivatives Not	Gain/(Loss) Recognized in
Designated as SFAS 133	Income on Derivative
Hedging Instruments	Amount						Location
	For the Three Months
	Ended March 31,
	2009			2008
Commodity derivatives	$	24.3		$	(1.6	)	Revenue
Commodity derivatives		--			(0.8	)	Operating costs and expenses
Foreign currency derivatives		(0.1	)		--		Other, net
Total	$	24.2		$	(2.4	)

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FAS 157 – Fair Value Measurements

SFAS 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities measured on a recurring basis at March 31, 2009. These financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Level 1		Level 2		Level 3		Total
Financial assets:
Interest rate derivative instruments	$	--	$	45.5	$	--	$	45.5
Commodity derivative instruments		20.5		179.0		37.1		236.6
Total	$	20.5	$	224.5	$	37.1	$	282.1

Financial liabilities:
Interest rate derivative instruments	$	--	$	9.1	$	--	$	9.1
Commodity derivative instruments		29.2		302.5		3.0		334.7
Total	$	29.2	$	311.6	$	3.0	$	343.8

The following table sets forth a reconciliation of changes in the fair value of our Level 3 financial assets and liabilities for the periods presented:

	For the Three Months
	Ended March 31,
	2009			2008
Balance, January 1	$	32.6		$	(4.6	)
Total gains (losses) included in:
Net income (1)		12.5			(2.3	)
Other comprehensive income (loss)		1.5			2.4
Purchases, issuances, settlements		(12.5	)		1.9
Balance, March 31	$	34.1		$	(2.6	)

(1) There were $0.2 million and $0.4 million of unrealized losses included in these amounts for the three months ended March 31, 2009 and 2008, respectively.

We adopted the provisions of SFAS 157 that apply to nonfinancial assets and liabilities on January 1, 2009. Our adoption of this guidance had no impact on our financial position, results of operations or cash flows.

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Note 5. Inventories

Our inventory amounts were as follows at the dates indicated:

	March 31,		December 31,
	2009		2008
Working inventory (1)	$	279.5	$	200.4
Forward sales inventory (2)		240.5		162.4
Total inventory	$	520.0	$	362.8

(1) Working inventory is comprised of inventories of natural gas, NGLs and certain petrochemical products that are either available-for-sale or used in providing services. (2) Forward sales inventory consists of identified NGL and natural gas volumes dedicated to the fulfillment of forward sales contracts.

Our inventory values reflect payments for product purchases, freight charges associated with such purchase volumes, terminal and storage fees, vessel inspection costs, demurrage charges and other related costs. We value our inventories at the lower of average cost or market.

Operating costs and expenses, as presented on our Unaudited Condensed Statements of Consolidated Operations, include cost of sales amounts related to the sale of inventories. Our costs of sales were $2.63 billion and $4.90 billion for the three months ended March 31, 2009 and 2008, 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, 2009 and 2008, we recognized LCM adjustments of approximately $5.7 million and $4.2 million, respectively.

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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		2009		2008
Plants and pipelines (1)		3-45(5)	$	13,544.7	$	12,296.3
Underground and other storage facilities (2)		5-35(6)		925.1		900.7
Platforms and facilities (3)		20-31		634.8		634.8
Transportation equipment (4)		3-10		38.3		38.7
Land				58.7		54.6
Construction in progress				792.0		1,604.7
Total				15,993.6		15,529.8
Less accumulated depreciation				2,487.9		2,375.0
Property, plant and equipment, net			$	13,505.7	$	13,154.8

(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, 18-45 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).

The following table summarizes our depreciation expense and capitalized interest amounts for the periods indicated:

	For the Three Months
	Ended March 31,
	2009		2008
Depreciation expense (1)	$	125.0	$	109.8
Capitalized interest (2)		12.1		18.1

(1) Depreciation expense is a component of costs and expenses as presented in our Unaudited Condensed Statements of Consolidated Operations. (2) Capitalized interest increases the carrying value of the associated asset and reduces interest expense during the period it is recorded.

Asset Retirement Obligations

Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of certain tangible long-lived assets that result from acquisitions, construction, development and/or normal operations. The following table presents information regarding our AROs since December 31, 2008.

ARO liability balance, December 31, 2008	$	37.7
Liabilities incurred		0.4
Liabilities settled		(6.5	)
Revisions in estimated cash flows		6.0
Accretion expense		0.5
ARO liability balance, March 31, 2009	$	38.1

Property, plant and equipment at March 31, 2009 and December 31, 2008 includes $10.1 million and $9.9 million, respectively, of asset retirement costs capitalized as an increase in the associated long-lived asset.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 shows our investments in and advances to unconsolidated affiliates at the dates indicated.

	Ownership
	Percentage at
	March 31,		March 31,		December 31,
	2009		2009		2008
NGL Pipelines & Services:
Venice Energy Service Company, L.L.C.		13.1%	$	31.1	$	37.7
K/D/S Promix, L.L.C. (“Promix”)		50%		46.6		46.4
Baton Rouge Fractionators LLC		32.2%		24.6		24.1
Skelly-Belvieu Pipeline Company, L.L.C.		49%		36.3		36.0
Onshore Natural Gas Pipelines & Services:
Jonah Gas Gathering Company (“Jonah”)		19.4%		252.6		258.1
Evangeline (1)		49.5%		4.8		4.5
White River Hub, LLC		50%		26.8		21.4
Offshore Pipelines & Services:
Poseidon Oil Pipeline, L.L.C. (“Poseidon”)		36%		58.2		60.2
Cameron Highway Oil Pipeline Company (“Cameron Highway”)		50%		249.1		250.8
Deepwater Gateway, L.L.C.		50%		103.0		104.8
Neptune Pipeline Company, L.L.C. (“Neptune”)		25.7%		51.1		52.7
Nemo Gathering Company, LLC		33.9%		--		0.4
Texas Offshore Port System (2)		33.3%		35.2		35.9
Petrochemical Services:
Baton Rouge Propylene Concentrator, LLC		30%		12.5		12.6
La Porte (3)		50%		3.7		3.9
Total			$	935.6	$	949.5

(1) Refers to our ownership interests in Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp., collectively. (2) Balance at March 31, 2009 includes $1.1 million in receivables related to construction activities performed on behalf of the Texas Offshore Port System. We expect the Texas Offshore Port System to remit payment for these predissociation matters. See Note 18 for a subsequent event regarding the Texas Offshore Port System. (3) Refers to our ownership interests in La Porte Pipeline Company, L.P. and La Porte GP, LLC, collectively.

Our investments in Promix, La Porte, Neptune, Poseidon, Cameron Highway and Jonah included excess cost amounts totaling $43.2 million and $43.7 million at March 31, 2009 and December 31, 2008, respectively, all of which were attributable to the fair value of the underlying tangible assets of these entities exceeding their book carrying values at the time of our acquisition of interests in these entities. To the extent that we attribute all or a portion of an excess cost amount to higher fair values, we amortize such excess cost as a reduction in equity earnings in a manner similar to depreciation. To the extent we attribute an excess cost amount to goodwill, we do not amortize this amount but it is subject to evaluation for impairment. Amortization of such excess cost amounts was $0.5 million for each of the three months ended March 31, 2009 and 2008.

The following table presents our equity in earnings of unconsolidated affiliates for the periods indicated:

	For the Three Months
	Ended March 31,
	2009		2008
NGL Pipelines & Services	$	1.2	$	(2.3	)
Onshore Natural Gas Pipelines & Services		7.2		5.8
Offshore Pipelines & Services		4.7		10.7
Petrochemical Services		0.3		0.4
Total	$	13.4	$	14.6

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

On a quarterly basis, we monitor the underlying business fundamentals of our investments in unconsolidated affiliates and test such investments for impairment when impairment indicators are present. As a result of our reviews for the first quarter of 2009, no impairment charges were required. We have the intent and ability to hold these investments, which are integral to our operations.

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, 2009						March 31, 2008
			Operating		Net				Operating			Net
	Revenues		Income		Income		Revenues		Income (Loss)			Income
NGL Pipelines & Services	$	55.6	$	5.0	$	5.1	$	68.6	$	(0.1	)	$	0.1
Onshore Natural Gas Pipelines & Services		97.7		34.0		34.2		117.6		31.0			29.7
Offshore Pipelines & Services		29.4		1.1		0.5		43.2		26.3			25.3
Petrochemical Services		4.7		1.3		1.3		5.4		1.5			1.5

Note 8. Intangible Assets and Goodwill

Identifiable Intangible Assets

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

	March 31, 2009							December 31, 2008
	Gross		Accum.			Carrying		Gross		Accum.			Carrying
	Value		Amort.			Value		Value		Amort.			Value
NGL Pipelines & Services	$	537.3	$	(195.4	)	$	341.9	$	537.1	$	(186.1	)	$	351.0
Onshore Natural Gas Pipelines & Services		473.3		(147.4	)		325.9		473.3		(139.8	)		333.5
Offshore Pipelines & Services		207.0		(94.7	)		112.3		207.0		(90.8	)		116.2
Petrochemical Services		67.9		(13.6	)		54.3		67.9		(13.2	)		54.7
Total	$	1,285.5	$	(451.1	)	$	834.4	$	1,285.3	$	(429.9	)	$	855.4

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

	For the Three Months
	Ended March 31,
	2009		2008
NGL Pipelines & Services	$	9.3	$	10.1
Onshore Natural Gas Pipelines & Services		7.6		7.8
Offshore Pipelines & Services		3.9		4.4
Petrochemical Services		0.4		0.5
Total	$	21.2	$	22.8

For the remainder of 2009, amortization expense associated with our intangible assets is currently estimated at $61.6 million.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Goodwill

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

	March 31,		December 31,
	2009		2008

NGL Pipelines & Services	$	269.0	$	269.0
Onshore Natural Gas Pipelines & Services		282.1		282.1
Offshore Pipelines & Services		82.1		82.1
Petrochemical Services		73.7		73.7
Total	$	706.9	$	706.9

Note 9. Debt Obligations

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

	March 31,			December 31,
	2009			2008
EPO senior debt obligations:
Multi-Year Revolving Credit Facility, variable rate, due November 2012	$	1,234.1		$	800.0
Pascagoula MBFC Loan, 8.70% fixed-rate, due March 2010 (1)		54.0			54.0
Petal GO Zone Bonds, variable rate, due August 2037		57.5			57.5
Yen Term Loan, 4.93% fixed-rate, due March 2009 (2)		--			217.6
Senior Notes B, 7.50% fixed-rate, due February 2011		450.0			450.0
Senior Notes C, 6.375% fixed-rate, due February 2013		350.0			350.0
Senior Notes D, 6.875% fixed-rate, due March 2033		500.0			500.0
Senior Notes F, 4.625% fixed-rate, due October 2009 (1)		500.0			500.0
Senior Notes G, 5.60% fixed-rate, due October 2014		650.0			650.0
Senior Notes H, 6.65% fixed-rate, due October 2034		350.0			350.0
Senior Notes I, 5.00% fixed-rate, due March 2015		250.0			250.0
Senior Notes J, 5.75% fixed-rate, due March 2035		250.0			250.0
Senior Notes K, 4.950% fixed-rate, due June 2010		500.0			500.0
Senior Notes L, 6.30% fixed-rate, due September 2017		800.0			800.0
Senior Notes M, 5.65% fixed-rate, due April 2013		400.0			400.0
Senior Notes N, 6.50% fixed-rate, due January 2019		700.0			700.0
Senior Notes O, 9.75% fixed-rate, due January 2014		500.0			500.0
Duncan Energy Partners’ debt obligations:
DEP Revolving Credit Facility, variable rate, due February 2011		188.0			202.0
DEP Term Loan, variable rate, due December 2011		282.3			282.3
Total principal amount of senior debt obligations		8,015.9			7,813.4
EPO Junior Subordinated Notes A, fixed/variable rate, due August 2066		550.0			550.0
EPO Junior Subordinated Notes B, fixed/variable rate, due January 2068		682.7			682.7
Total principal amount of senior and junior debt obligations		9,248.6			9,046.1
Other, non-principal amounts:
Change in fair value of debt-related derivative instruments		49.5			51.9
Unamortized discounts, net of premiums		(7.2	)		(7.3	)
Unamortized deferred net gains related to terminated interest rate swaps		16.4			17.7
Total other, non-principal amounts		58.7			62.3
Total long-term debt	$	9,307.3		$	9,108.4

(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, 2009. With respect to Senior Notes F due in October 2009 and the Pascagoula MBFC Loan due in March 2010, we have the ability to use available credit capacity under EPO’s Multi-Year Revolving Credit Facility to fund the repayment of this debt. (2) The Yen Term Loan matured on March 30, 2009 and was replaced with the $200.0 Million Term Loan (see Note 18).

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Parent-Subsidiary Guarantor Relationships

Enterprise Products Partners L.P. acts as guarantor of the consolidated debt obligations of EPO with the exception of the DEP Revolving Credit Facility and the DEP Term Loan. If EPO were to default on any of its guaranteed debt, Enterprise Products Partners L.P. would be responsible for full repayment of that obligation.

Letters of Credit

At March 31, 2009 we had $1.0 million in a standby letter of credit outstanding.

EPO’s Debt Obligations

Apart from that discussed below, there have been no significant changes in the terms of our debt obligations since those reported in our Annual Report on Form 10-K for the year ended December 31, 2008.

$200.0 Million Term Loan. On April 1, 2009, EPO entered into a $200.0 Million Term Loan, which replaced its borrowing availability under the Yen Term Loan that matured on March 30, 2009. See Note 18 for additional information regarding this subsequent event.

Dixie Revolving Credit Facility

The Dixie Revolving Credit Facility was terminated in January 2009. As of December 31, 2008, there were no debt obligations outstanding under this facility.

Covenants

We were in compliance with the covenants of our consolidated debt agreements at March 31, 2009.

Information Regarding Variable Interest Rates Paid

The following table shows the weighted-average interest rate paid on our consolidated variable-rate debt obligations during the three months ended March 31, 2009.

	Weighted-Average
	Interest Rate
	Paid
EPO’s Multi-Year Revolving Credit Facility	1.05%
DEP Revolving Credit Facility	2.05%
DEP Term Loan	1.50%
Petal GO Zone Bonds	0.56%

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.

2009	$	--
2010		500.0
2011		920.3
2012		1,788.1
2013		750.0
Thereafter		5,290.2
Total scheduled principal payments	$	9,248.6

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Debt Obligations of Unconsolidated Affiliates

We have two unconsolidated affiliates with long-term debt obligations. The following table shows (i) our ownership interest in each entity at March 31, 2009, (ii) total debt of each unconsolidated affiliate at March 31, 2009 (on a 100% basis to the affiliate) and (iii) the corresponding scheduled maturities of such debt.

	Our				Scheduled Maturities of Debt
	Ownership
	Interest		Total		2009		2010		2011
Poseidon		36%	$	98.0	$	--	$	--	$	98.0
Evangeline		49.5%		15.7		5.0		3.2		7.5
Total			$	113.7	$	5.0	$	3.2	$	105.5

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, 2009 and December 31, 2008. The credit agreements of our unconsolidated affiliates also 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.

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, 2008.

Note 10. 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, EPGP.

Equity Offerings and Registration Statements

We have a universal shelf registration statement on file with the SEC that allows us to issue an unlimited amount of debt and equity securities. In January 2009, we sold 10,590,000 common units (including an over-allotment of 990,000 common units) to the public at an offering price of $22.20 per unit under this universal shelf registration.

In addition, we have a registration statement on file related to our employee unit purchase plan (“EUPP”), under which we can issue up to 1,200,000 common units. A total of 695,618 common units have been issued to employees under this plan through March 31, 2009.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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, 2009:

	Net Proceeds from Sale of Common Units
	Number of		Contributed		Contributed by		Total
	Common Units		by Limited		General		Net
	Issued		Partners		Partner		Proceeds
January underwritten offering		10,590,000	$	225.6	$	4.6	$	230.2
February DRIP and EUPP		3,679,163		78.9		1.6		80.5
Total 2009		14,269,163	$	304.5	$	6.2	$	310.7

Net proceeds received from our underwritten offering, DRIP and EUPP were used to temporarily reduce borrowings outstanding under EPO’s Multi-Year Revolving Credit Facility and for general partnership purposes.

Summary of Changes in Outstanding Units

The following table summarizes changes in our outstanding units since December 31, 2008:

				Restricted
	Common			Common			Treasury
	Units			Units			Units
Balance, December 31, 2008		439,354,731			2,080,600			--
Common units issued in connection with underwritten offering		10,590,000			--			--
Common units issued in connection with DRIP and EUPP		3,679,163			--			--
Common units issued in connection with equity awards		4,307			--			--
Restricted units issued		--			19,000			--
Forfeiture of restricted units		--			(136,200	)		--
Conversion of restricted units to common units		11,000			(11,000	)		--
Acquisition of treasury units		(1,357	)		--			1,357
Cancellation of treasury units		--			--			(1,357	)
Balance, March 31, 2009		453,637,844			1,952,400			--

Summary of Changes in Limited Partners’ Equity

The following table details the changes in limited partners’ equity since December 31, 2008:

				Restricted
	Common			Common
	Units			Units			Total
Balance, December 31, 2008	$	6,036.9		$	26.2		$	6,063.1
Net income		185.5			0.8			186.3
Operating leases paid by EPCO		0.2			--			0.2
Cash distributions to partners		(238.5	)		(1.0	)		(239.5	)
Unit option reimbursements to EPCO		(0.1	)		--			(0.1	)
Non-cash distributions		(2.0	)		--			(2.0	)
Net proceeds from issuance of common units		304.5			--			304.5
Proceeds from exercise of unit options		0.1			--			0.1
Amortization of equity awards		2.5			2.2			4.7
Balance, March 31, 2009	$	6,289.1		$	28.2		$	6,317.3

Distributions to Partners

We paid EPGP incentive distributions of $35.2 million and $29.8 million during the three months ended March 31, 2009 and 2008, respectively.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

We paid aggregate distributions to our unitholders and general partner of $279.6 million during the three months ended March 31, 2009. These distributions pertained to the three month period ended December 31, 2008 (i.e., the fourth quarter of 2008). On May 8, 2009, we paid a quarterly cash distribution of $0.5375 per unit with respect to the first quarter of 2009, to unitholders of record at the close of business on April 30, 2009.

Accumulated Other Comprehensive Loss

The following table presents the components of accumulated other comprehensive loss at the dates indicated:

	March 31,			December 31,
	2009			2008
Commodity derivative instruments (1)	$	(143.9	)	$	(114.1	)
Interest rate derivative instruments (1)		4.0			3.8
Foreign currency derivative instruments (1)		--			10.6
Foreign currency translation adjustment (2)		(1.7	)		(1.3	)
Pension and postretirement benefit plans		(0.7	)		(0.7	)
Subtotal		(142.3	)		(101.7	)
Amount attributable to noncontrolling interest		3.9			4.5
Total accumulated other comprehensive loss in partners’ equity	$	(138.4	)	$	(97.2	)

(1) See Note 4 for additional information regarding these components of accumulated other comprehensive loss. (2) Relates to transactions of our Canadian NGL marketing subsidiary.

Noncontrolling Interest

At March 31, 2009 and December 31, 2008, noncontrolling interest includes $279.8 million and $281.1 million, respectively, attributable to third party owners of Duncan Energy Partners. Net income attributable to noncontrolling interest for the three months ended March 31, 2009 and 2008 includes $5.1 million and $4.3 million, respectively, attributable to third party owners of Duncan Energy Partners. The remaining noncontrolling interest amounts are primarily attributable to our other consolidated affiliates.

The following table presents distributions paid to noncontrolling interest as presented on our Unaudited Condensed Statements of Consolidated Cash Flows and Unaudited Condensed Statements of Consolidated Equity for the periods indicated:

	For the Three Months
	Ended March 31,
	2009		2008
Distributions paid to noncontrolling interest:
Limited partners of Duncan Energy Partners	$	6.4	$	6.1
Joint venture partners		7.7		10.0
Total distributions paid to noncontrolling interest	$	14.1	$	16.1

Distributions paid to the limited partners of Duncan Energy Partners primarily represent the quarterly cash distributions paid by this entity to its common unitholders.

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.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

		For the Three Months
		Ended March 31,
		2009			2008
Revenues (1)		$	3,423.1		$	5,684.5
Less:	Operating costs and expenses (1)		(3,041.3	)		(5,311.2	)
Add:	Equity in earnings of unconsolidated affiliates (1)		13.4			14.6
	Depreciation, amortization and accretion in operating costs and expenses (2)		153.5			133.9
	Operating lease expense paid by EPCO (2)		0.2			0.5
	Gain from asset sales and related transactions in operating costs and expenses (2)		(0.2	)		(0.1	)
Total segment gross operating margin		$	548.7		$	522.2

(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 follows:

	For the Three Months
	Ended March 31,
	2009			2008
Total segment gross operating margin	$	548.7		$	522.2
Adjustments to reconcile total segment gross operating margin
to operating income:
Depreciation, amortization and accretion in operating costs and expenses		(153.5	)		(133.9	)
Operating lease expense paid by EPCO		(0.2	)		(0.5	)
Gain from asset sales and related transactions in operating costs and expenses		0.2			0.1
General and administrative costs		(23.0	)		(21.2	)
Operating income		372.2			366.7
Other expense, net		(119.7	)		(91.0	)
Income before provision for income taxes	$	252.5		$	275.7

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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, 2009	$	2,255.3		$	600.0	$	68.3	$	255.0	$	--		$	3,178.6
Three months ended March 31, 2008		3,977.7			702.5		85.0		618.6		--			5,383.8
Revenues from related parties:
Three months ended March 31, 2009		178.5			65.8		0.2		--		--			244.5
Three months ended March 31, 2008		242.9			57.8		--		--		--			300.7
Intersegment and intrasegment revenues:
Three months ended March 31, 2009		1,356.4			148.4		0.3		97.0		(1,602.1	)		--
Three months ended March 31, 2008		1,995.5			136.0		0.4		129.8		(2,261.7	)		--
Total revenues:
Three months ended March 31, 2009		3,790.2			814.2		68.8		352.0		(1,602.1	)		3,423.1
Three months ended March 31, 2008		6,216.1			896.3		85.4		748.4		(2,261.7	)		5,684.5
Equity in earnings of unconsolidated affiliates:
Three months ended March 31, 2009		1.2			7.2		4.7		0.3		--			13.4
Three months ended March 31, 2008		(2.3	)		5.8		10.7		0.4		--			14.6
Gross operating margin by individual business segment and in total:
Three months ended March 31, 2009		342.8			116.0		61.3		28.6		--			548.7
Three months ended March 31, 2008		289.7			109.9		81.6		41.0		--			522.2
Segment assets:
At March 31, 2009		6,198.8			4,436.5		1,378.9		699.5		792.0			13,505.7
At December 31, 2008		5,424.1			4,033.3		1,394.5		698.2		1,604.7			13,154.8
Investments in and advances to unconsolidated affiliates: (see Note 7)
At March 31, 2009		138.6			284.2		496.6		16.2		--			935.6
At December 31, 2008		144.2			284.0		504.8		16.5		--			949.5
Intangible assets, net: (see Note 8)
At March 31, 2009		341.9			325.9		112.3		54.3		--			834.4
At December 31, 2008		351.0			333.5		116.2		54.7		--			855.4
Goodwill: (see Note 8)
At March 31, 2009		269.0			282.1		82.1		73.7		--			706.9
At December 31, 2008		269.0			282.1		82.1		73.7		--			706.9

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table provides additional information regarding our consolidated revenues (net of adjustments and eliminations) and expenses for the periods indicated:

	For the Three Months
	Ended March 31,
	2009			2008
NGL Pipelines & Services:
Sales of NGLs	$	2,276.0		$	4,051.2
Sales of other petroleum and related products		0.5			0.7
Midstream services		157.3			168.7
Total		2,433.8			4,220.6
Onshore Natural Gas Pipelines & Services:
Sales of natural gas		561.7			641.8
Midstream services		104.1			118.5
Total		665.8			760.3
Offshore Pipelines & Services:
Sales of natural gas		0.3			0.5
Sales of other petroleum and related products		0.2			2.6
Midstream services		68.0			81.9
Total		68.5			85.0
Petrochemical Services:
Sales of other petroleum and related products		229.5			596.3
Midstream services		25.5			22.3
Total		255.0			618.6
Total consolidated revenues	$	3,423.1		$	5,684.5

Consolidated cost and expenses:
Operating costs and expenses:
Cost of sales	$	2,630.2		$	4,901.7
Depreciation, amortization and accretion		153.5			133.9
Gain on sale of assets and related transactions		(0.2	)		(0.1	)
Other operating costs and expenses		257.8			275.7
General and administrative costs		23.0			21.2
Total consolidated costs and expenses	$	3,064.3		$	5,332.4

Changes in our revenues and operating costs and expenses period-to-period are explained in part by changes in energy commodity prices. In general, lower energy commodity prices result in a decrease in our revenues attributable to the sale of natural gas and NGLs; however, these lower commodity prices also decrease the associated cost of sales as purchase prices decline.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 12. Related Party Transactions

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

	For the Three Months
	Ended March 31,
	2009			2008
Revenues from consolidated operations:
EPCO and affiliates	$	25.1		$	18.4
Energy Transfer Equity and subsidiaries		162.8			223.1
Unconsolidated affiliates		56.6			59.2
Total	$	244.5		$	300.7
Cost of sales:
EPCO and affiliates	$	28.4		$	15.8
Energy Transfer Equity and subsidiaries		90.0			45.5
Unconsolidated affiliates		13.1			28.3
Total	$	131.5		$	89.6
Operating costs and expenses:
EPCO and affiliates	$	79.5		$	85.9
Energy Transfer Equity and subsidiaries		1.4			3.3
Unconsolidated affiliates		(2.7	)		(2.2	)
Total	$	78.2		$	87.0
General and administrative expenses:
EPCO and affiliates	$	17.8		$	17.7
Other expense:
EPCO and affiliates	$	--		$	0.3

The following table summarizes related party amounts at the dates indicated.

	March 31,		December 31,
	2009		2008
Accounts receivable - related parties:
EPCO and affiliates	$	38.5	$	26.6
Energy Transfer Equity and subsidiaries		16.5		35.0
Total	$	55.0	$	61.6

Accounts payable - related parties:
EPCO and affiliates	$	20.4	$	39.4
Energy Transfer Equity and subsidiaries		1.6		0.2
Total	$	22.0	$	39.6

We believe that the terms and provisions of our related party agreements are fair to us; however, such agreements and transactions may not be as favorable to us as we could have obtained from unaffiliated third parties.

Significant Relationships and Agreements 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 a part of our consolidated group of companies:

§	EPCO and its privately-held subsidiaries;

§	EPGP, our sole general partner;

§	Enterprise GP Holdings, which owns and controls our general partner;

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§	TEPPCO, which is owned and controlled by Enterprise GP Holdings; and

§	the Employee Partnerships.

We also have an ongoing relationship with Duncan Energy Partners, the financial statements of which are consolidated with our own financial statements. Our transactions with Duncan Energy Partners are eliminated in consolidation. A description of our relationship with Duncan Energy Partners is presented within this Note 12.

EPCO is a privately-held company controlled by Dan L. Duncan, who is also a director and Chairman of EPGP, our general partner. At March 31, 2009, EPCO and its affiliates beneficially owned 155,731,708 (or 34.2%) of our outstanding common units, which includes 13,670,925 of our common units owned by Enterprise GP Holdings. In addition, at March 31, 2009, EPCO and its affiliates beneficially owned 77.8% 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 EPGP. The principal business activity of EPGP is to act as our managing partner. The executive officers and certain of the directors of EPGP and EPE Holdings are employees of EPCO.

As our general partner, EPGP received cash distributions of $40.1 million and $34.3 million from us during the three months ended March 31, 2009 and 2008, respectively. These amounts include incentive distributions of $35.2 million and $29.8 million for the three months ended March 31, 2009 and 2008, respectively.

We and EPGP 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 privately-held 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 privately-held affiliates received from us and Enterprise GP Holdings $109.3 million and $97.4 million in cash distributions during the three months ended March 31, 2009 and 2008, respectively.

EPCO ASA. We have no employees. Substantially all of our operating functions and general and administrative support services are provided by employees of EPCO pursuant to the ASA. We, Duncan Energy Partners, Enterprise GP Holdings, TEPPCO and our respective general partners are among the parties to the ASA. Our operating costs and expenses include reimbursement payments to EPCO for the costs it incurs to operate our facilities, including compensation of EPCO’s employees to the extent that such employees spend time on our businesses. For the three months ended March 31, 2009, we reimbursed EPCO $83.1 million for operating costs and expenses and $17.8 million for general and administrative costs.

Relationship with TEPPCO

TEPPCO became a related party to us in February 2005 when its general partner was acquired by privately-held affiliates of EPCO. Our relationship was further reinforced by the acquisition of TEPPCO’s general partner by Enterprise GP Holdings in May 2007. Enterprise GP Holdings also owns our general partner.

We received $25.1 million and $18.4 million from TEPPCO during the three months ended March 31, 2009 and 2008, respectively, from the sale of hydrocarbon products. We paid TEPPCO $24.7 million and $11.3 million for NGL pipeline transportation and storage services during the three months ended March 31, 2009 and 2008, respectively.

In August 2006, we became joint venture partners with TEPPCO in Jonah. We own an approximate 19.4% interest in Jonah and TEPPCO owns the remaining 80.6% interest. Our investment in Jonah at March 31, 2009 was $252.6 million.

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In August 2008, we, together with TEPPCO and Oiltanking Holding Americas, Inc. (“Oiltanking”), announced the formation of the Texas Offshore Port System. On April 16, 2009, we, along with TEPPCO, dissociated ourselves from the Texas Offshore Port System general partnership. See Note 18 for information regarding this subsequent event.

In April 2009, we announced the proposal made in March 2009 to acquire all of the outstanding partnership interests of TEPPCO. For more information on this subsequent event, see Note 18.

Relationship with Energy Transfer Equity

In May 2007, Enterprise GP Holdings acquired equity method investments in, and therefore is a related party to, Energy Transfer Equity and its general partner. As a result, Energy Transfer Equity and its consolidated subsidiaries became related parties to our consolidated businesses.

For the three months ended March 31, 2009 and 2008, we recorded $162.8 million and $223.1 million, respectively, of revenues from Energy Transfer Partners, L.P. (“ETP”), primarily from NGL marketing activities. We incurred $91.4 million and $48.8 million for the three months ended March 31, 2009 and 2008, respectively, in costs of sales and operating costs and expenses. We have a long-term revenue generating contract with Titan Energy Partners, L.P. (“Titan”), a consolidated subsidiary of ETP. Titan purchases substantially all of its propane requirements from us. The contract continues until March 31, 2010 and contains renewal and extension options. We and Energy Transfer Company (“ETC OLP”) transport natural gas on each other’s systems and share operating expenses on certain pipelines. ETC OLP also sells natural gas to us.

Relationship with Duncan Energy Partners

Duncan Energy Partners was formed in September 2006 and did not acquire any assets prior to February 5, 2007, which was the date it completed its initial public offering of 14,950,000 common units and acquired controlling interests in five midstream energy businesses from EPO in a dropdown transaction (the “DEP I Midstream Businesses”). On December 8, 2008, through a second dropdown transaction, Duncan Energy Partners acquired controlling interests in an additional three midstream energy businesses from EPO (the “DEP II Midstream Businesses”). The business purpose of Duncan Energy Partners is to acquire, own and operate a diversified portfolio of midstream energy assets and to support the growth objectives of EPO and other affiliates under common control. Duncan Energy Partners is engaged in the business of transporting and storing NGLs and petrochemical products and gathering, transporting, storing and marketing of natural gas.

At March 31, 2009, Duncan Energy Partners was owned 99.3% by its limited partners and 0.7% by its general partner, DEP GP, which is a wholly owned subsidiary of EPO. DEP GP is responsible for managing the business and operations of Duncan Energy Partners. DEP Operating Partnership, L.P., a wholly owned subsidiary of Duncan Energy Partners, conducts substantially all of Duncan Energy Partners’ business.

At March 31, 2009, EPO owned approximately 74.1% of Duncan Energy Partners’ limited partner interests and 100% of its general partner.

Enterprise Products Partners has continued involvement with all of the subsidiaries of Duncan Energy Partners, including the following types of transactions: (i) it utilizes Duncan Energy Partners’ storage services to support its Mont Belvieu fractionation and other businesses; (ii) it buys from, and sells to, Duncan Energy Partners natural gas in connection with its normal business activities; and (iii) it is currently the sole shipper on an NGL pipeline system located in south Texas that is owned by Duncan Energy Partners.

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Omnibus Agreement. Under the Omnibus Agreement, EPO agreed to make additional contributions to Duncan Energy Partners as reimbursement for Duncan Energy Partners’ 66% share of any excess construction costs above the (i) $28.6 million of estimated capital expenditures to complete Phase II expansions of the DEP South Texas NGL Pipeline System and (ii) $14.1 million of estimated construction costs for additional brine production capacity and above-ground storage reservoir projects at Mont Belvieu, Texas. Both projects were underway at the time of Duncan Energy Partners’ initial public offering. EPO made cash contributions to Duncan Energy Partners of $1.4 million and $9.3 million in connection with the Omnibus Agreement during the three months ended March 31, 2009 and 2008, respectively. The majority of these contributions related to funding the Phase II expansion costs of the DEP South Texas NGL Pipeline System. EPO will not receive an increased allocation of earnings or cash flows as a result of these contributions to South Texas NGL and Mont Belvieu Caverns.

Mont Belvieu Caverns’ LLC Agreement. EPO made cash contributions of $9.4 million and $36.2 million under the Mont Belvieu Caverns limited liability company agreement during the three months ended March 31, 2009 and 2008, respectively, to fund 100% of certain storage-related projects for the benefit of EPO’s NGL marketing activities. At present, Mont Belvieu Caverns is not expected to generate any identifiable incremental cash flows in connection with these projects; thus, the sharing ratio for Mont Belvieu Caverns is not expected to change from the current sharing ratio of 66% for Duncan Energy Partners and 34% for EPO. EPO expects to make additional contributions of approximately $21.6 million to fund such projects in 2009. The constructed assets will be the property of Mont Belvieu Caverns.

Company and Limited Partnership Agreements – DEP II Midstream Businesses. Enterprise Holdings III, LLC (“Enterprise III”) does not participate in expansion project spending with respect to the DEP II Midstream Businesses, although it may elect to invest in existing or future expansion projects at a later date. As a result, Enterprise GTM Holdings L.P. has funded 100% of such growth capital spending and its Distribution Base has increased from $473.4 million at December 31, 2008 to $586.8 million at March 31, 2009. The Enterprise III Distribution Base was unchanged at $730.0 million at March 31, 2009.

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 Promix. In addition, we purchase NGL storage, transportation and fractionation services from Promix and natural gas from Jonah. For additional information regarding our unconsolidated affiliates, see Note 7.

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Note 13. Earnings Per Unit

The following table presents the net income available to EPGP for the periods indicated:

	For the Three Months
	Ended March 31,
	2009			2008

Net income attributable to Enterprise Products Partners L.P.	$	225.3		$	259.6
Less incentive earnings allocations to EPGP		(35.2	)		(29.8	)
Net income available after incentive earnings allocation		190.1			229.8
Multiplied by EPGP ownership interest		2.0	%		2.0	%
Standard earnings allocation to EPGP	$	3.8		$	4.6

Incentive earnings allocation to EPGP	$	35.2		$	29.8
Standard earnings allocation to EPGP		3.8			4.6
Net income available to EPGP		39.0			34.4
Adjustment for EITF 07-4 (1)		1.4			1.1
Net income available to EPGP for EPU purposes	$	40.4		$	35.5

(1) For purposes of computing basic and diluted earnings per unit, we used the provisions of Emerging Issues Task Force (“EITF”) 07-4, Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships.

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

	For the Three Month
	Ended March 31,
	2009			2008
BASIC EARNINGS PER UNIT
Numerator
Net income attributable to Enterprise Products Partners L.P.	$	225.3		$	259.6
Net income available to EPGP for EPU purposes		(40.4	)		(35.5	)
Net income available to limited partners	$	184.9		$	224.1
Denominator
Weighted – average common units		450.7			434.0
Weighted – average time-vested restricted units		2.0			1.6
Total		452.7			435.6
Basic earnings per unit
Net income per unit before EPGP earnings allocation	$	0.50		$	0.60
Net income available to EPGP		(0.09	)		(0.09	)
Net income available to limited partners	$	0.41		$	0.51
DILUTED EARNINGS PER UNIT
Numerator
Net income attributable to Enterprise Products Partners L.P.	$	225.3		$	259.6
Net income available to EPGP for EPU purposes		(40.4	)		(35.5	)
Net income available to limited partners	$	184.9		$	224.1
Denominator
Weighted – average common units		450.7			434.0
Weighted – average time-vested restricted units		2.0			1.6
Incremental option units		--			0.3
Total		452.7			435.9
Diluted earnings per unit
Net income per unit before EPGP earnings allocation	$	0.50		$	0.60
Net income available to EPGP		(0.09	)		(0.09	)
Net income available to limited partners	$	0.41		$	0.51

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Note 14. Commitments and Contingencies

Litigation

On occasion, we or our unconsolidated affiliates are named as a defendant in litigation and legal proceedings, including regulatory and environmental matters. Although we are insured against various 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. We are unaware of any litigation, pending or threatened, that we believe is reasonably likely to have a significant adverse effect on our financial position, results of operations or cash flows.

We evaluate our ongoing litigation based upon a combination of litigation and settlement alternatives. These reviews are updated as the facts and combinations of the cases develop or change. Assessing and predicting the outcome of these matters involves substantial uncertainties. In the event that the assumptions we used to evaluate these matters change in future periods or new information becomes available, we may be required to record a liability for an adverse outcome. In an effort to mitigate potential adverse consequences of litigation, we could also seek to settle legal proceedings brought against us. We have not recorded any significant reserves for any litigation in our financial statements.

On September 18, 2006, Peter Brinckerhoff, a purported unitholder of TEPPCO, filed a complaint in the Court of Chancery of 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. Mr. Brinckerhoff filed an amended complaint on July 12, 2007. The amended complaint names as defendants (i) TEPPCO, certain of its current and former directors, and certain of its affiliates; (ii) us and certain of our affiliates; (iii) EPCO; and (iv) Dan L. Duncan.

The amended complaint alleges, among other things, that the defendants caused TEPPCO to enter into specified transactions that were unfair to TEPPCO or otherwise unfairly favored us or our affiliates over TEPPCO. These transactions are alleged to include: (i) the joint venture to further expand the Jonah system entered into by TEPPCO and us in August 2006; (ii) the sale by TEPPCO of its Pioneer natural gas processing plant and certain gas processing rights to us in March 2006; and (iii) certain amendments to TEPPCO’s partnership agreement, including a reduction in the maximum tier of TEPPCO’s incentive distribution rights in exchange for TEPPCO common units. The amended complaint seeks (i) rescission of the amendments to TEPPCO’s partnership agreement; (ii) damages for profits and special benefits allegedly obtained by defendants as a result of the alleged wrongdoings in the amended complaint; and (iii) an award to plaintiff of the costs of the action, including fees and expenses of his attorneys and experts. By its Opinion and Order dated November 25, 2008, the Court of Chancery dismissed Mr. Brinckerhoff’s individual and putative class action claims with respect to the amendments to TEPPCO’s partnership agreement. Although we believe there are valid defenses to the claims and we will defend ourselves vigorously, this lawsuit is at an early stage, and in view of the inherent risks and unpredictability of litigation, no assurance can be given as to the outcome of this litigation. See Note 12 for additional information regarding our relationship with TEPPCO.

On February 14, 2007, EPO received a letter from the Environment and Natural Resources Division (“ENRD”) of the U.S. Department of Justice (“DOJ”) related to an ammonia release in Kingman County, Kansas on October 27, 2004 from a pressurized anhydrous ammonia pipeline (“Magellan Ammonia Pipeline”) owned by a third party, Magellan Ammonia Pipeline, L.P. (“Magellan”), and a previous release of ammonia on September 27, 2004 from the same pipeline. EPO was the operator of this pipeline until July 1, 2008. The ENRD has indicated that it may pursue civil damages against EPO 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 EPO and Magellan is up to $17.4 million in the aggregate. EPO is cooperating with the DOJ and is hopeful that an expeditious resolution of this civil

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matter acceptable to all parties will be reached in the near future. Magellan has agreed to indemnify EPO for the civil matter. At this time, we do not believe that a final resolution of 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.

The Attorney General of Colorado on behalf of the Colorado Department of Public Health and Environment filed suit against us and others on April 15, 2008 in connection with the construction of a pipeline near Parachute, Colorado. The State sought a temporary restraining order and an injunction to halt construction activities since it alleged that the defendants failed to install measures to minimize damage to the environment and to follow requirements for the pipeline’s stormwater permit and appropriate stormwater plan. The State’s complaint also seeks penalties for the above alleged failures. Defendants and the State agreed to certain stipulations that, among other things, require us to install specified environmental protection measures in the disturbed pipeline right-of-way to comply with regulations. We have complied with the stipulations and the State has dismissed the portions of the complaint seeking the temporary restraining order and injunction. We believe that the settlement of any penalties with the State will not have a material impact on our consolidated financial position, results of operations or cash flows.

In January 2009, the State of New Mexico filed suit in District Court in Santa Fe County, New Mexico, under the New Mexico Air Quality Control Act. The lawsuit arose out of a February 27, 2008 Notice Of Violation issued to Marathon Oil Corp. (“Marathon”) as operator of the Indian Basin natural gas processing facility located in Eddy County, New Mexico. We own a 42.4% undivided interest in the assets comprising the Indian Basin facility. The State alleges violations of its air laws, and Marathon believes there has been no adverse impact to public health or the environment, having implemented voluntary emission reduction measures over the years. The State seeks penalties above $100,000. Marathon continues to work with the State to determine if resolution of the case is possible. We believe that any potential penalties will not have a material impact on our consolidated financial position, results of operations or cash flows.

See Note 18 for a subsequent event regarding new litigation involving us and TEPPCO.

Contractual Obligations

Scheduled maturities of long-term debt. With the exception of routine fluctuations in the balance of our consolidated revolving credit facilities, there have been no significant changes in our consolidated scheduled maturities of long-term debt since those reported in our Annual Report on Form 10-K for the year ended December 31, 2008.

Operating lease obligations. Lease and rental expense was $9.5 million and $9.0 million during the three months ended March 31, 2009 and 2008, respectively. There have been no material changes in our operating lease commitments since December 31, 2008.

Purchase obligations. Apart from that discussed below, there have been no material changes in our consolidated purchase obligations since December 31, 2008.

Due to our exit from the Texas Offshore Port System partnership, our capital expenditure commitments decreased by an estimated $68.0 million. See Note 18 for additional information regarding this subsequent event.

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Other Claims

As part of our normal business activities with joint venture partners and certain customers and suppliers, we occasionally have claims made against us as a result of disputes related to contractual agreements or similar arrangements. As of March 31, 2009, claims against us totaled approximately $4.6 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

EPCO expects to renew its property insurance policies on or before June 1, 2009. In light of the recent history associated with hurricane and other weather-related events, it is expected that renewal of policies for weather-related risks will result in significant increases in the cost of coverage as well as the physical damage and business interruption deductibles. With regard to windstorm events, EPCO may be unable to purchase coverage equivalent to existing policies due to changes in limits, terms and conditions of such insurance.

In the third quarter of 2008, our onshore and offshore facilities located along the Gulf Coast of Texas and Louisiana were adversely impacted by Hurricanes Gustav and Ike. The disruptions in natural gas, NGL and crude oil production caused by these storms resulted in decreased volumes for some of our pipeline systems, natural gas processing plants, NGL fractionators and offshore platforms, which, in turn, caused a decrease in gross operating margin from these operations. As a result of our allocated share of EPCO’s insurance deductibles for windstorm coverage, we expensed a combined cumulative total of $47.4 million of repair costs for property damage in connection with these two storms through March 31, 2009. We are in the process of filing property damage insurance claims to the extent repair costs exceed deductible amounts. Due to the recent nature of these storms, we are still evaluating the total cost of repairs and the potential for business interruption claims on certain assets.

The following table summarizes proceeds we received during the periods indicated from business interruption and property damage insurance claims with respect to certain named storms:

	For the Three Months
	Ended March 31,
	2009		2008
Business interruption proceeds:
Hurricane Katrina	$	--	$	0.5
Hurricane Rita		--		0.7
Total business interruption proceeds		--		1.2
Property damage proceeds:
Hurricane Katrina		23.2		6.9
Hurricane Rita		--		2.7
Total property damage proceeds		23.2		9.6
Total	$	23.2	$	10.8

At March 31, 2009, we have $12.8 million of estimated property damage claims outstanding related to storms that we believe are probable of collection during the next twelve months and $52.2 million thereafter. To the extent we estimate the dollar value of such damages, please be aware that a change in our estimates may occur as, if and when additional information becomes available.

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Note 16. Supplemental Cash Flow Information

The following table provides information regarding the net effect of changes in our operating assets and liabilities for the periods indicated:

	For the Three Months
	Ended March 31,
	2009			2008
Decrease (increase) in:
Accounts and notes receivable – trade	$	100.4		$	(113.4	)
Accounts receivable – related party		7.8			31.4
Inventories		(157.2	)		65.0
Prepaid and other current assets		9.4			17.4
Other assets		(33.3	)		(2.8	)
Increase (decrease) in:
Accounts payable – trade		7.1			(116.3	)
Accounts payable – related party		(17.5	)		(0.9	)
Accrued product payables		(60.8	)		75.8
Accrued expenses		8.7			(18.1	)
Accrued interest		(38.7	)		(47.2	)
Other current liabilities		4.3			(47.6	)
Other liabilities		(1.8	)		(0.2	)
Net effect of changes in operating accounts	$	(171.6	)	$	(156.9	)

Note 17. Condensed Financial Information of EPO

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

Enterprise Products Partners L.P. guarantees the debt obligations of EPO, with the exception of Duncan Energy Partners’ debt obligations. If EPO were to default on any of its guaranteed debt, Enterprise Products Partners L.P. 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 EPO are insignificant. The following table presents condensed consolidated balance sheet data for EPO at the dates indicated:

	March 31,		December 31,
	2009		2008
ASSETS
Current assets	$	2,296.2	$	2,175.6
Property, plant and equipment, net		13,505.7		13,154.8
Investments in and advances to unconsolidated affiliates, net		935.6		949.5
Intangible assets, net		834.4		855.4
Goodwill		706.9		706.9
Other assets		161.3		126.6
Total	$	18,440.1	$	17,968.8
LIABILITIES AND EQUITY
Current liabilities	$	2,285.3	$	2,222.7
Long-term debt		9,307.3		9,108.4
Other long-term liabilities		146.9		147.3
Equity		6,700.6		6,490.4
Total	$	18,440.1	$	17,968.8

Total EPO debt obligations guaranteed Enterprise Products Partners L.P.	$	8,778.3	$	8,561.8

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

	For the Three Months
	Ended March 31,
	2009			2008
Revenues	$	3,423.1		$	5,684.5
Costs and expenses		3,062.3			5,331.8
Equity in earnings of unconsolidated affiliates		13.4			14.6
Operating income		374.2			367.3
Other expense		(119.6	)		(91.1	)
Income before provision for income taxes		254.6			276.2
Provision for income taxes		(15.2	)		(3.7	)
Net income		239.4			272.5
Net income attributable to the noncontrolling interest		(12.1	)		(12.4	)
Net income attributable to EPO	$	227.3		$	260.1

Note 18. Subsequent Events

EPO Executes $200.0 Million Term Loan

On April 1, 2009, EPO entered into a $200.0 Million Term Loan, which replaced its borrowing availability under the Yen Term Loan that matured on March 30, 2009. EPO’s obligations under the term loan are not secured by any collateral; however, the obligations are guaranteed by Enterprise Products Partners L.P. pursuant to a guaranty agreement. The $200.0 Million Term Loan will mature on September 29, 2009.

Interest accrues on the term loan at a rate per annum equal to LIBOR plus 2.875%. The term loan contains customary representations, warranties, covenants and events of default, the occurrence of which would permit the lenders to accelerate the maturity date of the loan.

Enterprise Products Partners Exits Texas Offshore Port System Partnership

On April 21, 2009, we announced that, effective April 16, 2009, our affiliate elected to dissociate, or exit from, the Texas Offshore Port System partnership and forfeit our investment and one-third ownership interest in the partnership. An affiliate of TEPPCO also elected to dissociate from the Texas Offshore Port System partnership effective at the same time. As a result, we expect to record a non-cash charge of $34.2 million against our earnings for the second quarter of 2009. The decision to dissociate from the Texas Offshore Port System partnership was in connection with a disagreement with one of our partners, an affiliate of Oiltanking.

In a response to the notices of dissociation, Oiltanking has alleged that the dissociation of our and TEPPCO’s affiliates was wrongful and in breach of the Texas Offshore Port System partnership agreement. We believe that our actions in dissociating from the partnership are permitted by, and in accordance with, the terms of the Texas Offshore Port System partnership agreement and, should the need arise, we intend to vigorously defend such actions.

Discussions with TEPPCO Regarding Potential Combination and Related Matters

On April 29, 2009, we announced a proposal to acquire all of the outstanding partnership interests of TEPPCO. The consideration proposed by us included 1.043 of our common units for each issued and outstanding TEPPCO unit and cash equal to $1.00 per TEPPCO unit. Based on the current number of outstanding TEPPCO units, this consideration for TEPPCO units would consist of an aggregate of approximately 109.5 million of our common units and $105.0 million in cash. This consideration would have represented $21.89 per unit, or a premium of approximately 4.8%, based on the 10-day average

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closing prices of TEPPCO units and our common units on March 6, 2009, the business day prior to the date on which we made this proposal to TEPPCO.

We made the proposal after consultation with the Audit, Conflicts and Governance (“ACG”) Committee of the Board of Directors of our general partner. Our proposal did not specify consideration to be paid for TEPPCO’s general partner interests, including incentive distribution rights, or other financial terms or consideration. We do not currently own any TEPPCO units.

TEPPCO’s general partner interests, including incentive distribution rights, are owned by TEPPCO GP. TEPPCO GP is owned by Enterprise GP Holdings. Enterprise GP Holdings owns approximately 4.2% of the outstanding units of TEPPCO, our general partner and approximately 3.0% of our outstanding common units. Accordingly, we expect definitive terms of any combination will require the approval of the ACG Committees of us, TEPPCO and Enterprise GP Holdings. We cannot predict whether the terms of a potential combination will be agreed upon initially by the ACG Committees of the general partners of TEPPCO and us, or whether any potential combination if agreed upon by TEPPCO and us would be acceptable to the Board of Directors of Enterprise GP Holdings’ general partner or its ACG Committee. We believe that any combination with TEPPCO would require the approval of TEPPCO’s unitholders in accordance with its partnership agreement.

On April 29, 2009, we received notice from a special committee formed by TEPPCO to evaluate the proposed acquisition that it does not support the proposal in its current form; however, it would be willing to consider a revised proposal. We do not intend to publicly comment on further discussions unless and until a definitive agreement is reached.

On April 29, 2009, Peter Brinckerhoff and Renee Horowitz, as Attorney in Fact for Rae Kenrow, purported unitholders of TEPPCO, filed separate complaints in the Court of Chancery of New Castle County in the State of Delaware, as putative class actions on behalf of other unitholders of TEPPCO, concerning a proposal made by us to TEPPCO’s general partner, TEPPCO GP, to acquire by merger the limited partnership units of TEPPCO (the “Proposed Merger”). The complaints name as defendants us; EPGP; TEPPCO GP; the directors of TEPPCO GP; EPCO; and Dan L. Duncan.

The complaints allege, among other things, that the terms of the Proposed Merger are unfair to TEPPCO’s unitholders and that the Proposed Merger is an attempt to extinguish, without consideration, a separate derivative action that previously had been filed on behalf of TEPPCO by Peter Brinckerhoff against us; EPGP; EPCO; Dan L. Duncan; TEPPCO GP; and certain of TEPPCO GP’s current and former directors. The complaints further allege that the process through which a special committee of the ACG Committee of TEPPCO GP was appointed to consider the Proposed Merger is contrary to the spirit and intent of TEPPCO’s partnership agreement and constitutes a breach of the implied covenant of fair dealing.

The complaints seek relief (i) enjoining defendants and all persons acting in concert with them from pursuing the Proposed Merger; (ii) rescinding the Proposed Merger to the extent it is consummated or awarding rescissory damages in respect thereof; (iii) directing defendants to account to plaintiffs and the purported class for all damages suffered or to be suffered by them as a result of defendants’ wrongful conduct; and (iv) awarding plaintiffs costs of the actions, including fees and expenses of their attorneys and experts.

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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, 2009 and 2008.

The following information should be read in conjunction with our unaudited condensed consolidated financial statements and accompanying notes included in this report. The following information and such unaudited condensed consolidated financial statements should also be read in conjunction with the financial statements and related notes, together with our discussion and analysis of financial position and results of operations included in our Annual Report on Form 10-K for the year ended December 31, 2008. Our financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”).

Key References Used in this Quarterly Report

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.

References to “EPO” mean Enterprise Products Operating LLC, which is a wholly owned subsidiary of Enterprise Products Partners through which Enterprise Products Partners conducts substantially all of its business.

References to “Duncan Energy Partners” mean Duncan Energy Partners L.P., which is a consolidated subsidiary of EPO. Duncan Energy Partners is a publicly traded Delaware limited partnership, the common units of which are listed on the NYSE under the ticker symbol “DEP.” References to “DEP GP” mean DEP Holdings, LLC, which is the general partner of Duncan Energy Partners and is wholly owned by EPO.

References to “EPGP” mean Enterprise Products GP, LLC, which is our general partner.

References to “Enterprise GP Holdings” mean Enterprise GP Holdings L.P., a publicly traded limited partnership, the units of which are listed on the NYSE under the ticker symbol “EPE.” Enterprise GP Holdings owns EPGP. References to “EPE Holdings” mean EPE Holdings, LLC, which is the general partner of Enterprise GP Holdings.

References to “Energy Transfer Equity” mean the business and operations of Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include Energy Transfer Partners, L.P. (“ETP”). Energy Transfer Equity is a publicly traded Delaware limited partnership, the common units of which are listed on the NYSE under the ticker symbol “ETE.” The general partner of Energy Transfer Equity is LE GP, LLC (“LE GP”). Enterprise GP Holdings owns a noncontrolling interest in both LE GP and Energy Transfer Equity. Enterprise GP Holdings accounts for its investments in LE GP and Energy Transfer Equity using the equity method of accounting.

References to “EPCO” mean EPCO, Inc. and its wholly owned privately-held affiliates, which are related parties to all of the foregoing named entities.

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We, EPO, Duncan Energy Partners, DEP GP, EPGP, Enterprise GP Holdings, EPE Holdings, TEPPCO and TEPPCO GP are affiliates under the common control of Dan L. Duncan, the Group Co-Chairman and controlling shareholder of EPCO.

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
MBPD		= thousand barrels per day
MMBbls		= million barrels
MMBtus		= million British thermal units
Bcf		= billion cubic feet

Cautionary Note Regarding Forward-Looking Statements

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,” “seek,” “goal,” “estimate,” “forecast,” “intend,” “could,” “should,” “will,” “believe,” “may,” “potential” 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 on Form 10-K for 2008 and in Part II, Item 1A of this Quarterly Report. 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. The forward-looking statements in this Quarterly Report speak only as of the date hereof. Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason.

Critical Accounting Policies and Estimates

A summary of the significant accounting policies we have adopted and followed in the preparation of our consolidated financial statements is included in our Annual Report on Form 10-K for the year ended December 31, 2008. Certain of these accounting policies require the use of estimates. As more fully described therein, the following estimates, in our opinion, are subjective in nature, require the exercise of judgment and involve complex analysis: depreciation methods and estimated useful lives of property, plant and equipment; measuring recoverability of long-lived assets and equity method investments; amortization methods and estimated useful lives of qualifying intangible assets; methods we employ to measure the fair value of goodwill; revenue recognition policies and use of estimates for revenues and expenses; reserves for environmental matters; and natural gas imbalances. These estimates are based on our current knowledge and understanding and may change as a result of actions we may take in the future. Changes in these estimates will occur as a result of the passage of time and the occurrence of future events. Subsequent changes in these estimates may have a significant impact on our financial position, results of operations and cash flows.

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 NYSE under the ticker symbol “EPD.”

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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 to 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 EPO. We are owned 98% by our limited partners and 2% by our general partner, EPGP. EPGP is owned 100% by Enterprise GP Holdings.

Recent Developments

The following information highlights our significant developments since January 1, 2009 through the date of this filing.

Potential Business Combination Discussions with TEPPCO and Related Matters

On April 29, 2009, we announced the proposal to acquire all of the outstanding partnership interests of TEPPCO. The consideration proposed by us included 1.043 of our common units for each issued and outstanding TEPPCO unit and cash equal to $1.00 per TEPPCO unit. Based on the current number of outstanding TEPPCO units, this consideration for TEPPCO units would consist of an aggregate of approximately 109.5 million of our common units and $105.0 million in cash. This consideration would have represented $21.89 per unit, or a premium of approximately 4.8%, based on the 10-day average closing prices of TEPPCO units and our common units on March 6, 2009, the business day prior to the date on which we made this proposal to TEPPCO.

On April 29, 2009, we received notice from a special committee formed by TEPPCO to evaluate the proposed acquisition that it does not support the proposal in its current form; however, it would be willing to consider a revised proposal. We do not intend to comment further on discussions unless and until a definitive agreement is reached.

For information regarding lawsuits filed in connection with the proposed merger, see Note 18 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this Quarterly Report.

Enterprise Products Partners Exits Texas Offshore Port System Partnership

In April 2009, we announced that our affiliate elected to dissociate, or exit from, the Texas Offshore Port System partnership and forfeit our investment and one-third ownership interest in the partnership. As a result, we expect to record a non-cash charge of $34.2 million against our earnings for the second quarter of 2009. For additional information see Note 18 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this Quarterly Report.

Service Begins on Shenzi Crude Oil Export Pipeline

In April 2009, we announced that construction of our crude oil pipeline serving the Shenzi field in the Gulf of Mexico has been completed and is now transporting production from the deepwater discovery. The 83-mile pipeline has a capacity of 230 MBPD of crude oil and gives Shenzi producers access to the Cameron Highway Oil Pipeline and Poseidon Oil Pipeline systems, in which we have ownership interests and operate.

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EPO Executes $200.0 Million Term Loan

In April 2009, EPO entered into a $200.0 Million Term Loan, which replaced its borrowing availability under the Yen Term Loan that matured on March 30, 2009. For additional information regarding this term loan, see Note 18 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this Quarterly Report.

Service Begins on Sherman Extension Pipeline

In March 2009, we and Duncan Energy Partners announced that construction has been completed on the 174-mile Sherman Extension expansion of the Enterprise Texas Instrastate natural gas pipeline system which extends through the heart of the prolific Barnett Shale natural gas play of North Texas. The completion of the Sherman Extension adds 1.1 Bcf/d of incremental natural gas takeaway capacity from the region, while providing producers in the Barnett Shale and as far away as the Waha area of West Texas with greater flexibility to reach the most attractive natural gas markets.

Service Begins at Meeker II

In March 2009, we announced that operations commenced at our Meeker II natural gas processing plant in the Piceance Basin of Colorado. The Meeker II expansion doubles the natural gas processing capacity at the Meeker complex to 1.5 Bcf/d with the capability to extract up to 70 MBPD of NGLs.

Enterprise Products Partners Issues $225.6 million of Common Units

In January 2009, Enterprise Products Partners sold 10,590,000 common units representing limited partner interests (including an over-allotment of 990,000 common units) to the public at an offering price of $22.20 per unit. Net offering proceeds of $225.6 million were used to reduce borrowings outstanding under EPO’s Multi-Year Revolving Credit Facility and for general partnership purposes.

Results of Operations

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 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 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.

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.

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Selected Price and Volumetric Data

The following table illustrates selected annual and 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)
2008
1st Quarter	$8.03	$97.91	$1.01	$1.47	$1.80	$1.87	$2.12	$0.61	$0.54
2nd Quarter	$10.94	$123.88	$1.05	$1.70	$2.05	$2.08	$2.64	$0.70	$0.67
3rd Quarter	$10.25	$118.01	$1.09	$1.68	$1.97	$1.99	$2.52	$0.78	$0.66
4th Quarter	$6.95	$58.32	$0.42	$0.80	$0.90	$0.96	$1.09	$0.37	$0.22
2008 Averages	$9.04	$99.53	$0.89	$1.41	$1.68	$1.72	$2.09	$0.62	$0.52

2009
1st Quarter	$4.91	$42.96	$0.36	$0.68	$0.87	$0.97	$0.96	$0.26	$0.20

(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 a weighted-average of CMAI spot prices. Polymer-grade propylene represents average CMAI contract pricing. (2) Crude oil price is representative of an index price for West Texas Intermediate.

The following table presents our material 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. These statistics include volumes for newly constructed assets since the dates such assets were placed into service and for recently purchased assets since the date of acquisition.

	For the Three Months
	Ended March 31,
	2009		2008
NGL Pipelines & Services, net:
NGL transportation volumes (MBPD)		1,950		1,831
NGL fractionation volumes (MBPD)		432		423
Equity NGL production (MBPD)		114		104
Fee-based natural gas processing (MMcf/d)		3,104		2,669
Onshore Natural Gas Pipelines & Services, net:
Natural gas transportation volumes (BBtus/d)		7,981		6,981
Offshore Pipelines & Services, net:
Natural gas transportation volumes (BBtus/d)		1,542		1,936
Crude oil transportation volumes (MBPD)		126		206
Platform natural gas processing (MMcf/d)		777		830
Platform crude oil processing (MBPD)		3		21
Petrochemical Services, net:
Butane isomerization volumes (MBPD)		90		96
Propylene fractionation volumes (MBPD)		68		58
Octane additive production volumes (MBPD)		5		7
Petrochemical transportation volumes (MBPD)		106		115
Total, net:
NGL, crude oil and petrochemical transportation volumes (MBPD)		2,182		2,152
Natural gas transportation volumes (BBtus/d)		9,523		8,917
Equivalent transportation volumes (MBPD) (1)		4,688		4,499

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

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Comparison of Results of Operations

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

	For the Three Months
	Ended March 31,
	2009		2008
Revenues	$	3,423.1	$	5,684.5
Operating costs and expenses		3,041.3		5,311.2
General and administrative costs		23.0		21.2
Equity in earnings of unconsolidated affiliates		13.4		14.6
Operating income		372.2		366.7
Interest expense		120.4		91.9
Provision for income taxes		15.2		3.7
Net income		237.3		272.0
Net income attributable to Enterprise Products Partners L.P.		225.3		259.6

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

	For the Three Months
	Ended March 31,
	2009		2008
Gross operating margin by segment:
NGL Pipelines & Services	$	342.8	$	289.7
Onshore Natural Gas Pipelines & Services		116.0		109.9
Offshore Pipeline & Services		61.3		81.6
Petrochemical Services		28.6		41.0
Total segment gross operating margin	$	548.7	$	522.2

For a reconciliation of non-GAAP gross operating margin to GAAP operating income and further to GAAP income before provision for income taxes, see “Other Items – Non-GAAP Reconciliations” included within this Item 2.

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The following table summarizes the contribution to revenues from each business segment (including the effects of eliminations and adjustments) during the periods indicated (dollars in millions):

	For the Three Months
	Ended March 31,
	2009		2008
NGL Pipelines & Services:
Sales of NGLs	$	2,276.0	$	4,051.2
Sales of other petroleum and related products		0.5		0.7
Midstream services		157.3		168.7
Total		2,433.8		4,220.6
Onshore Natural Gas Pipelines & Services:
Sales of natural gas		561.7		641.8
Midstream services		104.1		118.5
Total		665.8		760.3
Offshore Pipelines & Services:
Sales of natural gas		0.3		0.5
Sales of other petroleum and related products		0.2		2.6
Midstream services		68.0		81.9
Total		68.5		85.0
Petrochemical Services:
Sales of other petroleum and related products		229.5		596.3
Midstream services		25.5		22.3
Total		255.0		618.6
Total consolidated revenues	$	3,423.1	$	5,684.5

Comparison of Three Months Ended March 31, 2009 with

Three Months Ended March 31, 2008

Revenues for the first quarter of 2009 were $3.42 billion compared to $5.68 billion for the first quarter of 2008. The $2.26 billion quarter-to-quarter decrease in consolidated revenues is primarily due to lower energy commodity sales prices during the first quarter of 2009 relative to the first quarter of 2008. Reduced energy commodity prices accounted for $2.22 billion of the quarter-to-quarter decrease in consolidated revenues associated with our NGL, natural gas and petrochemical marketing activities.

Operating costs and expenses were $3.04 billion for the first quarter of 2009 versus $5.31 billion for the first quarter of 2008. The $2.27 billion quarter-to-quarter decrease in consolidated operating costs and expenses is primarily due to lower cost of sales associated with our commodity marketing activities. The cost of sales of our marketing activities decreased $1.95 billion quarter-to-quarter primarily due to lower energy commodity prices. Likewise, the operating costs and expenses of our natural gas processing plants decreased $304.5 million quarter-to-quarter primarily due to lower energy commodity prices. General and administrative costs increased $1.8 million quarter-to-quarter.

Changes in our revenues and costs and expenses quarter-to-quarter are primarily explained by changes in energy commodity prices. The weighted-average indicative market price for NGLs was $0.66 per gallon during the first quarter of 2009 versus $1.49 per gallon during the first quarter of 2008 – a 56% decrease quarter-to-quarter. 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) decreased 39% quarter-to-quarter to an average of $4.91 per MMBtu during the first quarter of 2009 versus $8.03 per MMBtu during the first quarter of 2008. See “Results of Operations - Selected Price and Volumetric Data” within this Item 2 for additional historical energy commodity pricing information.

Equity in earnings from our unconsolidated affiliates was $13.4 million for the first quarter of 2009 compared to $14.6 million for the first quarter of 2008, a $1.2 million quarter-to-quarter decrease. Our investments in White River Hub, LLC (“White River Hub”) and Skelly-Belvieu Pipeline Company,

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L.L.C. (“Skelly-Belvieu”) contributed equity earnings of $0.9 million and $0.3 million, respectively, for the first quarter of 2009. The assets owned by White River Hub began commercial operations in December 2008. We acquired a 49% equity interest in Skelly-Belvieu during December 2008. Equity in earnings from our investment in Venice Energy Services Company, L.L.C. increased $4.3 million quarter-to-quarter primarily due to adjustments to repair expenses that we originally recorded during the first quarter of 2008. Collectively, equity earnings from our other equity investments decreased $6.7 million quarter-to-quarter primarily due to the lingering effects of Hurricanes Gustav and Ike on our offshore and south Louisiana investments during the first quarter of 2009.

Operating income for the first quarter of 2009 was $372.2 million compared to $366.7 million for the first quarter of 2008. Consolidated revenues and certain operating costs and expenses can fluctuate significantly due to changes in energy commodity prices (e.g., the price of natural gas and NGLs) without significantly affecting our operating income. Consequently, the aforementioned changes in revenues, costs and expenses and equity earnings contributed to the $5.5 million quarter-to-quarter increase in operating income.

Interest expense increased to $120.4 million for the first quarter of 2009 from $91.9 million for the first quarter of 2008. The $28.5 million quarter-to-quarter increase in interest expense is primarily due to our issuance of Senior Notes M and N in the second quarter of 2008 and Senior Notes O in the fourth quarter of 2008. Average debt principal outstanding during the first quarter of 2009 was $9.16 billion compared to $7.18 billion during the first quarter of 2008. Provision for income taxes increased $11.5 million quarter-to-quarter primarily due to higher corporate income taxes for our Dixie Pipeline Company (“Dixie”) and Seminole Pipeline Company subsidiaries during the first quarter of 2009 relative to the first quarter of 2008 and a quarter-to-quarter increase in expenses attributable to the Texas Margin Tax. Provision for income taxes attributable to Dixie for the first quarter of 2009 includes a one-time charge of $6.6 million associated with taxable gains from the sale of certain assets.

As a result of items noted in the previous paragraphs, net income decreased $34.7 million quarter-to-quarter to $237.3 million for the first quarter of 2009 compared to $272.0 million for the first quarter of 2008. Net income attributable to noncontrolling interests was $12.0 million for the first quarter of 2009 compared to $12.4 million for the first quarter of 2008. Net income attributable to Enterprise Products Partners decreased $34.3 million quarter-to-quarter to $225.3 million for the first quarter of 2009 compared to $259.6 million for the first quarter of 2008.

We estimate that gross operating margin was reduced by approximately $21.0 million during the first quarter of 2009 primarily due to the lingering effects of Hurricanes Gustav and Ike, which resulted in continued producer supply interruptions and facility downtime. For more information regarding our insurance program and claims related to these storms, see “Other Items – Weather-Related Risks” included within this Item 2.

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

NGL Pipelines & Services. Gross operating margin from this business segment was $342.8 million for the first quarter of 2009 compared to $289.7 million for the first quarter of 2008, a $53.1 million quarter-to-quarter increase. In general, this business segment benefited quarter-to-quarter from increased natural gas processing activity at our recently completed Pioneer and Meeker gas processing facilities including the effects of our hedging activities, lower power-related costs and increased NGL export activity during the first quarter of 2009 compared to the first quarter of 2008.

Gross operating margin from our natural gas processing and related NGL marketing business was $194.6 million for the first quarter of 2009 compared to $178.5 million for the first quarter of 2008. Equity NGL production increased to 114 MBPD during the first quarter of 2009 from 104 MBPD during the first quarter of 2008. The $16.1 million quarter-to-quarter increase in gross operating margin from this business is largely due to contributions from our Meeker and Pioneer cryogenic natural gas processing facilities as a result of higher equity NGL production and the effects of our commodity hedging activities. These

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facilities contributed $56.5 million of the quarter-to-quarter increase in gross operating margin and produced an average of 53 MBPD of equity NGLs during the first quarter of 2009 compared to an average of 38 MBPD during the first quarter of 2008. Collectively, gross operating margin from the remainder of this business decreased $40.4 million quarter-to-quarter primarily due to reduced natural gas processing margins quarter-to-quarter attributed to our natural gas processing activities in the Permian Basin, south Texas and south Louisiana.

Gross operating margin from our NGL pipelines and related storage business was $119.6 million for the first quarter of 2009 compared to $86.2 million for the first quarter of 2008, a $33.4 million quarter-to-quarter increase. Gross operating margin from our Mid-America and Seminole Pipeline Systems increased $16.2 million quarter-to-quarter primarily due to lower fuel costs. Gross operating margin from the remainder of our NGL pipeline and storage assets increased $17.2 million quarter-to-quarter largely due to higher NGL export activity and storage activity at our Mont Belvieu storage complex during the first quarter of 2009 relative to the first quarter of 2008. Total NGL transportation volumes increased to 1,950 MBPD during the first quarter of 2009 from 1,831 MBPD during the first quarter of 2008.

Gross operating margin from our NGL fractionation business was $28.6 million for the first quarter of 2009 compared to $25.0 million for the first quarter of 2008. Fractionation volumes increased to 432 MBPD during the first quarter of 2009 from 423 MBPD during the first quarter of 2008. Gross operating margin from this business increased $3.6 million quarter-to-quarter largely due to lower power-related costs at our Mont Belvieu and Hobbs fractionators during the first quarter of 2009 relative to the first quarter of 2008.

Onshore Natural Gas Pipelines & Services. Gross operating margin from this business segment was $116.0 million for the first quarter of 2009 compared to $109.9 million for the first quarter of 2008, a $6.1 million quarter-to-quarter increase. Our onshore natural gas transportation volumes were 7,981 BBtus/d during the first quarter of 2009 compared to 6,981 BBtus/d during the first quarter of 2008. Gross operating margin from our onshore natural gas pipeline and related natural gas marketing business increased $3.6 million quarter-to-quarter to $103.0 million for the first quarter of 2009 from $99.4 million for the first quarter of 2008. This business benefitted from improved results during the first quarter of 2009, in comparison to the first quarter of 2008, from our natural gas marketing activities, increased gross operating margin attributable to the Great Divide gathering system we acquired during December 2008 and our equity in earnings of White River Hub. Collectively, the aforementioned improvements more than offset a $24.0 million quarter-to-quarter decrease in gross operating margin from our San Juan gathering system as a result of lower revenues from gathering fees indexed to natural gas prices and lower proceeds from condensate sales.

Gross operating margin from our natural gas storage business was $13.0 million for the first quarter of 2009 compared to $10.5 million for the first quarter of 2008. The $2.5 million quarter-to-quarter increase in gross operating margin is primarily due to increased storage activity at our Petal natural gas storage facility. We placed in service an additional natural gas storage cavern having 4.2 Bcf of subscribed capacity at our Petal facility during the third quarter of 2008.

Offshore Pipelines & Services. Gross operating margin from this business segment was $61.3 million for the first quarter of 2009 compared to $81.6 million for the first quarter of 2008. Results from this business segment for the first quarter of 2009 were negatively impacted by ongoing repairs to downstream infrastructure damaged by Hurricanes Gustav and Ike, which resulted in prolonged downtime and continued supply interruptions for certain of our offshore assets during the first quarter of 2009.

Gross operating margin from our offshore platform services business was $38.5 million for the first quarter of 2009 compared to $43.6 million for the first quarter of 2008, a $5.1 million quarter-to-quarter decrease. Gross operating margin from our Independence Hub platform increased $1.0 million quarter-to-quarter due to higher processing volumes. Collectively, gross operating margin from our other offshore platforms decreased $6.1 million quarter-to-quarter primarily due to lower natural gas and crude oil processing volumes at our Marco Polo platform as a result of continuing hurricane-related disruptions and the expiration of demand fee revenues at our Falcon platform. Our net platform natural gas processing

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volumes decreased to 777 MMcf/d during the first quarter of 2009 compared to 830 MMcf/d during the first quarter of 2008. Our net platform crude oil processing volumes decreased to 3 MBPD during the first quarter of 2009 compared to 21 MBPD during the first quarter of 2008.

Gross operating margin from our offshore crude oil pipeline business was $5.1 million for the first quarter of 2009 versus $12.1 million for the first quarter of 2008. Gross operating margin decreased $7.0 million quarter-to-quarter due to lower transportation volumes on our Marco Polo, Constitution and Cameron Highway oil pipelines as a result of continuing disruptions from previous hurricanes. Total offshore crude oil transportation volumes were 126 MBPD during the first quarter of 2009 versus 206 MBPD during the first quarter of 2008.

Gross operating margin from our offshore natural gas pipeline business was $17.7 million for the first quarter of 2009 compared to $25.8 million for the first quarter of 2008. Offshore natural gas transportation volumes were 1,542 BBtus/d during the first quarter of 2009 versus 1,936 BBtus/d during the first quarter of 2008. Gross operating margin from our Independence Trail pipeline increased $0.9 million quarter-to-quarter due to increased producer transportation volumes. Collectively, gross operating margin from our other offshore natural gas pipelines decreased $9.0 million quarter-to-quarter primarily due to continuing disruptions as a result of Hurricanes Gustav and Ike damages.

Petrochemical Services. Gross operating margin from this business segment was $28.6 million for the first quarter of 2009 compared to $41.0 million for the first quarter of 2008. Gross operating margin from our propylene fractionation and pipeline business was $21.8 million for the first quarter of 2009 compared to $15.4 million for the first quarter of 2008. The $6.4 million quarter-to-quarter increase in gross operating margin is largely due to higher propylene sales margins and volumes during the first quarter of 2009 relative to the first quarter of 2008. Propylene fractionation volumes increased to 68 MBPD during the first quarter of 2009 from 58 MBPD during the first quarter of 2008.

Gross operating margin from our butane isomerization business was $14.9 million for the first quarter of 2009 compared to $27.9 million for the first quarter of 2008. The $13.0 million quarter-to-quarter decrease in gross operating margin is primarily due to reduced butane isomerization volumes and lower proceeds from the sale of plant by-products resulting from lower NGL prices during the first quarter of 2009 relative to the first quarter of 2008. Butane isomerization volumes decreased to 90 MBPD during the first quarter of 2009 from 96 MBPD during the first quarter of 2008. Gross operating margin from our octane enhancement business was a loss of $8.1 million for the first quarter of 2009 compared to a loss of $2.2 million for the first quarter of 2008. The $5.9 million quarter-to-quarter decrease in gross operating margin is due to prolonged downtime and higher costs associated with scheduled maintenance activities during the first quarter of 2009.

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 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 business expansion projects and acquisitions are expected to be funded by a variety of sources (either separately or in combination) including operating cash flows, borrowings under credit facilities, the issuance of additional equity and debt securities and proceeds from divestitures of ownership interests in assets to affiliates or third parties. We expect to fund cash distributions to partners primarily with operating cash flows. Our debt service requirements are expected to be funded by operating cash flows and/or refinancing arrangements.

At March 31, 2009, we had $41.5 million of unrestricted cash on hand and approximately $877.8 million of available credit under EPO’s Multi-Year Revolving Credit Facility and 364-Day Revolving Credit Facility. We had approximately $9.25 billion in principal outstanding under consolidated debt agreements at March 31, 2009. In total, our consolidated liquidity at March 31, 2009 was approximately

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$1.06 billion, which includes the available borrowing capacity of our consolidated subsidiaries such as Duncan Energy Partners.

Registration Statements

We have a universal shelf registration statement on file with the SEC that allows us to issue an unlimited amount of debt and equity securities for general partnership purposes. In January 2009, we sold 10,590,000 common units (including an over-allotment of 990,000 common units) to the public at an offering price of $22.20 per unit. We used the net proceeds of $225.6 million from the offering to temporarily reduce borrowings outstanding under EPO’s Multi-Year Revolving Credit Facility, which may be reborrowed to fund capital expenditures and other growth projects, and for general partnership purposes.

We also have a registration statement on file with the SEC authorizing the issuance of up to 40,000,000 common units in connection with our distribution reinvestment plan (“DRIP”). During the three months ended March 31, 2009, we issued 3,634,842 common units in connection with our DRIP, which generated proceeds of $77.9 million from plan participants. In February 2009, affiliates of EPCO reinvested $65.0 million in connection with the DRIP.

In addition, we have a registration statement on file related to our employee unit purchase plan (“EUPP”), under which we can issue up to 1,200,000 common units. During the three months ended March 31, 2009, we issued 44,321 common units to employees under this plan, which generated proceeds of $1.0 million.

Duncan Energy Partners has a universal shelf registration statement filed with the SEC that authorizes its issuance of up to $1.00 billion in debt and equity securities. Duncan Energy Partners did not issue any securities under this registration statement during the three months ended March 31, 2009. After taking into account the past issuance of securities under this universal registration statement, Duncan Energy Partners can issue approximately $999.5 million of additional securities under this registration statement as of March 31, 2009.

For information regarding our public debt obligations or partnership equity, see Notes 9 and 10, respectively, of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this Quarterly Report.

Letter of Credit Facilities

At March 31, 2009 we had $1.0 million in a standby letter of credit outstanding. In April 2009, we replaced a prior letter of credit facility relating to our NYMEX margin requirements for natural gas derivative instruments with a $60.0 million letter of credit facility. These letter of credit facilities do not reduce the amount available under EPO’s credit facilities.

Credit Ratings of EPO

The investment-grade credit ratings of EPO’s senior unsecured debt securities were Baa3 by Moody’s Investor Services; BBB- by Fitch Ratings; and BBB- by Standard and Poor’s. Such ratings reflect only the view of a rating agency and should not be interpreted as a recommendation to buy, sell or hold any security. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it determines that the circumstances warrant such a change and should be evaluated independently of any other rating.

We have had preliminary consultations with the ratings agencies regarding the potential combination of our Partnership with TEPPCO under the terms of the offer dated March 9, 2009. Based on these discussions, reports and comments issued by the ratings agencies after our announcement of the potential combination, we do not expect a change in our credits ratings if the potential business combination materializes based on terms similar to those of our offer dated March 9, 2009. However, the

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terms of the potential combination have not been agreed to and material changes to the underlying proposed structure of such a combination could have a different outcome with respect to our credit ratings.

Cash Flows from Operating, Investing and Financing Activities

The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated (dollars in millions). 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,
	2009		2008
Net cash flows provided by operating activities	$	218.1	$	265.1
Cash used in investing activities		424.3		568.6
Cash provided by financing activities		214.3		329.6

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

Comparison of Three Months Ended March 31, 2009

with Three Months Ended March 31, 2008

Operating Activities. Net cash flows provided by operating activities were $218.1 million for the three months ended March 31, 2009 compared to $265.1 million for the three months ended March 31, 2008. This $47.0 million decrease in net cash flows provided by operating activities was primarily due to the following:

Net cash flows from consolidated operations (excluding cash payments for interest and distributions received from unconsolidated affiliates) decreased $45.5 million quarter-to-quarter. Although our gross operating margin increased quarter-to-quarter (see “Results of Operations” within this Item 2), the reduction in operating cash flow is generally due to the timing of related cash receipts and disbursements. The $45.5 million total quarter-to-quarter decrease also includes an $8.6 million increase in cash proceeds we received primarily from property damage insurance claims related to named storms. For information regarding proceeds from business interruption and property damage claims, see Note 15 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this Quarterly Report.

§	Cash payments for interest decreased $4.2 million quarter-to-quarter due primarily to a lower weighted average interest rate applicable to EPO’s Multi-Year Revolving Credit Facility during the three months ended March 31, 2009 compared to the three months ended March 31, 2008.

§	Distributions received from unconsolidated affiliates decreased $5.7 million for the three months ended March 31, 2009 compared to the three months ended March 31, 2008 primarily due to lower distribution received from Deepwater Gateway, L.L.C.

Investing Activities. Cash used in investing activities was $424.3 million for the three months ended March 31, 2009 compared to $568.6 million for the three months ended March 31, 2008. This $144.3 million decrease in cash used in investing activities was primarily due to the following:

§	Capital spending for property, plant and equipment, net of contributions in aid of construction costs, decreased $231.2 million quarter-to-quarter. For additional information related to our capital spending program, see “Capital Spending” included within this Item 2.

§	A $40.7 million increase in restricted cash (a cash outflow) for the three months ended March 31, 2009 due to margin requirements related to derivative instruments held during the three months

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ended March 31, 2009 compared to a $64.5 decrease in restricted cash (a cash inflow) due to the elimination of margin requirements related to derivative instruments held during the three months ended March 31, 2008.

§	Cash outlays for net investments and advances relating to unconsolidated affiliates decreased by $14.3 million quarter-to-quarter primarily due to higher investments and advances to Jonah Gas Gathering Company during the three months ended March 31, 2008.

Financing Activities. Cash provided by financing activities was $214.3 million for the three months ended March 31, 2009 compared to $329.6 million for the three months ended March 31, 2008. This $115.3 million decrease in cash provided by financing activities was primarily due to the following:

Net borrowings under our consolidated debt agreements were $198.5 million during the three months ended March 31, 2009 compared to $573.0 million during the three months ended March 31, 2008. The $374.5 million decrease in net borrowings was attributable to increased net borrowings under EPO’s Multi-Year Revolving Credit Facility during the three months ended March 31, 2008 partially offset by the repayment of the $217.6 million Yen Term Loan in March 2009.

§	Cash distributions to our partners increased $27.8 million quarter-to-quarter primarily due to increases to our common units outstanding and quarterly distribution rates.

Net proceeds from issuance of common units increased $292.5 million quarter-to-quarter primarily due to the January 2009 issuance of underwritten common units that generated proceeds of $225.6 million and an increase of $62.5 million in proceeds generated by our DRIP and EUPP quarter-to-quarter. Affiliates of EPCO reinvested $62.5 million of their distributions through the DRIP in the first quarter of 2009.

Capital Spending

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

	For the Three Months Ended March 31,
	2009		2008
Capital spending for property, plant and equipment, net
of contributions in aid of construction costs	$	386.1	$	617.3
Capital spending for investments in unconsolidated affiliates		6.4		7.4
Total capital spending	$	392.5	$	624.7

Based on information currently available, we estimate our consolidated capital spending for the remainder of 2009 (i.e., the second, third and fourth quarters) will approximate $700 million, which includes estimated expenditures of $560 million for growth capital projects and acquisitions and $140 million for sustaining capital expenditures.

Our forecast of consolidated capital expenditures is based on our current announced strategic operating and growth plans and exclude amounts associated with the Texas Offshore Port System partnership, which we announced our dissociation from in April 2009. Our strategic operating and growth plans 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.

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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 capital we can invest. 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.

At March 31, 2009, we had approximately $279.6 million in purchase commitments outstanding that relate to our capital spending for property, plant and equipment. Due to our exit from the Texas Offshore Port System partnership in April 2009, our purchase commitments outstanding decreased by an estimated $68.0 million. See Note 18 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this Quarterly Report for additional information regarding this subsequent event. These remaining commitments primarily relate to construction of our Barnett Shale and Piceance Basin natural gas pipeline projects.

Significant Ongoing Growth Capital Projects

The following table summarizes information regarding certain ongoing significant growth capital projects (dollars in millions). Actual costs noted for each project reflects our share of cash expenditures as of March 31, 2009, excluding capitalized interest. The current forecast amount noted for each project also reflects our share of project expenditures, excluding estimated capitalized interest.

			Current
	Estimated		Forecast
	Date of	Actual	Total
Project Name	Completion	Costs	Cost

Piceance Basin pipeline projects	Fourth Quarter 2009	$ 118.7	$ 215.3
Trinity River Basin Extension	2010	53.8	268.1
Expansion of Wilson natural gas storage facility	2010	55.4	118.5

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. This federal agency has issued safety regulations containing requirements for the development of integrity management programs for hazardous liquid pipelines (which include NGL and petrochemical pipelines) and natural gas pipelines. In general, these regulations require companies to assess the condition of their pipelines in certain high consequence areas (as defined by the regulation) and to perform any necessary repairs.

The following table summarizes our pipeline integrity costs for the periods indicated (dollars in millions):

	For the Three Months
	Ended March 31,
	2009		2008
Expensed	$	5.7	$	11.7
Capitalized		2.9		5.5
Total	$	8.6	$	17.2

We expect the costs of our pipeline integrity program, irrespective of whether such costs are capitalized or expensed, to approximate $90.7 million for the remaining three quarters of 2009.

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Other Items

Contractual Obligations

With the exception of routine fluctuations in the balance of our consolidated revolving credit facilities and the effects of our dissociation from the Texas Offshore Port System partnership on our purchase commitments, there have been no significant changes in our contractual obligations since those reported in our Annual Report on Form 10-K for the year ended December 31, 2008.

Off-Balance Sheet Arrangements

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, 2008.

Summary of Related Party Transactions

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

	For the Three Months
	Ended March 31,
	2009			2008
Revenues from consolidated operations:
EPCO and affiliates	$	25.1		$	18.4
Energy Transfer Equity and subsidiaries		162.8			223.1
Unconsolidated affiliates		56.6			59.2
Total	$	244.5		$	300.7
Cost of sales:
EPCO and affiliates	$	28.4		$	15.8
Energy Transfer Equity and subsidiaries		90.0			45.5
Unconsolidated affiliates		13.1			28.3
Total	$	131.5		$	89.6
Operating costs and expenses:
EPCO and affiliates	$	79.5		$	85.9
Energy Transfer Equity and subsidiaries		1.4			3.3
Unconsolidated affiliates		(2.7	)		(2.2	)
Total	$	78.2		$	87.0
General and administrative expenses:
EPCO and affiliates	$	17.8		$	17.7
Other expense:
EPCO and affiliates	$	--		$	0.3

The following table summarizes related party amounts at the dates indicated (dollars in millions).

	March 31,		December 31,
	2009		2008
Accounts receivable - related parties:
EPCO and affiliates	$	38.5	$	26.6
Energy Transfer Equity and subsidiaries		16.5		35.0
Total	$	55.0	$	61.6

Accounts payable - related parties:
EPCO and affiliates	$	20.4	$	39.4
Energy Transfer Equity and subsidiaries		1.6		0.2
Total	$	22.0	$	39.6

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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.

Non-GAAP Reconciliations

The following table presents a reconciliation of our measurement of total non-GAAP gross operating margin to GAAP operating income and income before provision for income taxes (dollars in millions):

	For the Three Months
	Ended March 31,
	2009			2008
Total segment gross operating margin	$	548.7		$	522.2
Adjustments to reconcile total gross operating margin
to operating income:
Depreciation, amortization and accretion in
operating costs and expenses		(153.5	)		(133.9	)
Operating lease expense paid by EPCO		(0.2	)		(0.5	)
Gain from asset sales and related transactions in
operating costs and expenses		0.2			0.1
General and administrative costs		(23.0	)		(21.2	)
Operating income		372.2			366.7
Other expense, net		(119.7	)		(91.0	)
Income before provision for income taxes	$	252.5		$	275.7

Recent Accounting Pronouncements

The accounting standard setting bodies have recently issued the following accounting guidance since those reported in our Annual Report on Form 10-K for the year ended December 31, 2008 that will or may affect our future financial statements:

§	FSP FAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly, and

§	FSP FAS 107-1 and APB 28-1, Interim Disclosures About Fair Value of Financial Instruments.

For additional information regarding recent accounting developments, see Note 2 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this Quarterly Report.

Weather-Related Risks

EPCO expects to renew its property insurance policies on or before June 1, 2009. In light of the recent history associated with hurricane and other weather-related events, it is expected that renewal of policies for weather related risks will result in significant increases in the cost of coverage as well as the physical damage and business interruption deductibles. With regard to windstorm events, EPCO may be unable to purchase coverage equivalent to existing policies due to changes in limits, terms and conditions of such insurance.

For additional information regarding weather-related risks, including insurance matters in connection with Hurricanes Katrina, Rita, Gustav and Ike, see Note 15 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this Quarterly Report.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk.

In the course of our normal business operations, we are exposed to certain risks, including changes in interest rates, commodity prices and, to a limited extent, foreign exchange rates. In order to manage risks associated with certain identifiable and anticipated transactions, we use derivative instruments. Derivatives are financial instruments whose fair value is determined by changes in a specified benchmark such as interest rates, commodity prices or currency values. Typical derivative instruments include futures, forward contracts, swaps and other instruments with similar characteristics. Substantially all of our derivatives are used for non-trading activities. See Note 4 to the Unaudited Condensed Financial Statements included under Item 1 of this Quarterly Report for additional information regarding our derivative instruments and hedging activities.

Our exposures to market risk have not changed materially since those reported under Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk of our Annual Report on Form 10-K for the year ended December 31, 2008.

Interest Rate Derivative Instruments

The following tables show the effect of hypothetical price movements on the estimated fair value (“FV”) of interest rate swap portfolios at the dates presented (dollars in millions):

Enterprise Products Partners	Resulting	Swap Fair Value at
Scenario	Classification	March 31, 2009		April 20, 2009
FV assuming no change in underlying interest rates	Asset	$	45.5	$	41.6
FV assuming 10% increase in underlying interest rates	Asset		41.4		37.4
FV assuming 10% decrease in underlying interest rates	Asset		49.6		45.8

Duncan Energy Partners	Resulting	Swap Fair Value at
Scenario	Classification	March 31, 2009			April 20, 2009
FV assuming no change in underlying interest rates	Liability	$	(7.7	)	$	(7.4	)
FV assuming 10% increase in underlying interest rates	Liability		(7.3	)		(7.0	)
FV assuming 10% decrease in underlying interest rates	Liability		(8.0	)		(7.8	)

Commodity Derivative Instruments

The prices of natural gas, NGLs, crude oil 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 risk associated with such products, we enter into commodity derivative instruments such as forwards, basis swaps and futures contracts.

The following table shows the effect of hypothetical price movements on the estimated fair value of our natural gas marketing portfolio at the dates presented (dollars in millions):

	Resulting	Portfolio Fair Value at
Scenario	Classification	March 31, 2009		April 20, 2009
FV assuming no change in underlying commodity prices	Asset	$	21.9	$	23.2
FV assuming 10% increase in underlying commodity prices	Asset		18.1		18.9
FV assuming 10% decrease in underlying commodity prices	Asset		25.6		27.5

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The following table shows the effect of hypothetical price movements on the estimated fair value of our NGL and petrochemical operations portfolio at the dates presented (dollars in millions):

	Resulting	Portfolio Fair Value at
Scenario	Classification	March 31, 2009			April 20, 2009
FV assuming no change in underlying commodity prices	Liability	$	(120.0	)	$	(125.9	)
FV assuming 10% increase in underlying commodity prices	Liability		(126.6	)		(135.6	)
FV assuming 10% decrease in underlying commodity prices	Liability		(113.4	)		(116.2	)

Foreign Currency Derivative Instruments

In addition, we were exposed to foreign currency exchange risk in connection with a term loan denominated in Japanese yen (see Note 9 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this Quarterly Report). We entered into this loan agreement in November 2008 and the loan matured in March 2009. The derivative instrument used to hedge this risk was accounted for as a cash flow hedge and settled upon repayment of the loan.

Item 4. Controls and Procedures.

Disclosure Controls and Procedures

As of the end of the period covered by this Quarterly Report, our management carried out an evaluation, with the participation of our general partner’s chief executive officer (the “CEO”) and our general partner’s chief financial officer (the “CFO”), of the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 of the Securities Exchange Act of 1934. Based on this evaluation, as of the end of the period covered by this Report, the CEO and CFO concluded:

(i)

that our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including the CEO and CFO, as appropriate to allow timely decisions regarding required disclosure; and

(ii)	that our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

There were no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) or in other factors during the first quarter of 2009, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

On April 29, 2009, Peter Brinckerhoff and Renee Horowitz, as Attorney in Fact for Rae Kenrow, purported unitholders of TEPPCO, filed separate complaints in the Court of Chancery of New Castle County in the State of Delaware, as putative class actions on behalf of other unitholders of TEPPCO, concerning a proposal made by us to TEPPCO’s general partner, TEPPCO GP, to acquire by merger the limited partnership units of TEPPCO. The complaints name as defendants us; EPGP; TEPPCO GP; the directors of TEPPCO GP; EPCO; and Dan L. Duncan.

See Part I, Item 1, Financial Statements, Note 14, “Commitments and Contingencies – Litigation,” of the Notes to Unaudited Condensed Consolidated Financial Statements included in this Quarterly Report, which is incorporated herein by reference for information on other legal proceedings.

Item 1A. Risk Factors.

Security holders and potential investors in our securities should carefully consider the risk factor set forth below and the risk factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2008 in addition to other information in such report and in this Quarterly Report. We have identified these risk factors as important factors that could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by use or on our behalf.

Our prior interest in the Texas Offshore Port System partnership and dissociation from the

partnership in April 2009 could subject us to various liabilities.

The Texas Offshore Port System partnership was expected to represent an important component of our Offshore Pipelines & Services segment, requiring an estimated $600.0 million in capital contributions from us through 2011. Effective April 16, 2009, we and a subsidiary of TEPPCO elected to dissociate, or exit, from the partnership. In dissociating from the partnership, we forfeited our investment and one-third ownership interest in the partnership. The third partner, Oiltanking, has asserted that the dissociation was wrongful and in breach of the Texas Offshore Port System partnership agreement, citing provisions of the agreement that, if applicable, would continue to obligate us to make capital contributions to fund the project and impose additional liabilities on us.

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

As of March 31, 2009, we and our affiliates could repurchase up to 618,400 additional common units under the December 1998 common unit repurchase program. We did not repurchase any of our common units in connection with this announced program during the three months ended March 31, 2009.

The following table summarizes our repurchase activity during 2009 in connection with other arrangements:

				Maximum
			Total Number of	Number of Units
		Average	of Units Purchased	That May Yet
	Total Number of	Price Paid	as Part of Publicly	Be Purchased
Period	Units Purchased	per Unit	Announced Plans	Under the Plans
February 2009	1,357 (1)	$22.64	--	--
(1) Of the 11,000 restricted unit awards that vested in February 2009 and converted to common units, 1,357 of these units were sold back to the partnership by employees to cover related withholding tax requirements.

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	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).
2.2	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).
2.3	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).
2.4	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).
2.5	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).

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3.1	Certificate of Limited Partnership of Enterprise Products Partners L.P. (incorporated by reference to Exhibit 3.6 to Form 10-Q filed November 9, 2007).
3.2	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).
3.3	First Amendment to the Fifth Amended and Restated Partnership Agreement of Enterprise Products Partners L.P. dated as of December 27, 2007 (incorporated by reference to Exhibit 3.1 to Form 8-K/A filed January 3, 2008).
3.4	Second Amendment to the Fifth Amended and Restated Partnership Agreement of Enterprise Products Partners L.P. dated as of April 14, 2008 (incorporated by reference to Exhibit 10.1 to Form 8-K filed April 16, 2008).
3.5	Third Amendment to the Fifth Amended and Restated Partnership Agreement of Enterprise Products Partners L.P. dated as of November 6, 2008 (incorporated by reference to Exhibit 3.5 to Form 10-Q filed on November 10, 2008).
3.6	Fifth Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC, dated as of November 7, 2007 (incorporated by reference to Exhibit 3.2 to Form 10-Q filed November 9, 2007).
3.7	First Amendment to Fifth Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC, dated as of November 6, 2008 (incorporated by reference to Exhibit 3.7 to Form 10-Q filed on November 10, 2008).
3.8	Limited Liability Company Agreement of Enterprise Products Operating LLC dated as of June 30, 2007 (incorporated by reference to Exhibit 3.3 to Form 10-Q filed on August 8, 2007).
3.9	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).
3.10	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).
3.11	Certificate of Limited Partnership of Duncan Energy Partners L.P. (incorporated by reference to Exhibit 3.1 to Duncan Energy Partners L.P.’s Form S-1 Registration Statement, Reg. No. 333-138371, filed November 2, 2006).
3.12	Amended and Restated Agreement of Limited Partnership of Duncan Energy Partners L.P., dated February 5, 2007 (incorporated by reference to Exhibit 3.1 to Duncan Energy Partners L.P.’s Form 8-K filed February 5, 2007).
3.13	First Amendment to Amended and Restated Partnership Agreement of Duncan Energy Partners L.P. dated as of December 27, 2007 (incorporated by reference to Exhibit 3.1 to Duncan Energy Partners L.P.’s Form 8-K/A filed on January 3, 2008).
4.1	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).
4.2	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).
4.3	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).
4.4	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	Third Supplemental Indenture dated as of June 30, 2007, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Guarantor, and U.S. Bank National Association, as successor Trustee (incorporated by reference to Exhibit 4.55 to Form 10-Q filed on August 8, 2007).

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4.6

Amended and Restated Revolving Credit Agreement dated as of November 19, 2007 among Enterprise Products Operating LLC, the financial institutions party thereto as lenders, Wachovia Bank, National Association, as Administrative Agent, Issuing Bank and Swingline Lender, Citibank, N.A. and JPMorgan Chase Bank, as Co-Syndication Agents, and SunTrust Bank, Mizuho Corporate Bank, Ltd. and The Bank of Nova Scotia, as Co-Documentation Agents (incorporated by reference to Exhibit 10.1 to Form 8-K filed on November 20, 2007).

4.7	Amended and Restated Guaranty Agreement dated as of November 19, 2007 executed by Enterprise Products Partners L.P. in favor of Wachovia Bank, National Association, as Administrative Agent (incorporated by reference to Exhibit 10.2 to Form 8-K filed on November 20, 2007).
4.8	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).
4.9	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).
4.10	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).
4.11	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).
4.12	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).
4.13	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).
4.14	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).
4.15	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).
4.16	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).
4.17	Ninth Supplemental Indenture, dated as of May 24, 2007, by and 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 the Current Report on Form 8-K filed by Enterprise Products Partners L.P. on May 24, 2007).
4.18	Tenth Supplemental Indenture, dated as of June 30, 2007, by and among Enterprise Products Operating LLC, as issuer, Enterprise Products Partners L.P., as parent guarantor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.54 to Form 10-Q filed August 8, 2007).

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4.19	Eleventh Supplemental Indenture, dated as of September 4, 2007, by and among Enterprise Products Operating LLC, as issuer, Enterprise Products Partners L.P., as parent guarantor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed on September 5, 2007).
4.20	Twelfth Supplemental Indenture, dated as of April 3, 2008, 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 April 3, 2008).
4.21	Thirteenth Supplemental Indenture, dated as of April 3, 2008, 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 April 3, 2008).
4.22	Fourteenth Supplemental Indenture, dated as of December 8, 2008, 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 December 8, 2008).
4.23	Global Note representing $350.0 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).
4.24	Global Note representing $500.0 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).
4.25	Global Notes representing $450.0 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).
4.26	Global Note representing $500.0 million principal amount of 4.00% 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).
4.27	Global Note representing $500.0 million principal amount of 5.60% 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).
4.28	Global Note representing $150.0 million principal amount of 5.60% 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).
4.29	Global Note representing $350.0 million principal amount of 6.65% Series B Senior Notes due 2034 with attached Guarantee (incorporated by reference to Exhibit 4.19 to Form S-3 Registration Statement Reg. No. 333-123150 filed on March 4, 2005).
4.30	Global Note representing $500.0 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).
4.31	Global Note representing $250.0 million 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).
4.32	Global Note representing $250.0 million 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).
4.33	Global Note representing $500.0 million 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).
4.34	Form of Junior Subordinated Note, including Guarantee (incorporated by reference to Exhibit 4.3 to Form 8-K filed July 19, 2006).
4.35	Global Note representing $800.0 million principal amount of 6.30% Senior Notes due 2017 with attached Guarantee (incorporated by reference to Exhibit 4.38 to Form 10-Q filed November 9, 2007).

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4.36	Form of Global Note representing $400.0 million principal amount of 5.65% Senior Notes due 2013 with attached Guarantee (incorporated by reference to Exhibit 4.3 to Form 8-K filed April 3, 2008).
4.37	Form of Global Note representing $700.0 million principal amount of 6.50% Senior Notes due 2019 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed April 3, 2008).
4.38	Form of Global Note representing $500.0 million principal amount of 9.75% Senior Notes due 2014 with attached Guarantee (incorporated by reference to Exhibit 4.3 to Form 8-K filed December 8, 2008).
4.39	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).
4.40	Replacement Capital Covenant, dated May 24, 2007, executed by Enterprise Products Operating L.P. and Enterprise Products Partners L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K filed by Enterprise Products Partners L.P. on May 24, 2007).
4.41	First Amendment to Replacement Capital Covenant dated August 25, 2006, executed by Enterprise Products Operating L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 99.2 to Form 8-K filed August 25, 2006).
4.42	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	Fifth 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, 2009 (incorporated by reference to Exhibit 10.1 to the Form 8-K filed by Enterprise Products Partners L.P. on February 5, 2009).
10.2	Term Loan Credit Agreement dated as of April 1, 2009 among Enterprise Products Operating LLC, the financial institutions party thereto as lenders, Mizuho Corporate Bank, Ltd., as administrative agent, a lender and as sole lead arranger (incorporated by reference to Exhibit 10.1 to Form 8-K on April 2, 2009).
10.3	Guaranty Agreement dated as of April 1, 2009 executed by Enterprise Products Partners L.P. in favor of Mizuho Corporate Bank, Ltd., as administrative agent (incorporated by reference to Exhibit 10.2 to Form 8-K on April 2, 2009).
31.1#	Sarbanes-Oxley Section 302 certification of Michael A. Creel for Enterprise Products Partners L.P. for the March 31, 2009 quarterly report on Form 10-Q.
31.2#	Sarbanes-Oxley Section 302 certification of W. Randall Fowler for Enterprise Products Partners L.P. for the March 31, 2009 quarterly report on Form 10-Q.
32.1#	Section 1350 certification of Michael A. Creel for the March 31, 2009 quarterly report on Form 10-Q.
32.2#	Section 1350 certification of W. Randall Fowler for the March 31, 2009 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., Duncan Energy Partners L.P. and Enterprise GP Holdings L.P. are 1-14323, 1-33266 and 1-32610, respectively.
#	Filed with this report.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on May 11, 2009.

					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