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

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

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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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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