Edgar Filing: ENTERPRISE PRODUCTS PARTNERS L P

epdform10q_033111.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, 2011

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 Street, 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 þ 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 845,386,852 common units and 4,520,431 Class B units (which generally vote together with the common units) of Enterprise Products Partners L.P. outstanding at April 30, 2011. Our common units trade on the New York Stock Exchange under the ticker symbol “EPD.”

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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 Operations, Organization and Basis of Presentation	8
	2. General Accounting Matters	10
	3. Equity-based Awards	12
	4. Derivative Instruments, Hedging Activities and Fair Value Measurements	16
	5. Inventories	24
	6. Property, Plant and Equipment	25
	7. Investments in Unconsolidated Affiliates	27
	8. Intangible Assets and Goodwill	29
	9. Debt Obligations	31
	10. Equity and Distributions	34
	11. Business Segments	37
	12. Related Party Transactions	41
	13. Earnings Per Unit	44
	14. Commitments and Contingencies	45
	15. Significant Risks and Uncertainties	50
	16. Supplemental Cash Flow Information	52
	17. Condensed Consolidating Financial Information	52
	18. Subsequent Event	57
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	58
Item 3.	Quantitative and Qualitative Disclosures about Market Risk.	76
Item 4.	Controls and Procedures.	79

PART II. OTHER INFORMATION.
Item 1.	Legal Proceedings.	80
Item 1A.	Risk Factors.	80
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	80
Item 3.	Defaults upon Senior Securities.	80
Item 4.	(Removed and Reserved).	80
Item 5.	Other Information.	80
Item 6.	Exhibits.	81

Signatures		88

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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	2011			2010
Current assets:
Cash and cash equivalents	$	150.4		$	65.5
Restricted cash		191.6			98.7
Accounts receivable – trade, net of allowance for doubtful accounts of $13.5 at March 31, 2011 and $18.4 at December 31, 2010		3,881.3			3,800.1
Accounts receivable – related parties		31.0			36.8
Inventories		800.8			1,134.0
Prepaid and other current assets		391.7			372.0
Total current assets		5,446.8			5,507.1
Property, plant and equipment, net		19,892.9			19,332.9
Investments in unconsolidated affiliates		2,269.9			2,293.1
Intangible assets, net of accumulated amortization of $945.3 at March 31, 2011 and $932.3 at December 31, 2010		1,794.0			1,841.7
Goodwill		2,107.7			2,107.7
Other assets		309.9			278.3
Total assets	$	31,821.2		$	31,360.8

LIABILITIES AND EQUITY
Current liabilities:
Current maturities of debt	$	782.3		$	282.3
Accounts payable – trade		607.6			542.0
Accounts payable – related parties		139.0			133.1
Accrued product payables		4,078.7			4,164.8
Accrued interest		181.3			252.9
Other current liabilities		669.2			505.1
Total current liabilities		6,458.1			5,880.2
Long-term debt: (see Note 9)		13,273.6			13,281.2
Deferred tax liabilities		78.6			78.0
Other long-term liabilities		210.9			220.6
Commitments and contingencies
Equity: (see Note 10)
Partners’ equity:
Limited partners:
Common units (845,431,409 units outstanding at March 31, 2011 and 843,681,572 units outstanding at December 31, 2010)		11,258.5			11,288.2
Class B units (4,520,431 units outstanding at March 31, 2011 and December 31, 2010)		118.5			118.5
Accumulated other comprehensive loss		(100.1	)		(32.5	)
Total partners’ equity		11,276.9			11,374.2
Noncontrolling interest		523.1			526.6
Total equity		11,800.0			11,900.8
Total liabilities and equity	$	31,821.2		$	31,360.8

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,
	2011			2010
Revenues:
Third parties	$	9,933.6		$	8,312.1
Related parties		250.1			232.4
Total revenues (see Note 11)		10,183.7			8,544.5
Costs and expenses:
Operating costs and expenses:
Third parties		9,111.5			7,647.9
Related parties		425.6			324.0
Total operating costs and expenses		9,537.1			7,971.9
General and administrative costs:
Third parties		12.9			16.3
Related parties		25.0			24.0
Total general and administrative costs		37.9			40.3
Total costs and expenses (see Note 11)		9,575.0			8,012.2
Equity in income of unconsolidated affiliates		16.2			26.6
Operating income		624.9			558.9
Other income (expense):
Interest expense		(183.8	)		(157.9	)
Interest income		0.3			0.2
Other, net		0.2			(0.1	)
Total other expense, net		(183.3	)		(157.8	)
Income before provision for income taxes		441.6			401.1
Provision for income taxes		(7.1	)		(8.7	)
Net income		434.5			392.4
Net income attributable to noncontrolling interest (see Note 10)		(13.8	)		(322.5	)
Net income attributable to partners	$	420.7		$	69.9

Allocation of net income attributable to partners:
Limited partners	$	420.7		$	69.9
General partner	$	--		$	**

Earnings per unit (see Note 13)
Basic earnings per unit	$	0.52		$	0.33
Diluted earnings per unit	$	0.49		$	0.33

See Notes to Unaudited Condensed Consolidated Financial Statements.

** Amount is negligible.

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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,
	2011			2010

Net income	$	434.5		$	392.4
Other comprehensive income (loss):
Cash flow hedges:
Commodity derivative instrument losses during period		(151.4	)		(58.9	)
Reclassification adjustment for losses included in net income related to commodity derivative instruments		68.9			16.5
Interest rate derivative instrument gains (losses) during period		14.1			(7.5	)
Reclassification adjustment for losses included in net income related to interest rate derivative instruments		1.5			6.1
Foreign currency derivative losses during period		--			(0.1	)
Reclassification adjustment for gains included in net income related to foreign currency derivative instruments		--			(0.3	)
Total cash flow hedges		(66.9	)		(44.2	)
Foreign currency translation adjustment		--			0.6
Change in funded status of pension and postretirement plans, net of tax		0.3			(0.9	)
Proportionate share of other comprehensive income (loss) of unconsolidated affiliate		(1.0	)		1.0
Total other comprehensive loss		(67.6	)		(43.5	)
Comprehensive income		366.9			348.9
Comprehensive income attributable to noncontrolling interest		(13.8	)		(279.5	)
Comprehensive income attributable to partners	$	353.1		$	69.4

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,
	2011			2010
Operating activities:
Net income	$	434.5		$	392.4
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		241.1			218.6
Non-cash asset impairment charges		--			1.5
Equity in income of unconsolidated affiliates		(16.2	)		(26.6	)
Distributions received from unconsolidated affiliates		42.5			51.4
Operating lease expenses paid by EPCO		0.2			0.2
Gains from asset sales and related transactions		(18.4	)		(7.5	)
Deferred income tax expense		0.8			1.0
Changes in fair market value of derivative instruments		(1.3	)		(7.8	)
Effect of pension settlement recognition		(0.5	)		(0.2	)
Net effect of changes in operating accounts (see Note 16)		120.0			73.4
Net cash flows provided by operating activities		802.7			696.4
Investing activities:
Capital expenditures		(713.5	)		(347.8	)
Contributions in aid of construction costs		3.2			3.6
Increase in restricted cash		(92.9	)		(38.1	)
Cash used for business combinations		--			(2.2	)
Investments in unconsolidated affiliates		(3.8	)		(7.7	)
Proceeds from asset sales and related transactions		84.2			21.7
Other investing activities		(3.6	)		--
Cash used in investing activities		(726.4	)		(370.5	)
Financing activities:
Borrowings under debt agreements		2,821.6			378.1
Repayments of debt		(2,316.0	)		(615.8	)
Debt issuance costs		(12.8	)		(0.1	)
Cash distributions paid to partners		(479.7	)		(73.8	)
Cash distributions paid to noncontrolling interest		(17.2	)		(351.9	)
Cash contributions from noncontrolling interest		1.3			417.3
Net cash proceeds from issuance of common units		21.0			--
Acquisition of treasury units		(3.9	)		(0.2	)
Other financing activities		(5.7	)		--
Cash provided by (used in) financing activities		8.6			(246.4	)
Effect of exchange rate changes on cash		--			0.4
Net change in cash and cash equivalents		84.9			79.5
Cash and cash equivalents, January 1		65.5			55.3
Cash and cash equivalents, March 31	$	150.4		$	135.2

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, Accumulated Other Comprehensive Loss and Noncontrolling Interest)

(Dollars in millions)

	Partners’ Equity
	Limited Partners			General Partner		Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest			Total
Balance, December 31, 2010	$	11,406.7		$	--	$	(32.5	)	$	526.6		$	11,900.8
Net income		420.7			--		--			13.8			434.5
Operating lease expenses paid by EPCO		0.2			--		--			--			0.2
Cash distributions paid to partners		(479.7	)		--		--			--			(479.7	)
Cash distributions paid to noncontrolling interest		--			--		--			(17.2	)		(17.2	)
Cash contributions from noncontrolling interest		--			--		--			1.3			1.3
Net cash proceeds from issuance of common units		21.0			--		--			--			21.0
Acquisition of treasury units		(3.9	)		--		--			--			(3.9	)
Amortization of equity awards		12.0			--		--			0.1			12.1
Change in value of cash flow hedges		--			--		(66.9	)		--			(66.9	)
Proportionate share of other comprehensive loss of unconsolidated affiliate		--			--		(1.0	)		--			(1.0	)
Other		--			--		0.3			(1.5	)		(1.2	)
Balance, March 31, 2011	$	11,377.0		$	--	$	(100.1	)	$	523.1		$	11,800.0

	Partners’ Equity
	Limited Partners			General Partner		Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest			Total
Balance, December 31, 2009	$	1,972.4		$	**	$	(33.3	)	$	8,534.0		$	10,473.1
Net income		69.9			**		--			322.5			392.4
Operating lease expenses paid by EPCO		--			--		--			0.2			0.2
Cash distributions paid to partners		(73.8	)		--		--			--			(73.8	)
Cash distributions paid to noncontrolling interest		--			--		--			(351.9	)		(351.9	)
Cash contributions from noncontrolling interest		--			--		--			417.3			417.3
Acquisition of treasury units		--			--		--			(0.2	)		(0.2	)
Amortization of equity awards		0.5			--		--			8.0			8.5
Change in value of cash flow hedges		--			--		(1.5	)		(42.7	)		(44.2	)
Proportionate share of other comprehensive income of unconsolidated affiliate		--			--		1.0			--			1.0
Other		--			--		--			(0.3	)		(0.3	)
Balance, March 31, 2010	$	1,969.0		$	**	$	(33.8	)	$	8,886.9		$	10,822.1

See Notes to Unaudited Condensed Consolidated Financial Statements.

** Amount is negligible.

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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.

SIGNIFICANT RELATIONSHIPS REFERENCED IN THESE

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unless the context requires otherwise, references to “we,” “us,” “our,” “Enterprise” 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, and its consolidated subsidiaries, through which Enterprise conducts substantially all of its business. Enterprise is managed by its general partner, Enterprise Products Holdings LLC (“Enterprise GP”), which is a wholly owned subsidiary of Dan Duncan LLC, a Delaware limited liability company.

On September 3, 2010, Enterprise GP Holdings L.P. (“Holdings”), Enterprise, Enterprise GP, Enterprise Products GP, LLC (“EPGP,” the former general partner of Enterprise) and Enterprise ETE LLC (“Holdings MergerCo,” a Delaware limited liability company and a wholly owned subsidiary of Enterprise) entered into a merger agreement (the “Holdings Merger Agreement”). On November 22, 2010, the Holdings Merger Agreement was approved by the unitholders of Holdings and the merger of Holdings with and into Holdings MergerCo and related transactions were completed, with Holdings MergerCo surviving such merger (collectively, we refer to these transactions as the “Holdings Merger”). Enterprise’s membership interests in Holdings MergerCo were subsequently contributed to EPO. For additional information regarding the Holdings Merger, see Note 1.

The membership interests of Dan Duncan LLC are owned of record by a voting trust, the current trustees (“DD LLC Trustees”) of which are: (i) Randa Duncan Williams, who is also a director of Enterprise GP; (ii) Dr. Ralph S. Cunningham, who is also a director and the Chairman of Enterprise GP and one of three managers of Dan Duncan LLC; and (iii) Richard H. Bachmann, who is also a director of Enterprise GP and one of three managers of Dan Duncan LLC.

References to “EPCO” mean Enterprise Products Company and its privately held affiliates. A majority of the outstanding voting capital stock of EPCO is owned of record by a voting trust, the current trustees (“EPCO Trustees”) of which are: (i) Ms. Williams, who serves as Chairman of EPCO; (ii) Dr. Cunningham, who serves as a Vice Chairman of EPCO; and (iii) Mr. Bachmann, who serves as the President and Chief Executive Officer (“CEO”) of EPCO. Ms. Williams, Dr. Cunningham and Mr. Bachmann are also currently directors of EPCO.

References to “Duncan Energy Partners” mean Duncan Energy Partners L.P. (NYSE: DEP), which is a consolidated subsidiary of EPO. References to “DEP GP” mean DEP Holdings, LLC, which is the general partner of Duncan Energy Partners and a wholly owned subsidiary of EPO. On April 28, 2011, we, our general partner, and two of our subsidiaries entered into a definitive merger agreement with Duncan Energy Partners and DEP GP. See Note 1 for information regarding the proposed merger of Duncan Energy Partners with a subsidiary of Enterprise.

References to “TEPPCO” and “TEPPCO GP” mean TEPPCO Partners, L.P. and Texas Eastern Products Pipeline Company, LLC (which is the general partner of TEPPCO), respectively, prior to their mergers with our subsidiaries on October 26, 2009. We refer to such related mergers both individually and in the aggregate as the “TEPPCO Merger.”

References to “Energy Transfer Equity” mean the business and operations of Energy Transfer Equity, L.P. (NYSE: ETE) and its consolidated subsidiaries, which include Energy Transfer Partners, L.P. (“ETP”) and Regency Energy Partners LP (“RGNC”). The general partner of Energy Transfer Equity is LE GP, LLC (“LE GP”). We own noncontrolling interests in Energy Transfer Equity, which we account for using the equity method of accounting.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

References to “Employee Partnerships” mean EPE Unit L.P., EPE Unit II, L.P., EPE Unit III, L.P., Enterprise Unit L.P. and EPCO Unit L.P., collectively, all of which were privately held affiliates of EPCO. The Employee Partnerships were liquidated in August 2010. See Note 3 for additional information.

Duncan Energy Partners and Energy Transfer Equity electronically file certain documents with the U.S. Securities and Exchange Commission (“SEC”), including annual reports on Form 10-K and quarterly reports on Form 10-Q. The SEC maintains an Internet website at www.sec.gov that contains periodic reports and other information regarding these registrants.

Note 1. Partnership Operations, Organization and Basis of Presentation

We are a publicly traded Delaware limited partnership, the common units of which are listed on the NYSE under the ticker symbol EPD. We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO. We are a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, refined products and certain petrochemicals. Our midstream energy asset network links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the United States, Canada and the Gulf of Mexico with domestic consumers and international markets. Our assets include approximately 50,200 miles of onshore and offshore pipelines; 190 million barrels (“MMBbls”) of storage capacity for NGLs, refined products and crude oil; and 27 billion cubic feet (“Bcf”) of natural gas storage capacity.

Our midstream energy operations include: natural gas gathering, treating, processing, transportation and storage; NGL transportation, fractionation, storage, and import and export terminaling; crude oil and refined products transportation, storage, and terminaling; offshore production platforms; petrochemical transportation and services; and a marine transportation business that operates primarily on the United States inland and Intracoastal Waterway systems and in the Gulf of Mexico. We have six reportable business segments: (i) NGL Pipelines & Services; (ii) Onshore Natural Gas Pipelines & Services; (iii) Onshore Crude Oil Pipelines & Services; (iv) Offshore Pipelines & Services; (v) Petrochemical & Refined Products Services; and (vi) Other Investments. Our business segments reflect the manner in which these businesses are managed and reviewed by the CEO of our general partner. See Note 11 for additional information regarding our business segments.

We are 100% owned by our limited partners from an economic perspective. We are managed and controlled by Enterprise GP, which has a non-economic general partner interest in us. We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates and under the collective common control of the DD LLC and EPCO Trustees. We have no employees. All of our operating functions and general and administrative support services are provided by employees of EPCO pursuant to an administrative services agreement (the “ASA”) or by other service providers. See Note 12 for information regarding the ASA and other related party matters.

Agreement and Plan of Merger with Duncan Energy Partners

On April 28, 2011, we entered into an Agreement and Plan of Merger, dated as of April 28, 2011 (the “Duncan Merger Agreement”), by and among Enterprise, Enterprise GP, EPD MergerCo LLC (“Duncan MergerCo,” a Delaware limited liability company and a wholly owned subsidiary of Enterprise), Duncan Energy Partners and DEP GP. At the effective time of the merger, Duncan MergerCo will merge with and into Duncan Energy Partners, pursuant to the Duncan Merger Agreement, with Duncan Energy Partners surviving the merger as a wholly owned subsidiary of Enterprise (the “Duncan Merger”), and all of the outstanding Duncan Energy Partners common units at the effective time of the merger will be cancelled and converted into the right to receive common units representing limited partner interests in Enterprise based on an exchange rate of 1.01 Enterprise common units for each Duncan Energy Partners common unit.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The Duncan Merger Agreement and the Duncan Merger must be approved by the affirmative vote or consent of holders of (i) a majority of the outstanding common units of Duncan Energy Partners and (ii) a majority of the Duncan Energy Partners common units owned by the Duncan Unaffiliated Unitholders (as defined in the Duncan Merger Agreement) that actually vote for or against such approval. In connection with the Duncan Merger Agreement, we, Duncan Energy Partners and Enterprise GTM Holdings L.P., a Delaware limited partnership and a wholly owned subsidiary of Enterprise (“Enterprise GTM”), entered into a Voting Agreement, dated as of April 28, 2011 (the “Voting Agreement”), pursuant to which Enterprise GTM and Enterprise agreed to vote any of the Duncan Energy Partners common units owned by them or their subsidiaries in favor of the adoption of the Duncan Merger Agreement and the Duncan Merger at any meeting of the Duncan Energy Partners unitholders, including the 33,783,587 Duncan Energy Partners common units currently directly owned by Enterprise GTM (representing approximately 58.5% of the outstanding common units of Duncan Energy Partners). The Voting Agreement will terminate upon the termination of the Duncan Merger Agreement.

The Duncan Merger Agreement contains customary representations, warranties and covenants by each of the parties. Completion of the Duncan Merger is conditioned upon, among other things: (i) requisite Duncan Energy Partners unitholder approval of the Duncan Merger Agreement and the Duncan Merger; (ii) applicable regulatory approvals; (iii) the absence of certain legal injunctions or impediments prohibiting the transactions; (iv) the effectiveness of a registration statement on Form S-4 with respect to the issuance by Enterprise of the Enterprise common units in connection with the Duncan Merger; (v) the receipt of certain tax opinions; and (vi) approval for the listing of the Enterprise common units issued in connection with the Duncan Merger on the NYSE.

Basis of Presentation

Holdings Merger. On November 22, 2010, the Holdings Merger Agreement was approved by the unitholders of Holdings and the merger of Holdings with Holdings MergerCo and related transactions were completed, with Holdings MergerCo surviving such merger. At the effective time of the Holdings Merger, Enterprise GP succeeded as Enterprise’s general partner, and each issued and outstanding unit representing limited partner interests in Holdings was cancelled and converted into the right to receive Enterprise common units based on an exchange ratio of 1.5 Enterprise common units for each Holdings unit. Enterprise issued an aggregate of 208,813,454 of its common units (net of 23 fractional common units cashed out) as consideration in the Holdings Merger and, immediately after the merger, cancelled 21,563,177 of its common units previously owned by Holdings.

In connection with the Holdings Merger, Enterprise’s partnership agreement was amended and restated to effect the cancellation of its general partner’s 2% economic general partner interest and incentive distribution rights in Enterprise. In addition, a privately held affiliate of EPCO agreed to temporarily waive the regular quarterly cash distributions it would otherwise receive from Enterprise on an initial amount of 30,610,000 of Enterprise’s common units (the “Designated Units”) for a five-year period after the merger closing date. The number of Designated Units to which the temporary distribution waiver applies is as follows for distributions to be paid during the following periods, if any: 30,610,000 during 2011; 26,130,000 during 2012; 23,700,000 during 2013; 22,560,000 during 2014; and 17,690,000 during 2015.

Prior to the Holdings Merger, Enterprise was a consolidated subsidiary of Holdings, which was Enterprise’s parent. Upon completion of the Holdings Merger, Holdings merged with and into a wholly owned subsidiary of Enterprise. The Holdings Merger results in Holdings being considered the surviving consolidated entity for accounting purposes, while Enterprise is the surviving consolidated entity for legal and reporting purposes. For accounting purposes, Holdings is deemed the acquirer of the noncontrolling interests in Enterprise that were previously recognized in Holdings’ consolidated financial statements (i.e., the acquisition of Enterprise’s limited partner interests that were owned by parties other than Holdings).

As a result of the Holdings Merger, Enterprise’s consolidated financial and operating results prior to November 22, 2010 have been presented as if it were Holdings from an accounting perspective (i.e., the financial statements of Holdings become the historical financial statements of Enterprise). The primary

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

differences between Holdings’ and Enterprise’s consolidated results of operations were: (i) general and administrative costs incurred by Holdings and EPGP (our former general partner); (ii) equity in income of Holdings’ noncontrolling ownership interests in Energy Transfer Equity; and (iii) interest expense associated with Holdings’ debt. In addition, for periods prior to November 22, 2010, the net assets, income, cash distributions and contributions and other amounts attributable to Enterprise’s limited partner interests that were owned by third parties and related parties other than Holdings are presented as a component of noncontrolling interest. See Note 10 for additional information regarding noncontrolling interests.

The historical limited partner units outstanding and earnings per unit amounts presented in our financial statements have been retroactively presented in connection with the 1.5 to one unit-for-unit exchange that occurred under the Holdings Merger. See Note 13 for additional information regarding earnings per unit.

Consolidation of Duncan Energy Partners. For financial reporting purposes, we consolidate the financial statements of Duncan Energy Partners with those of our own and reflect its operations in our business segments. We control Duncan Energy Partners through our ownership of its general partner. 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 nor EPO have any obligation for the payment of interest or repayment of borrowings incurred by Duncan Energy Partners.

Note 2. General Accounting Matters

Our results of operations for the three months ended March 31, 2011 are not necessarily indicative of results expected for the full year. 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 and 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 SEC. These Unaudited Condensed Consolidated Financial Statements and the Notes thereto should be read in conjunction with the Audited Consolidated Financial Statements and Notes thereto included in our annual report on Form 10-K for the year ended December 31, 2010 (the “2010 Form 10-K”).

Allowance for Doubtful Accounts

Our allowance for doubtful accounts is determined based on specific identification and estimates of future uncollectible accounts. Our procedure for determining the allowance for doubtful accounts is based on: (i) historical experience with customers, (ii) the perceived financial stability of customers based on our research and (iii) the levels of credit we grant to customers. In addition, we may increase the allowance account in response to the specific identification of customers involved in bankruptcy proceedings and similar financial difficulties. On a routine basis, we review estimates associated with the allowance for doubtful accounts to ensure that we have recorded sufficient reserves to cover potential losses. Our allowance also includes estimates for uncollectible natural gas imbalances based on specific identification of accounts.

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The following table presents the activity of our allowance for doubtful accounts for the periods presented:

	For the Three Months
	Ended March 31,
	2011			2010
Balance at beginning of period	$	18.4		$	16.8
Charged to costs and expenses		0.2			0.7
Deductions (1)		(5.1	)		--
Balance at end of period	$	13.5		$	17.5

(1) Primarily due to our reassessment of the allowance for doubtful accounts as a result of improved credit ratings of a significant customer, which reduced our exposure to potential uncollectibility.

Contingencies

Certain conditions may exist as of the date our financial statements are issued, which may result in a loss to us but which will only be resolved when one or more future events occur or fail to occur. Our management and its legal counsel assess such contingent liabilities, and such assessment inherently involves an exercise in judgment. In assessing loss contingencies related to legal proceedings that are pending against us or unasserted claims that may result in proceedings, our management and legal counsel evaluate the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.

If the assessment of a contingency indicates that it is probable that a material loss has been incurred and the amount of liability can be estimated, then the estimated liability would be accrued in our financial statements. If the assessment indicates that a potentially material loss contingency is not probable but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss (if determinable and material), is disclosed. Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed. See Note 14 for additional information regarding our contingencies.

Derivative Instruments

We use derivative instruments such as swaps, forwards and other contracts to manage price risks associated with inventories, firm commitments, interest rates and certain anticipated transactions. To qualify for hedge accounting, the item to be hedged must expose us to risk and the related derivative instrument must reduce that exposure and meet specific documentation requirements. We formally designate a derivative instrument as a hedge and document and assess the effectiveness of the hedge at inception and thereafter on a quarterly basis.

We apply the normal purchases/normal sales exception for certain of our derivative instruments, which precludes the recognition of changes in mark-to-market values for these items on our balance sheet or income statement. Revenues and costs for these transactions are recognized when volumes are physically delivered or received.

See Note 4 for additional information regarding our derivative instruments and related hedging activities.

Earnings Per Unit

Earnings per unit is based on the amount of income attributable to limited partners and the weighted-average number of units outstanding during the period. See Note 1 for information regarding the retroactive presentation of earnings per unit amounts for the first quarter of 2010 in connection with the Holdings Merger.

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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. Any future changes in facts and circumstances may require updated estimates, which, in turn, could have a significant impact on our financial statements.

Fair Value Information

The carrying amounts of cash and cash equivalents (including restricted cash), accounts receivable and accounts payable approximate their fair value. See Note 4 for fair value information associated with our derivative instruments.

The estimated fair value of our fixed-rate debt obligations were approximately $13.93 billion and $12.91 billion at March 31, 2011 and December 31, 2010, respectively. These values are based on quoted market prices for such debt or debt of similar terms and maturities. The carrying amounts of our variable-rate debt obligations reasonably approximate their fair values due to their variable interest rates.

We do not have any long-term investments in debt or equity securities carried at fair value. See Note 7 for summarized financial information of our investments accounted for using the equity method.

Restricted Cash

Restricted cash represents amounts held in connection with our commodity derivative instruments portfolio and related physical natural gas, crude oil and NGL purchases. Additional cash may be restricted to maintain this portfolio as commodity prices fluctuate or deposit requirements change. At March 31, 2011 and December 31, 2010, our restricted cash amounts were $191.6 million and $98.7 million, respectively. See Note 4 for information regarding derivative instruments and hedging activities.

Note 3. Equity-based Awards

An allocated portion of the fair value of EPCO’s equity-based awards is charged to us under the ASA. The following table summarizes the expense we recognized in connection with equity-based awards for the periods presented:

	For the Three Months Ended March 31,
	2011			2010
Restricted common unit awards	$	11.4		$	5.8
Unit option awards		0.9			0.7
Other (1)		(0.5	)		2.2
Total compensation expense	$	11.8		$	8.7

(1) Primarily consists of unit appreciation rights (“UARs”), phantom units and similar awards. Equity-based compensation expense for the three months ended March 31, 2011 includes a credit of $0.6 million associated with UARs. Also, the amount presented for 2010 consists of awards related to limited partnership interests in the Employee Partnerships.

The fair value of equity-classified awards (e.g., restricted common unit and unit option awards) is amortized to earnings over the requisite service or vesting period. Compensation expense for liability-classified awards (e.g., UARs and phantom units) is recognized over the requisite service or vesting period based on the fair value of the award remeasured at each reporting period. Liability-classified awards are settled in cash upon vesting.

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At March 31, 2011, EPCO’s significant long-term incentive plans applicable to us were the Enterprise Products 1998 Long-Term Incentive Plan (“1998 Plan”), the Amended and Restated 2008 Enterprise Products Long-Term Incentive Plan (“2008 Plan”) and the 2010 Duncan Energy Partners L.P. Long-Term Incentive Plan (“2010 Plan”). In addition, there were unvested awards outstanding under an inactive plan, the Enterprise Products 2006 TPP Long-Term Incentive Plan (“2006 Plan”).

The 1998 Plan provides for awards of our common units and other rights to our non-employee directors and to employees of EPCO and its affiliates providing services to us. Awards under the 1998 Plan may be granted in the form of unit options, restricted common units, phantom units and distribution equivalent rights (“DERs”). Up to 7,000,000 of our common units may be issued as awards under the 1998 Plan. After giving effect to awards granted under the plan through March 31, 2011, a total of 1,318,502 additional common units could be issued.

The 2008 Plan provides for awards of our common units and other rights to our non-employee directors and to consultants and employees of EPCO and its affiliates providing services to us. Awards under the 2008 Plan may be granted in the form of unit options, restricted common units, phantom units, UARs and DERs. Up to 10,000,000 of our common units may be issued as awards under the 2008 Plan. After giving effect to awards granted under the plan through March 31, 2011, a total of 4,685,352 additional common units could be issued.

The 2010 Plan provides for awards to employees, directors or consultants providing services to Duncan Energy Partners. Awards under the 2010 Plan may be granted in the form of options to purchase Duncan Energy Partners’ common units, restricted common units, UARs, phantom units and DERs. Up to 500,000 of Duncan Energy Partners’ common units may be issued as awards under the 2010 Plan. After giving effect to awards granted under the plan through March 31, 2011, a total of 489,986 additional common units could be issued. The Duncan Merger Agreement contains restrictions on the issuance of additional awards under the 2010 Plan. See Note 1 for information regarding the proposed merger of Duncan Energy Partners with a subsidiary of Enterprise.

Restricted Common Unit Awards

Restricted common unit awards allow recipients to acquire (at no cost to the recipient apart from service or other conditions) limited partner units once a defined vesting period expires, subject to customary forfeiture provisions. Restricted common unit awards may be denominated in our common units or those of Duncan Energy Partners depending on the issuer of the award. Restricted common unit awards issued prior to 2010 generally cliff vest four years from the date of grant. Beginning with awards issued in 2010, restricted common unit awards are typically subject to graded vesting provisions in which one-fourth of each award vests on the first, second, third and fourth anniversaries of the date of grant. As used in the context of EPCO’s long-term incentive plans, the term “restricted common unit” represents a time-vested unit. Such awards are non-vested until the required service period expires. Restricted common units are included in the number of common units presented on our Unaudited Condensed Consolidated Balance Sheets.

The fair value of a restricted common unit award is based on the market price per unit of the underlying security on the date of grant. Compensation expense is recognized based on the grant date fair value, net of an allowance for estimated forfeitures, over the requisite service or vesting period.

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The following table presents information regarding restricted common unit awards for the periods presented:

	Number of Units			Weighted- Average Grant Date Fair Value per Unit (1)
Enterprise restricted common unit awards:
Restricted common units at December 31, 2010		3,561,614		$	29.78
Granted (2)		1,350,530		$	43.70
Vested		(336,227	)	$	32.43
Forfeited		(16,475	)	$	34.37
Restricted common units at March 31, 2011		4,559,442		$	33.69

Duncan Energy Partners restricted common unit awards:
Restricted common units at December 31, 2010		--		$	--
Granted (3)		3,666		$	32.56
Vested (3)		(3,666	)	$	32.56
Restricted common units at March 31, 2011		--		$	--

(1) Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued. (2) The aggregate grant date fair value of restricted common unit awards issued in 2011 was $59.0 million based on a grant date market price of $43.70 per unit. Estimated forfeiture rates ranging between 4.6% and 17% were applied to these awards. (3) The aggregate grant date fair value of restricted common unit awards issued in 2011 was $0.1 million based on a grant date market price of $32.56 per unit. These awards vested upon issuance.

Typically, each recipient is also entitled to nonforfeitable cash distributions equal to the product of the number of restricted common units outstanding for the participant and the cash distribution per unit paid by the respective issuer. Since these restricted common units are participating securities, such distributions are included in cash distributions paid to partners (post-Holdings Merger) and cash distributions paid to noncontrolling interest (pre-Holdings Merger) as presented on our Unaudited Condensed Statements of Consolidated Cash Flows. The following table presents cash distributions paid with respect to our restricted common units and the total intrinsic value of restricted common units that vested during the periods indicated:

	For the Three Months
	Ended March 31,
	2011		2010
Cash distributions paid to restricted common unit holders	$	2.1	$	1.5
Total intrinsic value of restricted common unit awards vesting during period		14.7		1.1

For the EPCO group of companies, the unrecognized compensation cost associated with restricted common unit awards was an aggregate $86.5 million at March 31, 2011, of which our allocated share of the cost is currently estimated to be $84.1 million. We expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 2.2 years.

Unit Option Awards

EPCO’s long-term incentive plans provide for the issuance of non-qualified incentive options. These option awards may be denominated in our common units or those of Duncan Energy Partners depending on the issuer of the award. When issued, the exercise price of each option award may be no less than the market price of the underlying security on the date of grant. In general, these option awards have a vesting period of four years from the date of grant and expire between five and ten years after the date of grant.

The fair value of each unit option is estimated on the date of grant using a Black-Scholes option pricing model, which incorporates various assumptions including expected life of the option, risk-free interest rates, expected distribution yield of the underlying security, and expected unit price volatility. In

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general, our assumptions regarding the expected life of the options represents the period of time that the options are expected to be outstanding based on an analysis of our historical option activity. Our selection of risk-free interest rates is based on published yields for U.S. government securities with comparable terms. The unit price volatility and expected distribution yield assumptions are based on several factors, including an analysis of the underlying security’s historical market price and its distribution yield over a period of time equal to the expected life of the option, respectively. Compensation expense recorded in connection with unit options is based on the grant date fair value of such awards, net of an allowance for estimated forfeitures, over the requisite service or vesting period.

The following table presents unit option activity for the periods presented. As of March 31, 2011, only Enterprise has issued unit option awards.

	Number of Units		Weighted- Average Strike Price (dollars/unit)		Weighted- Average Remaining Contractual Term (in years)		Aggregate Intrinsic Value (1)
Unit options at December 31, 2010		3,753,420	$	28.08		3.6	$	--
Unit options at March 31, 2011		3,753,420	$	28.08		3.4	$	--
Options exercisable at March 31, 2011		--				--	$	--

(1) Aggregate intrinsic value reflects fully vested unit options at the date indicated. There were no vested unit options outstanding at either December 31, 2010 or March 31, 2011.

In order to fund its unit option-related obligations, EPCO may purchase common units at fair value either in the open market or directly from us. When employees exercise unit options, we reimburse EPCO for the cash difference between the strike price paid by the employee and the actual purchase price paid by EPCO for the units issued to the employee.

The following table presents supplemental information regarding our unit options during the periods presented:

	For the Three Months Ended March 31,
	2011		2010
Total intrinsic value of option awards exercised during period	$	--	$	0.9
Cash received from EPCO in connection with the exercise of unit option awards		--		0.6
Unit option-related reimbursements to EPCO		--		0.9

For the EPCO group of companies, the unrecognized compensation cost associated with unit option awards was an aggregate $5.8 million at March 31, 2011, of which our allocated share of the cost is currently estimated to be $5.6 million. We expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 2.1 years.

Other

Unit appreciation rights. UARs entitle the recipient to receive a cash payment on the vesting date of the award equal to the excess, if any, of the then current fair market value of the underlying security over the grant date fair value of the award. UARs are accounted for as liability awards. All of the UARs outstanding at March 31, 2011 are denominated in Enterprise common units.

The following tables present information regarding UARs for the periods presented:

UARs at December 31, 2010	170,104
Vested	(4,102	)
Settled or forfeited	(45,000	)
UARs at March 31, 2011	121,002

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		March 31, 2011				December 31, 2010
Accrued liability for UARs		$	0.3			$	1.0

At March 31, 2011, 121,002 UARs that had been granted under the 2006 Plan to certain employees of EPCO who work on our behalf were outstanding. These awards are subject to five-year cliff vesting requirements and are expected to settle in 2012. The grant date fair value with respect to these UARs is based on a unit price of $37.00 for our common units. If the employee resigns prior to vesting, the UARs are forfeited. Equity-based compensation expense for the three months ended March 31, 2011 and 2010 includes a credit of $0.6 million and an expense of $0.1 million, respectively, associated with UARs.

Limited partnership interests. EPCO granted its key employees who perform services on behalf of us, EPCO and other affiliated companies, limited partnership interests in the Employee Partnerships, which were privately held affiliates of EPCO. These partnerships were liquidated in August 2010. Prior to liquidation, the limited partnership interests entitled each holder to participate in the expected long-term appreciation in value of the equity securities owned by each Employee Partnership. Each Employee Partnership owned either Enterprise common units or Holdings’ units or a combination of both. Equity-based compensation expense for the three months ended March 31, 2010 includes $1.9 million of expense associated with these limited partnership interests.

Note 4. Derivative Instruments, Hedging Activities and Fair Value Measurements

In the normal course of our business operations, we are exposed to certain risks, including changes in interest rates and commodity prices. In order to manage risks associated with certain anticipated future transactions, we use derivative instruments. Derivatives are financial instruments whose fair value is determined by changes in a specified benchmark such as interest rates or commodity prices. Fair value is generally defined as the amount at which a derivative instrument could be exchanged in a current transaction between willing parties, not in a forced sale. Derivative instruments typically include futures, forward contracts, swaps, options and other instruments with similar characteristics. Substantially all of our derivatives are used for non-trading activities.

We are required to recognize derivative instruments at fair value as either assets or liabilities on our balance sheet. While all derivatives are required to be reported at fair value on the balance sheet, changes in fair value of the derivative instruments are reported in different ways, depending on the nature and effectiveness of the hedging activities to which they relate. After meeting specified conditions, a qualified derivative may be 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, gains and losses for 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 (loss) and is reclassified into earnings when the forecasted transaction affects earnings.

An effective hedge relationship is one in which the change in fair value of a derivative instrument can be expected to offset 80% to 125% of the changes in fair value of a hedged item at inception and throughout the life of the hedging relationship. The effective portion of a hedge relationship 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 relationship 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.

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A contract designated as a cash flow hedge of an anticipated transaction that is probable of not occurring is immediately recognized in earnings.

Certain of our derivative instruments do not qualify for hedge accounting treatment; therefore, they are accounted for using mark-to-market accounting.

Interest Rate Derivative Instruments

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

The following table summarizes our interest rate derivative instruments outstanding at March 31, 2011:

Hedged Transaction	Number and Type of Derivative(s) Employed	Notional Amount	Period of Hedge	Rate Swap	Accounting Treatment
Senior Notes C	1 fixed-to-floating swap	$100.0	1/04 to 2/13	6.4% to 2.3%	Fair value hedge
Senior Notes G	3 fixed-to-floating swaps	$300.0	10/04 to 10/14	5.6% to 1.4%	Fair value hedge
Senior Notes P	7 fixed-to-floating swaps	$400.0	6/09 to 8/12	4.6% to 2.7%	Fair value hedge
Senior Notes AA	10 fixed-to-floating swaps	$750.0	1/11 to 2/16	3.2% to 1.3%	Fair value hedge
Non-Hedged Swaps	2 floating-to-fixed swaps	$250.0	9/07 to 8/11	0.3% to 4.8%	Mark-to-market
Non-Hedged Swaps	6 floating-to-fixed swaps	$600.0	5/10 to 7/14	0.3% to 2.0%	Mark-to-market

Interest rate swaps exchange the stated interest rate paid on a notional amount of debt for the fixed or floating interest rate stipulated in the derivative instrument. Interest expense for the three months ended March 31, 2011 and 2010 reflects a decrease of $9.7 million and $1.4 million, respectively, attributable to interest rate swaps.

The following table summarizes our forward starting interest rate swaps, which hedge the expected underlying benchmark interest rates related to forecasted issuances of debt, outstanding at March 31, 2011:

Hedged Transaction	Number and Type of Derivatives Employed	Notional Amount	Expected Termination Date	Average Rate Locked	Accounting Treatment
Future debt offering	10 forward starting swaps	$500.0	2/12	4.5%	Cash flow hedge
Future debt offering	3 forward starting swaps	$150.0	8/12	4.0%	Cash flow hedge
Future debt offering	16 forward starting swaps	$1,000.0	3/13	3.7%	Cash flow hedge

In connection with the issuance of Senior Notes AA and BB (see Note 9), we settled three forward starting swaps in January 2011 having a notional amount of $250 million, resulting in a loss of $5.7 million. This loss will be amortized to earnings (as an increase in interest expense) using the effective interest method over the forecasted hedged period.

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Commodity Derivative Instruments

The prices of natural gas, NGLs, crude oil, refined products and certain petrochemical products are subject to fluctuations in response to changes in supply and demand, market conditions and a variety of additional factors that are beyond our control. In order to manage such price risks, we enter into commodity derivative instruments such as physical forward agreements, futures contracts, fixed-for-float swaps, basis swaps and options contracts. The following table summarizes our commodity derivative instruments outstanding at March 31, 2011:

	Volume (1)		Accounting
Derivative Purpose	Current	Long-Term (2)	Treatment
Derivatives designated as hedging instruments:
Enterprise:
Natural gas processing:
Forecasted natural gas purchases for plant thermal reduction (“PTR”) (3)	33.4 Bcf	n/a	Cash flow hedge
Forecasted sales of NGLs (4)	7.0 MMBbls	n/a	Cash flow hedge
Octane enhancement:
Forecasted purchases of NGLs (4)	0.1 MMBbls	n/a	Cash flow hedge
Forecasted sales of octane enhancement products	3.0 MMBbls	n/a	Cash flow hedge
Natural gas marketing:
Natural gas storage inventory management activities	4.1 Bcf	n/a	Fair value hedge
NGL marketing:
Forecasted purchases of NGLs and related hydrocarbon products	4.3 MMBbls	n/a	Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products	3.6 MMBbls	n/a	Cash flow hedge
Refined products marketing:
Forecasted purchases of refined products	4.0 MMBbls	0.1 MMBbls	Cash flow hedge
Forecasted sales of refined products	4.0 MMBbls	0.1 MMBbls	Cash flow hedge
Crude oil marketing:
Forecasted purchases of crude oil	3.6 MMBbls	n/a	Cash flow hedge
Forecasted sales of crude oil	5.2 MMBbls	n/a	Cash flow hedge
Derivatives not designated as hedging instruments:
Enterprise:
Natural gas risk management activities (5,6)	355.5 Bcf	55.6 Bcf	Mark-to-market
Refined products risk management activities (6)	4.5 MMBbls	n/a	Mark-to-market
Crude oil risk management activities (6)	7.3 MMBbls	n/a	Mark-to-market
Duncan Energy Partners:
Natural gas risk management activities (6)	2.4 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 reflects the absolute value of derivative notional volumes. (2) The maximum term for derivatives included in the long-term column is December 2013. (3) PTR represents the British thermal unit 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. (4) Forecasted sales of NGL volumes under Natural gas processing exclude 3.0 MMBbls of additional hedges executed under contracts that have been designated as normal sales agreements. (5) Current and long-term volumes include approximately 151.9 Bcf and 4.1 Bcf, respectively, of physical derivative instruments that are predominantly priced at an index plus a premium or minus a discount related to location differences. (6) Reflects the use of derivative instruments to manage risks associated with transportation, processing and storage assets.

Our predominant hedging strategies are: (i) hedging natural gas processing margins; (ii) hedging anticipated future contracted sales of NGLs, refined products and crude oil associated with volumes held in inventory and (iii) hedging the fair value of natural gas in inventory. The following information summarizes these hedging strategies:

§	The objective of our natural gas processing strategy is to hedge an amount of gross margin associated with our natural gas processing activities. We achieve this objective by using physical

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and financial instruments to lock in the purchase prices of natural gas consumed as PTR and the sales prices of the related NGL products. This program consists of (i) the forward sale of a portion of our expected equity NGL production at fixed prices through December 2011, which is achieved through the use of forward physical sales contracts and commodity derivative instruments and (ii) the purchase of commodity derivative instruments having a notional amount based on the volume of natural gas expected to be consumed as PTR in the production of such equity NGL production.

§	The objective of our NGL, refined products and crude oil sales hedging program is to hedge the margins of anticipated future sales of inventory by locking in sales prices through the use of forward physical sales contracts and commodity derivative instruments.

§	The objective of our natural gas inventory hedging program is to hedge the fair value of natural gas currently held in inventory by locking in the sales price of the inventory through the use of commodity derivative instruments.

Certain basis swaps, basis spread options and other financial derivative instruments not designated as hedging instruments are used to manage market risks associated with anticipated purchases and sales of natural gas necessary to optimize our owned and contractually committed transportation and storage capacity.

There is some uncertainty involved in the timing of these transactions often due to the development of more favorable profit opportunities or when spreads are insufficient to cover variable costs thus reducing the likelihood that the transactions will occur as originally forecasted. As a result of this timing uncertainty, these derivative instruments do not qualify for hedge accounting even though they are effective at managing the risk exposures of these assets.

The earnings volatility caused by fluctuations in non-cash, mark-to-market earnings cannot be predicted and the impact to earnings could be material.

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, 2011, the aggregate fair value of our over-the-counter derivative instruments in a net liability position was immaterial and not subject to any credit rating contingent feature. The potential for derivatives with contingent features to enter a net liability position may change in the future as commodity 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, 2011			December 31, 2010			March 31, 2011			December 31, 2010
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments
Interest rate derivatives	Other current assets	$	46.6	Other current assets	$	30.3	Other current liabilities	$	22.0	Other current liabilities	$	5.5
Interest rate derivatives	Other assets		82.0	Other assets		77.8	Other liabilities		18.9	Other liabilities		26.2
Total interest rate derivatives			128.6			108.1			40.9			31.7
Commodity derivatives	Other current assets		58.7	Other current assets		46.3	Other current liabilities		185.8	Other current liabilities		93.0
Commodity derivatives	Other assets		2.8	Other assets		1.0	Other liabilities		2.7	Other liabilities		1.7
Total commodity derivatives (1)			61.5			47.3			188.5			94.7
Total derivatives designated as hedging instruments		$	190.1		$	155.4		$	229.4		$	126.4

Derivatives not designated as hedging instruments
Interest rate derivatives	Other current assets	$	--	Other current assets	$	--	Other current liabilities	$	18.1	Other current liabilities	$	21.0
Interest rate derivatives	Other assets		3.0	Other assets		--	Other liabilities		--	Other liabilities		0.9
Total interest rate derivatives			3.0			--			18.1			21.9
Commodity derivatives	Other current assets		50.9	Other current assets		38.6	Other current liabilities		61.1	Other current liabilities		41.2
Commodity derivatives	Other assets		3.8	Other assets		4.5	Other liabilities		1.5	Other liabilities		5.4
Total commodity derivatives			54.7			43.1			62.6			46.6
Foreign currency derivatives	Other assets		--	Other assets		0.3	Other liabilities		--	Other liabilities		0.1
Total derivatives not designated as hedging instruments		$	57.7		$	43.4		$	80.7		$	68.6

(1) Represents commodity derivative instrument transactions that have either 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.

The following tables present the effect of our derivative instruments designated as fair value hedges on our Unaudited Condensed Statements of Consolidated Operations for the periods presented:

Derivatives in Fair Value Hedging Relationships	Location	Gain/(Loss) Recognized in Income on Derivative
		For the Three Months Ended March 31,
		2011			2010
Interest rate derivatives	Interest expense	$	(12.3	)	$	7.4
Commodity derivatives	Revenue		0.3			(1.8	)
Total		$	(12.0	)	$	5.6

Derivatives in Fair Value Hedging Relationships	Location	Gain/(Loss) Recognized in Income on Hedged Item
		For the Three Months Ended March 31,
		2011			2010
Interest rate derivatives	Interest expense	$	11.3		$	(7.4	)
Commodity derivatives	Revenue		(1.3	)		1.9
Total		$	10.0		$	(5.5	)

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The following tables present the effect of our derivative instruments designated as cash flow hedges on our Unaudited Condensed Statements of Consolidated Comprehensive Income and Consolidated Operations for the periods presented:

Derivatives in Cash Flow Hedging Relationships	Change in Value Recognized in Other Comprehensive Income/(Loss) on Derivative – Effective Portion
	For the Three Months Ended March 31,
	2011			2010
Interest rate derivatives	$	14.1		$	(7.5	)
Commodity derivatives – Revenue (1)		(155.4	)		(7.1	)
Commodity derivatives – Operating costs and expenses		4.0			(51.8	)
Foreign currency derivatives		--			(0.1	)
Total	$	(137.3	)	$	(66.5	)

(1) The increase in other comprehensive loss for the first quarter of 2011 is primarily due to the impact of rising crude oil, refined products and NGL prices on our derivative instruments designated as cash flow hedges of future physical sales transactions.

Derivatives in Cash Flow Hedging Relationships	Location	Gain/(Loss) Reclassified from Accumulated Other Comprehensive Income/(Loss) to Income (Effective Portion)
		For the Three Months
		Ended March 31,
		2011			2010
Interest rate derivatives	Interest expense	$	(1.5	)	$	(6.1	)
Commodity derivatives	Revenue		(69.2	)		(15.8	)
Commodity derivatives	Operating costs and expenses		0.3			(0.7	)
Foreign currency derivatives	Other income		--			0.3
Total		$	(70.4	)	$	(22.3	)

Derivatives in Cash Flow Hedging Relationships	Location	Gain/(Loss) Recognized in Income on Ineffective Portion of Derivative
		For the Three Months
		Ended March 31,
		2011			2010
Commodity derivatives	Revenue	$	(0.1	)	$	--
Commodity derivatives	Operating costs and expenses		--			(0.6	)
Total		$	(0.1	)	$	(0.6	)

Over the next twelve months, we expect to reclassify $6.5 million of losses attributable to interest rate derivative instruments from accumulated other comprehensive loss to earnings as an increase in interest expense. Likewise, we expect to reclassify $114.3 million of losses attributable to commodity derivative instruments from accumulated other comprehensive loss to earnings, $26.4 million as an increase in operating costs and expenses and $87.9 million as a decrease in revenue.

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The following table presents the effect of our derivative instruments not designated as hedging instruments on our Unaudited Condensed Statements of Consolidated Operations for the periods presented:

Derivatives Not Designated as Hedging Instruments	Location	Gain/(Loss) Recognized in Income on Derivative
		For the Three Months
		Ended March 31,
		2011			2010
Interest rate derivatives	Interest expense	$	(2.1	)	$	--
Commodity derivatives	Revenue		3.8			3.9
Commodity derivatives	Operating costs and expenses		--			(1.5	)
Total		$	1.7		$	2.4

Fair Value Measurements

Fair value is defined 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. Our fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. Recognized valuation techniques employ inputs such as product prices, operating costs, discount factors and business growth rates. These inputs may be either readily observable, corroborated by market data or generally unobservable. In developing our estimates of fair value, we endeavor to utilize the best information available and apply market-based data to the extent possible. Accordingly, we utilize valuation techniques (such as the market approach) that maximize the use of observable inputs and minimize the use of unobservable inputs.

A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements based on the observability of inputs used to estimate such fair values. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). At each balance sheet reporting date, we categorize our financial assets and liabilities using this hierarchy.

The following table sets forth, by level within the fair value hierarchy, the carrying values of our financial assets and liabilities at the date indicated. These assets and liabilities are measured on a recurring basis and are classified within the table based on the lowest level of input that is significant to their respective fair value. Our assessment of the relative significance of such inputs requires judgment.

	At March 31, 2011
	Quoted Prices
	in Active
	Markets for		Significant		Significant
	Identical Assets		Observable		Unobservable
	and Liabilities		Inputs		Inputs
	(Level 1)		(Level 2)		(Level 3)		Total
Financial assets:
Interest rate derivatives	$	--	$	131.6	$	--	$	131.6
Commodity derivatives		47.1		63.6		5.5		116.2
Total	$	47.1	$	195.2	$	5.5	$	247.8

Financial liabilities:
Interest rate derivatives	$	--	$	59.0	$	--	$	59.0
Commodity derivatives		137.2		108.8		5.1		251.1
Total	$	137.2	$	167.8	$	5.1	$	310.1

The characteristics of fair value amounts classified within each level of the hierarchy are described as follows:

§	Level 1 fair values are based on quoted prices, which are available in active markets for identical assets or liabilities as of the measurement date. Active markets are defined as those in which

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transactions for identical assets or liabilities occur with sufficient frequency so as to provide pricing information on an ongoing basis (e.g., the New York Mercantile Exchange). Our Level 1 fair values consist of financial assets and liabilities such as exchange-traded commodity derivative instruments.

Level 2 fair values are based on pricing inputs other than quoted prices in active markets (as reflected in Level 1 fair values) and are either directly or indirectly observable as of the measurement date. Level 2 fair values include instruments that are valued using financial models or other appropriate valuation methodologies. Such financial models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, the time value of money, volatility factors, current market and contractual prices for the underlying instruments and other relevant economic measures. Substantially all of these assumptions (i) are observable in the marketplace throughout the full term of the instrument; (ii) can be derived from observable data; or (iii) are validated by inputs other than quoted prices (e.g., interest rate and yield curves at commonly quoted intervals). Our Level 2 fair values primarily consist of commodity derivative instruments such as forwards, swaps and other instruments transacted on an exchange or over-the-counter and interest rate derivative instruments. The fair values of these derivative instruments are based on observable price quotes for similar products and locations. The fair value of our interest rate derivatives are determined using financial models that incorporate the implied forward London Interbank Offered Rate yield curve for the same period as the future interest swap settlements.

Level 3 fair values are based on unobservable inputs. Unobservable inputs are used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. Unobservable inputs reflect management’s ideas about the assumptions that market participants would use in pricing an asset or liability (including assumptions about risk). Unobservable inputs are based on the best information available to us in the circumstances, which might include our internally developed data. Level 3 inputs are typically used in connection with internally developed valuation methodologies where we make our best estimate of an instrument’s fair value. Our Level 3 fair values primarily consist of ethane, normal butane and natural gasoline-based contracts with terms greater than one year and certain options used to hedge natural gas storage inventory and transportation capacities. In addition, we often rely on price quotes from reputable brokers who publish price quotes on certain products and compare these prices to other reputable brokers for the same products in the same markets whenever possible. These prices, when combined with data from our commodity derivative instruments, are used in our models to determine the fair value of such instruments.

Transfers within the fair value hierarchy routinely occur for certain term contracts as prices and other inputs used for the valuation of future delivery periods become more observable with the passage of time. Other transfers are made periodically in response to changing market conditions that affect liquidity, price observability and other inputs used in determining valuations. Based on an assessment completed during the first quarter of 2011, we transferred ethane, normal butane and natural gasoline-based contracts with terms ranging from two months to one year from Level 3 to Level 2. These transfers were made after a sustained increase in the observability of forward prices for these energy commodity products relative to the date range stated above as demonstrated by narrowing bid/offer spreads, higher transaction volumes and more activity and liquidity for these types of contracts. With the exception of the transfers noted above, no other transfers were made between fair value levels during the quarter.

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

	For the Three Months
	Ended March 31,
	2011			2010
Balance, January 1	$	(25.9	)	$	5.7
Total gains (losses) included in:
Net income (1)		(0.5	)		(3.6	)
Other comprehensive income (loss)		16.2			(8.3	)
Settlements		0.8			3.6
Transfers out of Level 3 (2)		9.8			--
Balance, March 31	$	0.4		$	(2.6	)

(1) There were unrealized losses of $0.2 million and unrealized gains of $0.5 million included in these amounts for the three months ended March 31, 2011 and 2010, respectively. (2) Transfers out of Level 3 into Level 2 were primarily due to the change in observability of forward NGL prices as described above.

Nonfinancial Assets and Liabilities

During the three months ended March 31, 2010, certain pipeline assets recorded as property, plant and equipment were adjusted to fair value based on the present value of expected future cash flows (Level 3), resulting in nonrecurring fair value adjustments (i.e., non-cash asset impairment charges) totaling $1.5 million. The non-cash asset impairment charges we recorded during the three months ended March 31, 2010 are a component of operating costs and expenses.

Note 5. Inventories

Our inventory amounts were as follows at the dates indicated:

	March 31, 2011		December 31, 2010
Working inventory (1)	$	525.4	$	690.9
Forward sales inventory (2)		275.4		443.1
Total inventory	$	800.8	$	1,134.0

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

In those instances where we take ownership of inventory volumes through percent-of-liquids contracts and similar arrangements (as opposed to actually purchasing volumes for cash from third parties), these volumes are valued at market-based prices during the month in which they are acquired. In general, our inventory levels have decreased since December 31, 2010 due to a reduction in propane and butane inventories attributable to seasonal supply and demand fluctuations and a reduction in inventories attributable to the settlement of forward sales contracts.

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The following table summarizes our cost of sales and lower of cost or market (“LCM”) adjustment amounts for the periods presented:

	For the Three Months Ended March 31,
	2011		2010
Cost of sales (1)	$	8,819.3	$	7,342.3
LCM adjustments		1.2		5.7
(1) Cost of sales is a component of “Operating costs and expenses,” as presented on our Unaudited Condensed Statements of Consolidated Operations. Quarter-to-quarter fluctuations in these amounts are primarily due to changes in energy commodity prices and sales volumes associated with our marketing activities.

Note 6. Property, Plant and Equipment

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

	Estimated Useful Life in Years	March 31, 2011		December 31, 2010
Plants, pipelines and facilities (1)	3-45 (6)	$	19,552.3	$	19,388.4
Underground and other storage facilities (2)	5-40 (7)		1,491.3		1,477.8
Platforms and facilities (3)	20-31		637.5		637.5
Transportation equipment (4)	3-10		120.0		119.1
Marine vessels (5)	15-30		563.7		560.0
Land			123.4		123.4
Construction in progress			2,168.8		1,607.2
Total			24,657.0		23,913.4
Less accumulated depreciation			4,764.1		4,580.5
Property, plant and equipment, net		$	19,892.9	$	19,332.9

(1) Plants and pipelines include processing plants; NGL, natural gas, crude oil and petrochemical and refined products 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; above ground storage tanks; water wells and related assets. (3) Platforms and facilities include offshore platforms and related facilities and other associated assets located in the Gulf of Mexico. (4) Transportation equipment includes tractor-trailer tank trucks and other vehicles and similar assets used in our operations. (5) Marine vessels include tow boats, barges and related equipment used in our marine transportation business. (6) In general, the estimated useful lives of major assets within this category are: processing plants, 20-35 years; pipelines and related equipment, 5-45 years; terminal facilities, 10-35 years; office furniture and equipment, 3-20 years; buildings, 20-40 years; and laboratory and shop equipment, 5-35 years. (7) In general, the estimated useful lives of assets within this category are: underground storage facilities, 5-35 years; storage tanks, 10-40 years; and water wells, 5-35 years.

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

	For the Three Months
	Ended March 31,
	2011		2010
Depreciation expense (1)	$	186.5	$	180.3
Capitalized interest (2)		17.2		10.5
(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.

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Asset Retirement Obligations

We record asset retirement obligations (“AROs”) related to legal requirements to perform retirement activities as specified in contractual arrangements and/or governmental regulations. In general, our contractual AROs primarily result from right-of-way agreements associated with our pipeline operations and leases of plant sites. In addition, we have recorded AROs based on government regulations triggered by the abandonment or retirement of (i) certain underground storage facilities and related above-ground brine storage pits, (ii) offshore Gulf of Mexico assets and (iii) certain marine vessels. Our AROs may also result from regulatory requirements associated with the renovation or demolition of certain assets containing hazardous substances such as asbestos.

The following table presents information regarding our AROs since December 31, 2010:

ARO liability balance, December 31, 2010	$	97.1
Revisions in estimated cash flows		1.0
Accretion expense		1.6
Liabilities settled during period		(0.2	)
ARO liability balance, March 31, 2011	$	99.5

Property, plant and equipment at March 31, 2011 and December 31, 2010 includes $34.2 million and $34.1 million, respectively, of asset retirement costs capitalized as an increase in the associated long-lived asset. The following table presents forecast accretion expense associated with our AROs for the years presented:

Remainder of 2011				2012				2013				2014				2015
$	4.8			$	5.0			$	5.4			$	5.8			$	5.5

Certain of our unconsolidated affiliates have AROs recorded at March 31, 2011 and December 31, 2010 relating to contractual agreements and regulatory requirements. These amounts are immaterial to our consolidated financial statements.

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Note 7. Investments in Unconsolidated Affiliates

We own interests in a number of related businesses that are accounted for using the equity method of accounting. We group our investments in unconsolidated affiliates 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 unconsolidated affiliates by business segment at the dates indicated:

	Ownership Interest at March 31, 2011	March 31, 2011		December 31, 2010
NGL Pipelines & Services:
Venice Energy Service Company, L.L.C.	13.1%	$	33.5	$	31.9
K/D/S Promix, L.L.C. (“Promix”)	50%		42.4		43.5
Baton Rouge Fractionators LLC	32.2%		21.7		21.9
Skelly-Belvieu Pipeline Company, L.L.C.	50%		34.0		34.2
Onshore Natural Gas Pipelines & Services:
Evangeline (1)	49.5%		6.7		6.4
White River Hub, LLC (“White River Hub”)	50%		26.1		26.2
Onshore Crude Oil Pipelines & Services:
Seaway Crude Pipeline Company (“Seaway”)	50%		171.7		172.2
Offshore Pipelines & Services:
Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”)	36%		55.1		57.2
Cameron Highway Oil Pipeline Company	50%		231.8		233.7
Deepwater Gateway, L.L.C.	50%		97.7		98.4
Neptune Pipeline Company, L.L.C.	25.7%		53.0		53.9
Petrochemical & Refined Products Services:
Baton Rouge Propylene Concentrator, LLC	30%		10.0		10.1
Centennial Pipeline LLC (“Centennial”)	50%		61.5		63.1
Other (2)	Various		3.6		3.6
Other Investments:
Energy Transfer Equity	17.5%		1,421.1		1,436.8
Total		$	2,269.9	$	2,293.1

(1) Evangeline refers to our ownership interests in Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp., collectively. (2) Other unconsolidated affiliates include a 50% interest in a propylene pipeline extending from Mont Belvieu, Texas to La Porte, Texas and a 25% interest in a company that provides logistics communications solutions between petroleum pipelines and their customers.

The following table presents our equity in income (loss) of unconsolidated affiliates by business segment for the periods presented:

	For the Three Months
	Ended March 31,
	2011			2010
NGL Pipelines & Services	$	5.9		$	3.3
Onshore Natural Gas Pipelines & Services		1.2			1.3
Onshore Crude Oil Pipelines & Services		(0.5	)		2.3
Offshore Pipelines & Services		8.3			11.8
Petrochemical & Refined Products Services		(5.0	)		(2.7	)
Other Investments		6.3			10.6
Total	$	16.2		$	26.6

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On occasion, the price we pay to acquire an ownership interest in a company exceeds the underlying book value of the capital accounts we acquire. Such excess cost amounts are included within the carrying values of our investments in unconsolidated affiliates. The following table presents the unamortized excess cost amounts by business segment at the dates indicated:

	March 31,		December 31,
	2011		2010
NGL Pipelines & Services	$	25.4	$	25.7
Onshore Crude Oil Pipelines & Services		19.7		19.7
Offshore Pipelines & Services		15.7		16.0
Petrochemical & Refined Products Services		3.0		3.0
Other Investments (1)		1,516.0		1,525.1
Total	$	1,579.8	$	1,589.5

(1) Holdings’ investment in Energy Transfer Equity exceeded its share of the historical cost of the underlying net assets of such investee by $1.66 billion in May 2007. At March 31, 2011, this basis differential decreased to $1.52 billion and consisted of the following: $481.3 million attributed to fixed assets; $509.7 million attributed to the IDRs (an indefinite-life intangible asset) held by Energy Transfer Equity in the cash flows of ETP; $191.7 million attributed to amortizable intangible assets and $333.3 million attributed to equity method goodwill. These unamortized excess cost amounts are being amortized over their estimated economic lives of 20-27 years.

We amortize such excess cost amounts as a reduction in equity earnings in a manner similar to depreciation. The following table presents our amortization of such excess cost amounts by business segment for the periods presented:

	For the Three Months
	Ended March 31,
	2011		2010
NGL Pipelines & Services	$	0.3	$	0.2
Onshore Crude Oil Pipelines & Services		0.2		0.2
Offshore Pipelines & Services		0.3		0.3
Petrochemical & Refined Products Services		--		0.7
Other Investments		9.1		9.2
Total	$	9.9	$	10.6

Summarized Income Statement Information of Unconsolidated Affiliates

The following table presents unaudited income statement information (on a 100% basis) of our unconsolidated affiliates, aggregated by the business segments to which they relate, for the periods presented:

	Summarized Income Statement Information for the Three Months Ended
	March 31, 2011								March 31, 2010
			Operating			Net					Operating		Net
	Revenues		Income			Income (Loss)			Revenues		Income		Income (Loss)
NGL Pipelines & Services	$	100.1	$	23.4		$	23.4		$	74.8	$	13.1	$	13.0
Onshore Natural Gas Pipelines & Services		35.5		2.6			2.6			42.3		2.5		2.4
Onshore Crude Oil Pipelines & Services		11.2		0.5			0.5			18.5		7.3		7.3
Offshore Pipelines & Services		46.3		18.9			18.7			55.0		29.2		28.7
Petrochemical & Refined Products Services		10.1		(7.0	)		(9.2	)		8.6