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 September 30, 2010

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: 1-32610

ENTERPRISE GP HOLDINGS L.P.

(Exact name of Registrant as Specified in Its Charter)

Delaware		13-4297064
(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 139,195,064 Units of Enterprise GP Holdings L.P. outstanding at November 1, 2010. Our Units trade on the New York Stock Exchange under the ticker symbol “EPE.”

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ENTERPRISE GP HOLDINGS 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 and Basis of Presentation	9
	2. General Accounting Matters	12
	3. Equity-based Awards	14
	4. Derivative Instruments, Hedging Activities and Fair Value Measurements	17
	5. Inventories	26
	6. Property, Plant and Equipment	27
	7. Investments in Unconsolidated Affiliates	29
	8. Business Combinations	31
	9. Intangible Assets and Goodwill	34
	10. Debt Obligations	37
	11. Equity and Distributions	40
	12. Business Segments	44
	13. Related Party Transactions	48
	14. Earnings Per Unit	52
	15. Commitments and Contingencies	53
	16. Significant Risks and Uncertainties	57
	17. Supplemental Cash Flow Information	59
	18. Condensed Parent Company Financial Information	59
	19. Subsequent Event	64
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	65
Item 3.	Quantitative and Qualitative Disclosures about Market Risk.	95
Item 4.	Controls and Procedures.	97

PART II. OTHER INFORMATION.
Item 1.	Legal Proceedings.	98
Item 1A.	Risk Factors.	98
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	101
Item 3.	Defaults upon Senior Securities.	101
Item 4.	(Removed and Reserved).	101
Item 5.	Other Information.	101
Item 6.	Exhibits.	101

Signatures		109

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PART I. FINANCIAL INFORMATION.

Item 1. Financial Statements.

ENTERPRISE GP HOLDINGS L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

	September 30,			December 31,
ASSETS	2010			2009
Current assets:
Cash and cash equivalents	$	42.9		$	55.3
Restricted cash		32.5			63.6
Accounts and notes receivable – trade, net of allowance for doubtful accounts of $18.1 at September 30, 2010 and $16.8 at December 31, 2009		3,036.6			3,099.0
Accounts receivable – related parties		31.0			38.4
Inventories		1,210.0			711.9
Prepaid and other current assets		292.9			281.4
Total current assets		4,645.9			4,249.6
Property, plant and equipment, net		18,810.0			17,689.2
Investments in unconsolidated affiliates		2,331.2			2,416.2
Intangible assets, net of accumulated amortization of $894.7 at September 30, 2010 and $795.0 at December 31, 2009		1,860.3			1,064.8
Goodwill		2,052.7			2,018.3
Other assets		246.5			248.2
Total assets	$	29,946.6		$	27,686.3

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable – trade	$	519.4		$	410.6
Accounts payable – related parties		99.0			70.8
Accrued product payables		3,338.6			3,393.0
Accrued interest		178.2			231.7
Other current liabilities		494.1			447.8
Total current liabilities		4,629.3			4,553.9
Long-term debt (see Note 10)		13,790.1			12,427.9
Deferred tax liabilities		75.0			71.7
Other long-term liabilities		277.3			159.7
Commitments and contingencies
Equity: (see Note 11)
Enterprise GP Holdings L.P. partners’ equity:
Limited Partners:
Units (139,195,064 Units outstanding at September 30, 2010 and 139,191,640 Units outstanding at December 31, 2009)		1,909.6			1,972.4
General partner		**			**
Accumulated other comprehensive loss		(46.0	)		(33.3	)
Total Enterprise GP Holdings L.P. partners’ equity		1,863.6			1,939.1
Noncontrolling interest		9,311.3			8,534.0
Total equity		11,174.9			10,473.1
Total liabilities and equity	$	29,946.6		$	27,686.3

See Notes to Unaudited Condensed Consolidated Financial Statements.

** Amount is negligible.

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ENTERPRISE GP HOLDINGS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS

(Dollars in millions, except per unit amounts)

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2010			2009*			2010			2009*
Revenues:
Third parties	$	7,934.1		$	6,679.0		$	23,673.6		$	16,688.4
Related parties		133.7			110.4			482.1			422.2
Total revenues (see Note 12)		8,067.8			6,789.4			24,155.7			17,110.6
Costs and expenses:
Operating costs and expenses:
Third parties		7,117.1			6,128.2			21,441.1			15,046.4
Related parties		343.0			267.6			965.1			750.5
Total operating costs and expenses		7,460.1			6,395.8			22,406.2			15,796.9
General and administrative costs:
Third parties		28.8			28.3			61.5			63.4
Related parties		41.3			26.0			89.4			78.6
Total general and administrative costs		70.1			54.3			150.9			142.0
Total costs and expenses (see Note 12)		7,530.2			6,450.1			22,557.1			15,938.9
Equity in income of unconsolidated affiliates		5.6			14.1			43.2			57.7
Operating income		543.2			353.4			1,641.8			1,229.4
Other income (expense):
Interest expense		(192.0	)		(170.9	)		(529.1	)		(508.2	)
Interest income		0.9			0.4			1.6			2.0
Other, net		0.4			(0.3	)		0.2			0.2
Total other expense, net		(190.7	)		(170.8	)		(527.3	)		(506.0	)
Income before provision for income taxes		352.5			182.6			1,114.5			723.4
Provision for income taxes		(4.9	)		(7.7	)		(20.1	)		(26.8	)
Net income		347.6			174.9			1,094.4			696.6
Net income attributable to noncontrolling interests		(310.6	)		(149.6	)		(933.4	)		(569.3	)
Net income attributable to Enterprise GP Holdings L.P.	$	37.0		$	25.3		$	161.0		$	127.3

Allocation of net income attributable to
Enterprise GP Holdings L.P.:
Limited partners	$	37.0		$	25.3		$	161.0		$	127.3
General partner	$	**		$	**		$	**		$	**

Basic and diluted earnings per Unit (see Note 14)	$	0.27		$	0.18		$	1.16		$	0.93

See Notes to Unaudited Condensed Consolidated Financial Statements.

*See Note 1 for information regarding these recast amounts and basis of financial statement presentation.

** Amount is negligible.

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ENTERPRISE GP HOLDINGS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED

COMPREHENSIVE INCOME

(Dollars in millions)

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2010			2009*			2010			2009*

Net income	$	347.6		$	174.9		$	1,094.4		$	696.6
Other comprehensive income (loss):
Cash flow hedges:
Commodity derivative instrument losses during period		(64.1	)		(8.3	)		(31.0	)		(146.9	)
Reclassification adjustment for (gains) losses included in net income related to commodity derivative instruments		(25.6	)		77.8			(10.6	)		176.3
Interest rate derivative instrument gains (losses) during period		(81.6	)		(11.3	)		(168.4	)		3.0
Reclassification adjustment for losses included in net income related to interest rate derivative instruments		8.1			6.7			21.4			20.3
Foreign currency derivative gains (losses) during period		0.1			0.2			(0.1	)		(10.3	)
Reclassification adjustment for gains included in net income related to foreign currency derivative instruments		--			--			(0.3	)		--
Total cash flow hedges		(163.1	)		65.1			(189.0	)		42.4
Foreign currency translation adjustment		0.5			1.1			0.3			1.7
Change in funded status of pension and postretirement plans, net of tax		--			--			(0.9	)		--
Proportionate share of other comprehensive income (loss) of unconsolidated affiliate		11.9			(1.7	)		11.5			0.1
Total other comprehensive income (loss)		(150.7	)		64.5			(178.1	)		44.2
Comprehensive income		196.9			239.4			916.3			740.8
Comprehensive income attributable to noncontrolling interests		(167.2	)		(211.7	)		(768.0	)		(602.4	)
Comprehensive income attributable to Enterprise GP Holdings L.P.	$	29.7		$	27.7		$	148.3		$	138.4

See Notes to Unaudited Condensed Consolidated Financial Statements.

*See Note 1 for information regarding these recast amounts and basis of financial statement presentation.

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ENTERPRISE GP HOLDINGS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Dollars in millions)

	For the Nine Months
	Ended September 30,
	2010			2009*
Operating activities:
Net income	$	1,094.4		$	696.6
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		709.1			622.2
Non-cash asset impairment charges		1.5			26.3
Equity in income of unconsolidated affiliates		(43.2	)		(57.7	)
Distributions received from unconsolidated affiliates		146.0			117.0
Operating lease expenses paid by EPCO		0.5			0.5
Gains from asset sales and related transactions		(45.4	)		(0.5	)
Loss on forfeiture of investment in Texas Offshore Port System		--			68.4
Deferred income tax expense		3.7			2.5
Changes in fair market value of derivative instruments		(10.8	)		9.8
Effect of pension settlement recognition		(0.2	)		(0.1	)
Net effect of changes in operating accounts (see Note 17)		(411.8	)		(574.9	)
Net cash flows provided by operating activities		1,443.8			910.1
Investing activities:
Capital expenditures		(1,405.1	)		(1,100.4	)
Contributions in aid of construction costs		13.9			12.8
Decrease in restricted cash		37.9			100.8
Cash used for business combinations (see Note 8)		(1,233.0	)		(74.5	)
Investments in unconsolidated affiliates		(6.3	)		(14.7	)
Proceeds from asset sales and related transactions		89.6			2.9
Other investing activities		1.5			0.1
Cash used in investing activities		(2,501.5	)		(1,073.0	)
Financing activities:
Borrowings under debt agreements		4,170.3			5,037.7
Repayments of debt		(2,816.6	)		(4,666.5	)
Debt issuance costs		(14.7	)		(5.2	)
Cash distributions paid to partners		(227.6	)		(195.0	)
Cash distributions paid to noncontrolling interests		(1,099.0	)		(980.0	)
Cash contributions from noncontrolling interests		1,034.4			991.9
Acquisition of treasury units by subsidiary		(3.1	)		(1.8	)
Other financing activities		1.3			--
Cash provided by financing activities		1,045.0			181.1
Effect of exchange rate changes on cash		0.3			(0.4	)
Net change in cash and cash equivalents		(12.7	)		18.2
Cash and cash equivalents, January 1		55.3			56.8
Cash and cash equivalents, September 30	$	42.9		$	74.6

See Notes to Unaudited Condensed Consolidated Financial Statements.

*See Note 1 for information regarding these recast amounts and basis of financial statement presentation.

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ENTERPRISE GP HOLDINGS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY

(See Note 11 for Unit History and Detail of Accumulated Other Comprehensive Loss)

(Dollars in millions)

	Enterprise GP Holdings L.P.
	Limited Partners			General Partner		Accumulated Other Comprehensive Loss			Noncontrolling Interest			Total
Balance, December 31, 2009	$	1,972.4		$	**	$	(33.3	)	$	8,534.0		$	10,473.1
Net income		161.0			**		--			933.4			1,094.4
Operating lease expenses paid by EPCO		--			--		--			0.5			0.5
Cash distributions paid to partners		(227.6	)		**		--			--			(227.6	)
Cash distributions paid to noncontrolling interests		--			--		--			(1,099.0	)		(1,099.0	)
Cash contributions from noncontrolling interests		--			--		--			1,034.4			1,034.4
Amortization of equity awards		3.8			--		--			45.9			49.7
Acquisition of treasury units by subsidiary		--			--		--			(3.1	)		(3.1	)
Issuance of common units by subsidiary to EPCO in exchange for equity interests in trucking business		--			--		--			30.6			30.6
Foreign currency translation adjustment		--			--		--			0.3			0.3
Change in fair value of cash flow hedges		--			--		(24.2	)		(164.8	)		(189.0	)
Proportionate share of other comprehensive income of unconsolidated affiliates		--			--		11.5			--			11.5
Other		--			--		--			(0.9	)		(0.9	)
Balance, September 30, 2010	$	1,909.6		$	**	$	(46.0	)	$	9,311.3		$	11,174.9

	Enterprise GP Holdings L.P.
	Limited Partners			General Partner		Accumulated Other Comprehensive Loss			Noncontrolling Interest			Total
Balance, December 31, 2008*	$	2,031.2		$	**	$	(53.2	)	$	7,781.4		$	9,759.4
Net income		127.3			**		--			569.3			696.6
Operating lease expenses paid by EPCO		--			--		--			0.5			0.5
Cash distributions paid to partners		(195.0	)		**		--			--			(195.0	)
Cash distributions paid to noncontrolling interests		--			--		--			(980.0	)		(980.0	)
Deconsolidation of Texas Offshore Port System (see Note 1)		--			--		--			(33.4	)		(33.4	)
Cash contributions from noncontrolling interests		--			--		--			991.9			991.9
Amortization of equity awards		1.8			--		--			16.7			18.5
Acquisition of treasury units by subsidiary		--			--		--			(1.8	)		(1.8	)
Foreign currency translation adjustment		--			--		0.1			1.6			1.7
Change in fair value of cash flow hedges		--			--		10.9			31.5			42.4
Proportionate share of other comprehensive loss of unconsolidated affiliates		--			--		0.1			--			0.1
Other		--			--		--			(0.2	)		(0.2	)
Balance, September 30, 2009*	$	1,965.3		$	**	$	(42.1	)	$	8,377.5		$	10,300.7

See Notes to Unaudited Condensed Consolidated Financial Statements.

*See Note 1 for information regarding these recast amounts and basis of financial statement presentation.

** Amount is negligible.

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Except unit-related amounts, or as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnotes 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,” “Holdings” or the “Partnership” are intended to mean the business and operations of Enterprise GP Holdings L.P. and its consolidated subsidiaries.

References to the “Parent Company” mean Enterprise GP Holdings L.P., individually as the parent company, and not on a consolidated basis. On September 3, 2010, the Parent Company and Enterprise Products Partners (as defined below) entered into an Agreement and Plan of Merger (the “Holdings Merger Agreement”) that would, if approved by the Parent Company’s unitholders, result in the merger of the Parent Company with a wholly owned subsidiary of Enterprise Products Partners through a unit-for-unit exchange (the “Holdings Merger”). See Note 1 for additional information regarding the proposed Holdings Merger.

References to “EPE Holdings” mean EPE Holdings, LLC, which is the general partner of the Parent Company and a wholly owned subsidiary of Dan Duncan LLC. The membership interests of Dan Duncan LLC are owned of record by a voting trust formed on April 26, 2006, pursuant to the Dan Duncan LLC Voting Trust Agreement dated April 26, 2006 (the “DD LLC Voting Trust Agreement”), among Dan Duncan LLC and Dan L. Duncan (as the record owner of all of the membership interests of Dan Duncan LLC immediately prior to the entering into of the DD LLC Voting Trust Agreement and as the initial sole voting trustee).

Immediately upon Mr. Duncan’s death on March 29, 2010, voting and dispositive control of all of the membership interests of Dan Duncan LLC was transferred pursuant to the DD LLC Voting Trust Agreement to three voting trustees. The current voting trustees under the DD LLC Voting Trust Agreement (the “DD LLC Trustees”) are: (i) Randa Duncan Williams, Mr. Duncan’s oldest daughter who is also a director of EPE Holdings; (ii) Dr. Ralph S. Cunningham, who is currently the President and Chief Executive Officer (“CEO”) of EPE Holdings; and (iii) Richard H. Bachmann, who is currently an Executive Vice President, the Chief Legal Officer and Secretary of EPGP and one of three managers of Dan Duncan LLC. Dr. Cunningham and Mr. Bachmann also serve as directors of EPE Holdings.

The DD LLC Voting Trust Agreement requires that there always be two “Independent Voting Trustees” serving. If Mr. Bachmann or Dr. Cunningham fail to qualify or cease to serve, then the substitute or successor Independent Voting Trustee(s) will be appointed by the then-serving Independent Voting Trustee, provided that if no Independent Voting Trustee is then serving or if a vacancy in a trusteeship of an Independent Voting Trustee is not filled within 90 days of the vacancy’s occurrence, the CEO of the general partner of Enterprise Products Partners (as defined below), currently Michael A. Creel, will appoint the successor Independent Voting Trustee(s).

The DD LLC Voting Trust Agreement also provides for a “Duncan Voting Trustee.” The Duncan Voting Trustee is appointed by the children of Mr. Duncan acting by a majority or, if less than three children of Mr. Duncan are then living, unanimously. If for any reason no descendent of Mr. Duncan is appointed as the Duncan Voting Trustee, then such trusteeship will remain vacant until such time as a Duncan Voting Trustee is appointed in the manner provided above. If a Duncan Voting Trustee for any reason ceases to serve, his or her successor shall be appointed by the children of Mr. Duncan acting by majority or, if less than three children of Mr. Duncan are then living, unanimously. Ms. Williams is currently the Duncan Voting Trustee.

The estate of Mr. Duncan became the sole member party to the DD LLC Voting Trust Agreement upon the death of Mr. Duncan on March 29, 2010. For all purposes whatsoever, the DD LLC Trustees are required to treat the member party to the DD LLC Voting Trust Agreement as the beneficial owner of the membership interests of Dan Duncan LLC. However, the DD LLC Trustees collectively are the record

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owners of the Dan Duncan LLC membership interests and possess and are entitled to exercise all rights and powers of absolute ownership thereof and to vote, assent or consent with respect thereto and to take party in and consent to any corporate or members’ actions (except those actions, if any, to which the DD LLC Trustees may not legally consent) and, subject to the provisions of the DD LLC Voting Trust Agreement, to receive distributions on the Dan Duncan LLC membership interests. Except as otherwise provided in the DD LLC Voting Trust Agreement, all actions taken by the DD LLC Trustees are by majority vote.

The DD LLC Trustees serve in such capacity without compensation, but they are entitled to incur reasonable charges and expenses deemed necessary and proper for administering the DD LLC Voting Trust Agreement and to reimbursement and indemnification.

The DD LLC Voting Trust Agreement will terminate when (i) the descendants of Mr. Duncan, and entities directly or indirectly controlled by or held for the benefit of any such descendant, no longer own any capital stock of EPCO (as defined below); or (ii) upon such earlier date designated by the DD LLC Trustees by an instrument in writing delivered to the member party to the DD LLC Voting Trust Agreement.

On April 27, 2010, the independent co-executors for the estate of Mr. Duncan were appointed by the probate court. The independent co-executors are Mr. Bachmann, Dr. Cunningham and Ms. Williams, who are the same persons as the current DD LLC Trustees and voting trustees under a separate voting trust agreement relating to a majority of EPCO’s outstanding shares with voting rights (as more fully described below).

References to “EPCO” mean Enterprise Products Company (formerly EPCO, Inc.) and its privately held affiliates. Prior to Mr. Duncan’s death, the Parent Company, EPE Holdings, Enterprise Products Partners, EPO, EPGP, Duncan Energy Partners and DEP GP (as defined below) were affiliates under the common control of Mr. Duncan since he was the controlling shareholder of EPCO and the controlling member of Dan Duncan LLC. A majority of the outstanding voting capital stock of EPCO is owned of record by a voting trust formed on April 26, 2006, pursuant to the EPCO, Inc. Voting Trust Agreement (the “EPCO Voting Trust Agreement”), among EPCO and Mr. Duncan (as the record owner of a majority of the outstanding voting capital stock of EPCO immediately prior to the entering into of the EPCO Voting Trust Agreement and as the initial sole voting trustee).

Immediately upon Mr. Duncan’s death, voting and dispositive control of such majority of the outstanding voting capital stock of EPCO was transferred pursuant to the EPCO Voting Trust Agreement to three voting trustees (the “EPCO Trustees”). The current EPCO Trustees 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, CEO and Chief Legal Officer of EPCO. Ms. Williams, Dr. Cunningham and Mr. Bachmann are also currently directors of EPCO. The current EPCO Trustees are the same as the current DD LLC Trustees, which control Dan Duncan LLC. The current EPCO Trustees are also the same persons as the individuals appointed on April 27, 2010 as the independent co-executors of the estate of Mr. Duncan.

References to “Enterprise Products Partners” mean Enterprise Products Partners L.P., 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,” and its consolidated subsidiaries. Enterprise Products Partners conducts substantially all of its business through Enterprise Products Operating LLC (“EPO”) and its consolidated subsidiaries. Enterprise Products Partners completed the mergers of TEPPCO Partners, L.P. (“TEPPCO”) and Texas Eastern Products Pipeline Company, LLC (“TEPPCO GP”) with its subsidiaries on October 26, 2009. We refer to such related mergers both individually and in the aggregate as the “TEPPCO Merger.” References to “EPGP” refer to Enterprise Products GP, LLC, which is the general partner of Enterprise Products Partners. EPGP is owned by the Parent Company and is responsible for managing the business and operations of Enterprise Products Partners.

References to “Duncan Energy Partners” mean Duncan Energy Partners L.P., which is a consolidated subsidiary of EPO. Duncan Energy Partners is a publicly traded Delaware limited

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partnership, the common units of which are listed on the NYSE under the ticker symbol “DEP.” References to “DEP GP” mean DEP Holdings, LLC, which is the general partner of Duncan Energy Partners and wholly owned by EPO.

References to “Energy Transfer Equity” mean the business and operations of Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include Energy Transfer Partners, L.P. (“ETP”) and, effective May 26, 2010, Regency Energy Partners LP (“RGNC”). Energy Transfer Equity is a publicly traded Delaware limited partnership, the common units of which are listed on the NYSE under the ticker symbol “ETE.” ETP is a publicly traded Delaware limited partnership, the common units of which are listed on the NYSE under the ticker symbol “ETP.” RGNC is a publicly traded Delaware limited partnership, the common units of which are traded on the NASDAQ stock market under the ticker symbol “RGNC.” The general partner of Energy Transfer Equity is LE GP, LLC (“LE GP”). The Parent Company owns noncontrolling interests in both Energy Transfer Equity and LE GP that it accounts for using the equity method of accounting. We do not control Energy Transfer Equity or LE GP.

References to the “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. (“EPCO Unit”), collectively, all of which were privately held affiliates of EPCO. The Employee Partnerships were liquidated in August 2010. See Note 3 for additional information.

Additionally, Enterprise Products Partners, Duncan Energy Partners and Energy Transfer Equity electronically file certain documents with the 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 Organization and Basis of Presentation

Parent Company

The Parent Company is a publicly traded Delaware limited partnership, the limited partnership interests (the “Units”) of which are listed on the NYSE under the ticker symbol “EPE.” Our business consists of the ownership of general and limited partner interests of publicly traded partnerships engaged in the midstream energy industry and related businesses. Our goal is to increase cash distributions to unitholders.

The Parent Company is owned 99.99% by its limited partners and 0.01% by its general partner, EPE Holdings. EPE Holdings is a wholly owned subsidiary of Dan Duncan LLC, the membership interests of which are currently owned of record collectively by the DD LLC Trustees. The Parent Company has no operations apart from its investing activities and indirectly overseeing the management of the entities controlled by it. At September 30, 2010, the Parent Company had investments in Enterprise Products Partners, Energy Transfer Equity and their respective general partners.

Interim Reporting

Our results of operations for the three and nine months ended September 30, 2010 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 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 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, 2009 (the “2009 Form 10-K”).

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Basis of Presentation

General Purpose Consolidated and Parent Company-Only Information. In accordance with rules and regulations of the SEC and various other accounting standard-setting organizations, our general purpose financial statements reflect the consolidation of the financial information of businesses that we control through the ownership of general partner interests (i.e., Enterprise Products Partners). Our general purpose consolidated financial statements present those investments in which we do not have a controlling interest as unconsolidated affiliates (i.e., Energy Transfer Equity and LE GP). As presented in our consolidated financial statements, noncontrolling interest reflects third-party and related party ownership of our consolidated subsidiaries, which include the third-party and related party unitholders of Enterprise Products Partners and Duncan Energy Partners other than the Parent Company.

In order for the unitholders of Enterprise GP Holdings L.P. and others to more fully understand the Parent Company’s business and financial statements on a standalone basis, Note 18 includes information devoted exclusively to the Parent Company apart from that of our consolidated Partnership. A key difference between the non-consolidated Parent Company financial information and those of our consolidated Partnership is that the Parent Company views each of its investments (i.e., Enterprise Products Partners and Energy Transfer Equity) as unconsolidated affiliates and records its share of the net income of each as equity income in the Parent Company income information. In accordance with GAAP, we eliminate the equity income related to Enterprise Products Partners in the preparation of our consolidated financial statements.

Presentation of Investments. The Parent Company owns common units of Enterprise Products Partners and 100% of the membership interests of EPGP, which is entitled to 2% of the cash distributions paid by Enterprise Products Partners as well as the associated incentive distribution rights (“IDRs”) of Enterprise Products Partners. At September 30, 2010 and December 31, 2009, the Parent Company owned 21,563,177 and 21,167,783 common units, respectively, of Enterprise Products Partners.

The Parent Company owns 38,976,090 common units of Energy Transfer Equity and approximately 40.6% of the membership interests of LE GP. Energy Transfer Equity owns limited partner interests and the general partner interest of ETP. In addition, Energy Transfer Equity owns certain limited partner interests in and 100% of the general partner of RGNC. We account for our investments in Energy Transfer Equity and LE GP using the equity method of accounting.

Proposed Merger of the Parent Company with Enterprise Products Partners

On September 3, 2010, Enterprise Products Partners and the Parent Company entered into an Agreement and Plan of Merger that would, if approved by the Parent Company’s unitholders, result in the merger of the Parent Company with a wholly owned subsidiary of Enterprise Products Partners through a unit-for-unit exchange. Consequently, the Parent Company would become a wholly owned subsidiary of Enterprise Products Partners. Under the terms of the Holdings Merger Agreement, the Parent Company’s unitholders will be entitled to receive 1.5 of Enterprise Products Partners’ common units in exchange for each limited partner unit of the Parent Company they own at closing. As a result, Enterprise Products Partners expects to issue, in the aggregate, 208,813,477 of its common units to the Parent Company’s unitholders. The proposed transaction would also result in the cancellation of 21,563,177 of Enterprise Products Partners’ common units currently held by the Parent Company as well as the general partner’s 2% economic interest and its incentive distribution rights in Enterprise Products Partners. Affiliates of EPCO will continue to own Enterprise Products Partners’ general partner following the merger.

The proposed merger must receive the affirmative vote of the Parent Company’s unitholders owning at least a majority of the Parent Company’s outstanding units as of the record date. Subject to the terms and conditions of a support agreement, privately held affiliates of EPCO (the “Holdings supporting unitholders”) have agreed to vote their 105,739,220 units of the Parent Company, representing approximately 76% of the Parent Company’s outstanding units, in favor of the proposed merger. The support agreement will automatically terminate on December 31, 2010 or upon the earlier termination of

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the Holdings Merger Agreement. The Holdings supporting unitholders may terminate their obligations under the support agreement in certain circumstances, including specified changes in U.S. federal income tax law if such changes occur prior to the closing of the merger.

In connection with the proposed merger, a privately held affiliate of EPCO has agreed to temporarily waive the regular quarterly cash distributions it would otherwise receive from Enterprise Products Partners on an initial amount of 30,610,000 of its 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 would apply 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.

The Holdings Merger Agreement contains customary representations and warranties and covenants by each of the parties. Completion of the proposed merger is conditioned upon, among other things: (i) the absence of certain legal impediments prohibiting the transactions, (ii) applicable regulatory approvals and (iii) the conditions precedent contained in the Holdings Merger Agreement having been satisfied. The Holdings Merger Agreement contains provisions granting Enterprise Products Partners and the Parent Company the right to terminate the agreement for certain reasons, including, among others, if the proposed merger does not occur on or before December 31, 2010.

TEPPCO Merger

On October 26, 2009, the related mergers of wholly owned subsidiaries of Enterprise Products Partners with TEPPCO and TEPPCO GP were completed. Under terms of the merger agreements, TEPPCO and TEPPCO GP became wholly owned subsidiaries of Enterprise Products Partners, and each of TEPPCO’s unitholders, except for a privately held affiliate of EPCO, received 1.24 common units of Enterprise Products Partners for each TEPPCO unit they owned. In total, Enterprise Products Partners issued an aggregate of 126,932,318 common units and 4,520,431 Class B units (described below) as consideration in the TEPPCO Merger for both TEPPCO units and the TEPPCO GP membership interests. On October 27, 2009, the TEPPCO and TEPPCO GP equity interests were contributed to EPO, and TEPPCO and TEPPCO GP became wholly owned subsidiaries of EPO.

A privately held affiliate of EPCO exchanged a portion of its TEPPCO units, based on the 1.24 exchange rate, for 4,520,431 Class B units of Enterprise Products Partners in lieu of common units. The Class B units are not entitled to receive regular quarterly cash distributions for the first sixteen quarters following the closing date of the merger. The Class B units automatically convert into the same number of common units on the date immediately following the payment date for the sixteenth regular quarterly distribution following the closing date of the merger. The Class B units are entitled to vote together with the common units as a single class on partnership matters and, except for the payment of distributions, have the same rights and privileges as Enterprise Products Partners’ common units.

Under the terms of the TEPPCO Merger agreements, the Parent Company received 1,331,681 common units of Enterprise Products Partners and an increase in the capital account of EPGP to maintain its 2% general partner interest in Enterprise Products Partners as consideration for 100% of the membership interests of TEPPCO GP.

Due to common control considerations, the TEPPCO Merger was accounted for at historical costs as a reorganization of entities under common control in a manner similar to a pooling of interests. As a result, our consolidated financial statements and business segments were recast to reflect the TEPPCO Merger. Our recast consolidated financial statements for periods prior to the TEPPCO Merger reflect the combined financial information of Enterprise Products Partners, TEPPCO and TEPPCO GP on a 100% basis. Third-party and related party ownership interests in TEPPCO and TEPPCO GP are presented as “Former owners of TEPPCO,” which is a component of noncontrolling interest. Investors should use our recast consolidated financial statements when making comparisons between our current and prior period financial information.

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Deconsolidation of Texas Offshore Port System

In August 2008, Enterprise Products Partners, including TEPPCO, together with Oiltanking Holding Americas, Inc. (“Oiltanking”) formed the Texas Offshore Port System partnership (“TOPS”). In April 2009, Enterprise Products Partners and TEPPCO dissociated from TOPS. As a result, our operating costs and expenses and net income for the second quarter of 2009 include a non-cash charge of $68.4 million. This loss represents the forfeiture of our cumulative investment, including that of TEPPCO, in TOPS through the date of dissociation. The impact on net income attributable to Enterprise GP Holdings L.P. was approximately $8.7 million, as nearly all of this loss was absorbed by noncontrolling interests in consolidation (i.e., by the former owners of TEPPCO).

We consolidated the financial statements of TOPS with those of our own since TEPPCO and Enterprise Products Partners held a majority of the ownership interests and voting control of TOPS. Oiltanking’s interest in the joint venture was accounted for as a noncontrolling interest. As a result of our dissociation from TOPS, we discontinued the consolidation of TOPS during the second quarter of 2009. The effect of deconsolidation was to remove the accounts of TOPS, including Oiltanking’s noncontrolling interest of $33.4 million, from our books and records, after reflecting the $68.4 million aggregate write-off of the investments related to the deconsolidation.

In September 2009, we entered into a settlement agreement with certain affiliates of Oiltanking that resolved all disputes between the parties related to the business and affairs of the TOPS project. We recognized approximately $66.9 million of expense during the third quarter of 2009 in connection with the payment of this cash settlement.

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 (e.g., assets, liabilities, revenue and expenses) and disclosures regarding 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

Cash and cash equivalents and restricted cash, accounts receivable, accounts payable and accrued expenses and other current liabilities (excluding derivative instruments) are carried at amounts which reasonably approximate their fair values due to their short-term nature. The estimated fair values of our fixed-rate debt 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. See Note 4 for fair value information associated with our derivative instruments.

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The following table presents the estimated fair values of our financial instruments at the dates indicated:

	September 30, 2010				December 31, 2009
Financial Instruments	Carrying Value		Fair Value		Carrying Value		Fair Value
Financial assets:
Cash and cash equivalents and restricted cash	$	75.4	$	75.4	$	118.9	$	118.9
Accounts receivable		3,067.6		3,067.6		3,137.4		3,137.4
Financial liabilities:
Accounts payable and accrued expenses		4,135.2		4,135.2		4,106.1		4,106.1
Other current liabilities (excluding derivative instruments)		339.0		339.0		341.7		341.7
Fixed-rate debt (principal amount)		12,032.7		13,205.5		10,586.7		11,056.2
Variable-rate debt		1,707.6		1,707.6		1,791.8		1,791.8

Recent Accounting Developments

In November 2008, the SEC released a proposed roadmap regarding the potential use by U.S. issuers of financial statements prepared in accordance with International Financial Reporting Standards (“IFRS”). IFRS consist of accounting standards published by the International Accounting Standards Board (“IASB”), which is based in London, England. In February 2010, the SEC expressed its continuing support for a single set of high-quality globally accepted accounting standards and established a general work plan that sets forth areas and factors the SEC will consider before requiring domestic public companies to transition to IFRS. Currently, the Financial Accounting Standards Board (or “FASB,” based in Norwalk, Connecticut) and the IASB are working both individually and jointly on a number of accounting standard convergence projects that, if finalized in 2011, would bring about a significant shift in the accounting and financial reporting landscape. These projects include a broad range of topics such as financial statement presentation, accounting for leases, revenue recognition, financial instruments, consolidations and fair value measurements.

The SEC expects to make a determination in 2011 regarding the mandatory adoption of IFRS, with the expectation that any decision to adopt IFRS will allow U.S. issuers a number of years to transition from current U.S. GAAP. We continue to monitor developments regarding the potential implementation of IFRS and the ongoing convergence projects of the FASB and IASB. We will evaluate the impact that any definitive accounting guidance may have on our financial statements once this information is finalized by the appropriate standard setting organizations, including the SEC.

Restricted Cash

Restricted cash represents amounts held in connection with our commodity derivative instruments portfolio and related physical natural gas and NGL purchases. Additional cash may be restricted to maintain this portfolio as commodity prices fluctuate or deposit requirements change. At September 30, 2010 and December 31, 2009, our restricted cash amounts were $32.5 million and $63.6 million, respectively. Our restricted cash balances have decreased since December 31, 2009 due to a reduction in margin requirements related to our commodity hedging activities. See Note 4 for information regarding our derivative instruments and hedging activities.

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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 indicated:

	For the Three Months				For the Nine Months
	Ended September 30,				Ended September 30,
	2010		2009		2010		2009
Restricted unit awards (1)	$	9.6	$	4.4	$	23.3	$	11.0
Unit option awards (1)		1.2		0.7		3.1		1.5
Unit appreciation rights (2)		0.2		0.1		0.5		--
Phantom units (2)		--		0.1		0.1		0.2
Profits interests awards (1) (3)		19.6		2.1		23.4		5.8
Total compensation expense	$	30.6	$	7.4	$	50.4	$	18.5

(1) Accounted for as equity-classified awards. (2) Accounted for as liability-classified awards. (3) The increase between periods is due to the liquidation of the Employee Partnerships in August 2010 (see below).

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

At September 30, 2010, EPCO’s long-term incentive plans applicable to our operations were the Enterprise Products 1998 Long-Term Incentive Plan, the Enterprise Products Company 2005 EPE Long-Term Incentive Plan, the Amended and Restated 2008 Enterprise Products Long-Term Incentive Plan and the 2010 Duncan Energy Partners L.P. Long-Term Incentive Plan. In addition, there were unvested awards outstanding under an inactive plan, the Enterprise Products 2006 TPP Long-Term Incentive Plan (“2006 Plan”). EPCO’s equity-based awards also included profits interests in the Employee Partnerships until their liquidation in August 2010.

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 common units issued to the employee. In addition, we reimbursed EPCO for certain amounts recorded in connection with EPCO Unit (one of the Employee Partnerships). Beginning in February 2009, the ASA was amended to provide that we and other affiliates of EPCO would reimburse EPCO for our allocated share of distributions of cash or securities made to the Class B limited partners of EPCO Unit. Except for the foregoing, we are not responsible for reimbursing EPCO for any of the costs associated with equity awards.

Restricted Unit Awards

Restricted 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 unit awards may be denominated in our Units or common units of Enterprise Products Partners or Duncan Energy Partners depending on the issuer of the award. Restricted unit awards issued prior to 2010 generally cliff vest four years from the date of grant. Beginning with awards issued in 2010, restricted 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 unit” represents a time-vested unit. Such awards are non-vested until the required service period expires.

The fair value of a restricted 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 unit awards for the periods indicated:

	Number of Units			Weighted- Average Grant Date Fair Value per Unit (1)
Enterprise Products Partners L.P. restricted unit awards:
Restricted units at December 31, 2009		2,720,882		$	27.70
Granted (2,3)		1,353,425		$	32.36
Vested (3)		(339,628	)	$	25.26
Forfeited		(103,558	)	$	29.54
Restricted units at September 30, 2010		3,631,121		$	29.61

Duncan Energy Partners L.P. restricted unit awards:
Restricted units at December 31, 2009		--
Granted (3,4)		6,348		$	25.26
Vested (3)		(6,348	)	$	25.26
Restricted units at September 30, 2010		--

Parent Company restricted unit awards:
Restricted units at December 31, 2009		--
Granted (3,5)		3,424		$	41.47
Vested (3)		(3,424	)	$	41.47
Restricted units at September 30, 2010		--

(1) Determined by dividing the aggregate grant date fair value of awards before an allowance for forfeitures by the number of awards issued. (2) Aggregate grant date fair value of restricted unit awards denominated in Enterprise Products Partners’ common units was $43.8 million based on a grant date market price of Enterprise Products Partners’ common units ranging from $32.00 to $38.36 per unit. Estimated forfeiture rates ranging between 4.6% and 17% were applied to these awards. (3) Includes awards granted to the independent directors of the boards of directors of EPE Holdings, EPGP and DEP GP as part of their annual compensation for 2010. A total of 6,960, 6,348 and 3,424 restricted unit awards were issued in 2010 to the independent directors of EPGP, DEP GP and EPE Holdings, respectively, that immediately vested upon issuance. (4) Aggregate grant date fair value of restricted unit awards denominated in Duncan Energy Partners’ common units was $0.2 million based on a grant date market price of Duncan Energy Partners’ common units of $25.26 per unit. (5) Aggregate grant date fair value of restricted unit awards denominated in the Parent Company’s Units issued was $0.1 million based on a grant date market price of the Parent Company’s Units ranging from $39.99 to $51.66 per unit.

In the aggregate, unrecognized compensation cost of restricted unit awards was $53.2 million at September 30, 2010, of which our allocated share of the cost is currently estimated to be $48.8 million. We expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 2.1 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 Enterprise Products Partners’ 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, option awards have a vesting period of four years from the date of grant. If option awards are not exercised, these awards generally 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. Compensation expense is recognized based on the grant date fair value, net of an allowance for estimated forfeitures, over the vesting period.

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The following table presents unit option activity for the periods indicated. As of September 30, 2010, only Enterprise Products Partners 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, 2009		3,825,920		$	26.52
Granted (2)		785,000		$	32.26
Exercised		(812,500	)	$	25.01
Unit options at September 30, 2010		3,798,420		$	28.03		3.9	$	0.7
Options exercisable at September 30, 2010		45,000		$	24.30		4.4	$	0.7

(1) Aggregate intrinsic value reflects fully vested unit options at the date indicated. (2) Aggregate grant date fair value of these unit options was $2.3 million based on the following assumptions: (i) a weighted-average grant date market price of Enterprise Products Partners‘ common units of $32.26 per unit; (ii) weighted-average expected life of options of 4.9years; (iii) weighted-average risk-free interest rate of 2.5%; (iv) weighted-average expected distribution yield on Enterprise Products Partners’ common units of 6.9%; and (v) weighted-average expected unit price volatility on Enterprise Products Partners’ common units of 23.3%. An estimated forfeiture rate of 17% was applied to awards granted during 2010.

The following table presents additional information regarding unit option awards for the periods indicated:

	For the Three Months				For the Nine Months
	Ended September 30,				Ended September 30,
	2010		2009		2010		2009
Total intrinsic value of option awards exercised during period	$	7.5	$	0.3	$	9.7	$	0.6
Cash received from EPCO in connection with the exercise of unit option awards		5.0		0.3		6.6		0.5
Unit option-related reimbursements to EPCO		7.5		0.2		9.7		0.5

In the aggregate, unrecognized compensation cost of unit option awards was $8.5 million at September 30, 2010, of which our allocated share of the cost is currently estimated to be $7.6 million. We expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 2.5 years.

Unit Appreciation Rights

UARs entitle a participant to receive a cash payment on the vesting date equal to the excess, if any, of the fair market value of the underlying security (determined as of a future vesting date) over the grant date fair value of the award. UARs are accounted for as liability awards. The following tables present information regarding UARs for the periods indicated:

	UARs Based on Units of
	Enterprise Products Partners			Holdings		Total
UARs at December 31, 2009		142,196			90,000		232,196
Settled or forfeited		(10,255	)		--		(10,255	)
UARs at September 30, 2010		131,941			90,000		221,941

		September 30, 2010				December 31, 2009
Accrued liability for UARs		$	0.8			$	0.3

At September 30, 2010, 131,941 UARs had been granted under the 2006 Plan to certain employees of EPCO who work on our behalf. These awards are subject to five-year cliff vesting

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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 Enterprise Products Partners’ common units. If the employee resigns prior to vesting, the UARs are forfeited.

At September 30, 2010, there were 90,000 UARs outstanding that were granted to the independent directors of DEP GP. These UARs cliff vest in 2012. The grant date fair value with respect to these UARs is based on the Parent Company’s Unit price of $36.68. If a director resigns prior to vesting, his UARs are forfeited.

Phantom Unit Awards

Certain of EPCO’s long-term incentive plans provide for the issuance of phantom unit awards. These awards are automatically redeemed for cash based on the fair value of the vested portion of phantom units at redemption dates stated in each award. The fair value of each phantom unit award is equal to the closing market price of the underlying security on the redemption date. Each participant is required to redeem their phantom unit awards as they vest, which is typically three to four years from the date the award is granted. Phantom unit awards are accounted for as liability awards.

The following tables present information regarding phantom unit awards for the periods indicated:

Phantom unit awards at December 31, 2009	14,927
Granted	6,200
Vested (1)	(4,327	)
Phantom unit awards at September 30, 2010	16,800

(1) Primarily consists of 3,472 phantom unit awards outstanding under the TEPPCO 1999 Phantom Unit Retention Plan at December 31, 2009, which vested in January 2010. The plan was subsequently terminated.

	For the Three Months				For the Nine Months
	Ended September 30,				Ended September 30,
	2010		2009		2010		2009
Liabilities paid for phantom unit awards	$	--	$	--	$	0.1	$	1.1

	September 30,		December 31,
	2010		2009
Accrued liability for phantom unit awards	$	0.3	$	0.2

Profits Interests Awards

As long-term incentive arrangements, EPCO granted its key employees who perform services on behalf of us, EPCO and other affiliated companies, “profits interests” in the Employee Partnerships. These partnerships were liquidated in August 2010. Prior to liquidation, the profits interests awards 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 Products Partners’ common units or the Parent Company’s units or a combination of both. During the three months ended September 30, 2010, we recognized approximately $27 million of expense in connection with the liquidation of the Employee Partnerships, of which approximately $22 million was attributed to noncontrolling interest. Of this expense amount, approximately $19 million was non-cash.

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, commodity prices and, to a limited extent, foreign exchange rates. In order to manage risks associated with certain anticipated future transactions, we use derivative instruments. Derivatives are instruments whose fair value is determined by changes in a specified benchmark such as interest rates, commodity prices or currency values. Fair value is generally defined as the amount at which a derivative

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instrument could be exchanged in a current transaction between willing parties, not in a forced sale. Typical derivative instruments 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 the 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 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, 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.

§	Foreign currency exposure - A foreign currency hedge can be treated as either a fair value hedge or a cash flow hedge depending on the risk being hedged.

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.

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 the interest rates charged on borrowings under certain consolidated debt agreements. This strategy is a component in controlling our cost of capital associated with such borrowings.

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The following table summarizes our interest rate derivative instruments outstanding at September 30, 2010:

Hedged Transaction	Number and Type of Derivative(s) Employed	Notional Amount	Period of Hedge	Rate Swap	Accounting Treatment
Parent Company:
Variable-interest rate borrowings	2 floating-to-fixed swaps	$250.0	9/07 to 8/11	0.5% to 4.8%	Cash flow hedge
Variable-interest rate borrowings	6 floating-to-fixed swaps	$600.0	5/10 to 7/14	0.5% to 2.0%	Cash flow hedge
Enterprise Products Partners:
Senior Notes C	1 fixed-to-floating swap	$100.0	1/04 to 2/13	6.4% to 2.6%	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

In September 2010, Duncan Energy Partners’ three floating-to-fixed swaps with a notional amount of $175.0 million expired.

Interest rate swaps exchange the stated interest rate paid on a notional amount of debt for a fixed or floating interest rate stipulated in the derivative instrument. Our interest rate swaps associated with existing debt obligations resulted in an increase in interest expense of $1.3 million and $4.1 million for the three months ended September 30, 2010 and 2009, respectively. For the nine months ended September 30, 2010 and 2009, such swaps resulted in a decrease in interest expense of $0.9 million and an increase in interest expense of $13.4 million, respectively.

The following table summarizes our forward starting interest rate swaps outstanding at September 30, 2010, which hedge the expected underlying benchmark interest rates related to forecasted issuances of debt:

Hedged Transaction	Number and Type of Derivatives Employed	Notional Amount	Expected Termination Date	Average Rate Locked	Accounting Treatment
Future debt offering	3 forward starting swaps	$250.0	2/11	3.7%	Cash flow hedge
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 May 2010, we settled a forward starting swap with a notional amount of $50.0 million and recognized a gain of $1.3 million in other comprehensive income. This amount will be amortized to earnings using the effective interest method over the estimated term of the underlying fixed-rate debt.

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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 the price risk associated with certain exposures, 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 September 30, 2010:

	Volume (1)		Accounting
Derivative Purpose	Current	Long-Term (2)	Treatment
Derivatives designated as hedging instruments:
Enterprise Products Partners:
Natural gas processing:
Forecasted natural gas purchases for plant thermal reduction (“PTR”) (3)	19.0 Bcf	n/a	Cash flow hedge
Forecasted sales of NGLs (4)	5.1 MMBbls	n/a	Cash flow hedge
Octane enhancement:
Forecasted purchases of NGLs	0.8 MMBbls	n/a	Cash flow hedge
Forecasted sales of NGLs	0.1 MMBbls	n/a	Cash flow hedge
Forecasted sales of octane enhancement products	1.4 MMBbls	n/a	Cash flow hedge
Natural gas marketing:
Natural gas storage inventory management activities	3.8 Bcf	n/a	Fair value hedge
NGL marketing:
Forecasted purchases of NGLs and related hydrocarbon products	10.4 MMBbls	0.7 MMBbls	Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products	13.5 MMBbls	1.0 MMBbls	Cash flow hedge
Crude oil marketing:
Forecasted purchases of crude oil	3.0 MMBbls	n/a	Cash flow hedge
Forecasted sales of crude oil	4.3 MMBbls	n/a	Cash flow hedge
Duncan Energy Partners:
Forecasted sales of natural gas	1.0 Bcf	n/a	Cash flow hedge
Derivatives not designated as hedging instruments:
Enterprise Products Partners:
Natural gas risk management activities (5,6)	526.8 Bcf	62.2 Bcf	Mark-to-market
NGL risk management activities (6)	0.7 MMBbls	n/a	Mark-to-market
Crude oil risk management activities (6)	1.0 MMBbls	n/a	Mark-to-market
Duncan Energy Partners:
Natural gas risk management activities (6)	1.0 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 2012. (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) Excludes 1.5 MMBbls of additional hedges executed under contracts that have been designated as normal sales agreements under current accounting guidance. The combination of these volumes with the 5.1 MMBbls reflected as derivatives in the table above results in a total of 6.6 MMBbls of hedged forecasted NGL sales volumes, which corresponds to the 19.0 Bcf of forecasted natural gas purchase volumes for PTR. (5) Current and long-term volumes include approximately 149.7 and 10.5 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.

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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 gas processing activities. We achieve this objective by using physical 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 June 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.

Foreign Currency Derivative Instruments

We are exposed to a nominal amount of foreign currency exchange risk in connection with our NGL and natural gas marketing activities in Canada. As a result, we could be adversely affected by fluctuations in currency values 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 an exchange rate. Prior to the third quarter of 2010, long-term transactions (i.e., those having terms of more than two months) were accounted for as cash flow hedges and shorter term transactions were accounted for using mark-to-market accounting. We currently account for all foreign currency derivative transactions using mark-to-market accounting. At September 30, 2010, our foreign currency derivative instruments portfolio had a notional amount of $7.0 million Canadian. The fair market value of these derivative instruments was an asset of $0.1 million at September 30, 2010.

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 September 30, 2010, the aggregate fair value of our over-the-counter derivative instruments in a net liability position was $2.5 million, all of which was subject to a credit rating contingent feature. If our credit ratings were downgraded to Ba3/BB- or below, approximately $2.5 million would be payable as a margin deposit to the counterparties. Currently, no margin is required to be deposited. 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
	September 30, 2010			December 31, 2009			September 30, 2010			December 31, 2009
	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	$	30.8	Other current assets	$	32.7	Other current liabilities	$	45.6	Other current liabilities	$	18.6
Interest rate derivatives	Other assets		38.6	Other assets		31.8	Other liabilities		112.0	Other liabilities		6.7
Total interest rate derivatives			69.4			64.5			157.6			25.3
Commodity derivatives	Other current assets		29.9	Other current assets		52.0	Other current liabilities		63.8	Other current liabilities		62.6
Commodity derivatives	Other assets		2.7	Other assets		0.5	Other liabilities		2.9	Other liabilities		1.8
Total commodity derivatives (1)			32.6			52.5			66.7			64.4
Foreign currency derivatives	Other current assets		--	Other current assets		0.2	Other current liabilities		--	Other current liabilities		--
Total derivatives designated as hedging instruments		$	102.0		$	117.2		$	224.3		$	89.7

Derivatives not designated as hedging instruments
Commodity derivatives	Other current assets	$	50.7	Other current assets	$	28.9	Other current liabilities	$	45.7	Other current liabilities	$	24.9
Commodity derivatives	Other assets		3.9	Other assets		2.0	Other liabilities		8.1	Other liabilities		2.7
Total commodity derivatives			54.6			30.9			53.8			27.6
Foreign currency derivatives	Other assets		0.1	Other assets		--	Other liabilities		--	Other liabilities		--
Total derivatives not designated as hedging instruments		$	54.7		$	30.9		$	53.8		$	27.6

(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 indicated:

Derivatives in Fair Value Hedging Relationships	Location	Gain/(Loss) Recognized in Income on Derivative
		For the Three Months				For the Nine Months
		Ended September 30,				Ended September 30,
		2010		2009		2010		2009
Interest rate derivatives	Interest expense	$	8.1	$	12.0	$	27.1	$	(4.2	)
Commodity derivatives	Revenue		6.1		0.6		9.0		(0.1	)
Total		$	14.2	$	12.6	$	36.1	$	(4.3	)

Derivatives in Fair Value Hedging Relationships	Location	Gain/(Loss) Recognized in Income on Hedged Item
		For the Three Months						For the Nine Months
		Ended September 30,						Ended September 30,
		2010			2009			2010			2009
Interest rate derivatives	Interest expense	$	(8.6	)	$	(14.5	)	$	(26.8	)	$	1.1
Commodity derivatives	Revenue		(7.0	)		(0.5	)		(9.4	)		0.6
Total		$	(15.6	)	$	(15.0	)	$	(36.2	)	$	1.7

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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 indicated.

Derivatives in Cash Flow Hedging Relationships	Change in Value Recognized in Other Comprehensive Income on Derivative (Effective Portion)
	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2010			2009			2010			2009
Interest rate derivatives (1)	$	(81.6	)	$	(11.3	)	$	(168.4	)	$	3.0
Commodity derivatives – Revenue		(44.2	)		(21.3	)		42.2			44.5
Commodity derivatives – Operating costs and expenses		(19.9	)		13.0			(73.2	)		(191.4	)
Foreign currency derivatives		0.1			0.2			(0.1	)		(10.3	)
Total	$	(145.6	)	$	(19.4	)	$	(199.5	)	$	(154.2	)

(1) Change in value due to increased notional amounts of forward starting swaps and the reduction of London Interbank Offered Rates (“LIBOR”).

Derivatives in Cash Flow Hedging Relationships	Location	Gain/(Loss) Reclassified from Accumulated Other Comprehensive Income/Loss to Income (Effective Portion)
		For the Three Months						For the Nine Months
		Ended September 30,						Ended September 30,
		2010			2009			2010			2009
Interest rate derivatives	Interest expense	$	(8.1	)	$	(6.7	)	$	(21.4	)	$	(20.3	)
Commodity derivatives	Revenue		39.2			(12.5	)		41.7			7.2
Commodity derivatives	Operating costs and expenses		(13.6	)		(65.3	)		(31.1	)		(183.5	)
Foreign currency derivatives	Other income		--			--			0.3			--
Total		$	17.5		$	(84.5	)	$	(10.5	)	$	(196.6	)

Derivatives in Cash Flow Hedging Relationships	Location	Gain/(Loss) Recognized in Income on Ineffective Portion of Derivative
		For the Three Months						For the Nine Months
		Ended September 30,						Ended September 30,
		2010			2009			2010		2009
Interest rate derivatives	Interest expense	$	--		$	1.1		$	--	$	0.8
Commodity derivatives	Revenue		--			0.8			--		0.1
Commodity derivatives	Operating costs and expenses		(0.4	)		(1.0	)		2.5		(2.3	)
Total		$	(0.4	)	$	0.9		$	2.5	$	(1.4	)

Over the next twelve months, we expect to reclassify $24.9 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 $40.7 million of losses attributable to commodity derivative instruments from accumulated other comprehensive income to earnings, $21.9 million as an increase in operating costs and expenses and $18.8 million as a decrease in revenues.

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 indicated:

Derivatives Not Designated as Hedging Instruments	Location	Gain/(Loss) Recognized in Income on Derivative
		For the Three Months					For the Nine Months
		Ended September 30,					Ended September 30,
		2010		2009			2010			2009
Commodity derivatives	Revenue	$	17.0	$	(5.4	)	$	12.0		$	26.7
Commodity derivatives	Operating costs and expenses		--		--			(1.5	)		--
Foreign currency derivatives	Other income		0.1		--			0.1			(0.1	)
Total		$	17.1	$	(5.4	)	$	10.6		$	26.6

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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 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 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 primarily 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 are: (i) 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 appropriate financial models that incorporate the implied forward LIBOR 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 our 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 ranging from two months to a year. We rely on price quotes from reputable brokers who publish price quotes on certain products. Whenever possible, we compare these prices to

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other reputable brokers for the same product in the same market. These prices, when combined with data from our commodity derivative instruments, are used in our models to determine the fair value of such instruments.

The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities at September 30, 2010. These financial assets and liabilities are measured on a recurring basis and are classified based on the lowest level of input that is significant to their respective fair value measurements. Our assessment of the relative significance of such inputs requires judgment. There were no significant transfers between Levels 1, 2 or 3 during the nine months ended September 30, 2010.

	At September 30, 2010
	Level 1		Level 2		Level 3		Total
Financial assets:
Interest rate derivatives	$	--	$	69.4	$	--	$	69.4
Commodity derivatives		32.7		37.1		17.4		87.2
Foreign currency derivatives		--		0.1		--		0.1
Total	$	32.7	$	106.6	$	17.4	$	156.7

Financial liabilities:
Interest rate derivatives	$	--	$	157.6	$	--	$	157.6
Commodity derivatives		56.1		37.5		26.9		120.5
Total	$	56.1	$	195.1	$	26.9	$	278.1

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 indicated:

	For the Nine Months Ended September 30,
	2010			2009
Balance, January 1	$	5.7		$	32.4
Total gains (losses) included in:
Net income (1)		(3.6	)		12.9
Other comprehensive income (loss)		(8.3	)		1.5
Purchases, issuances, settlements – net		3.6			(12.3	)
Balance, March 31		(2.6	)		34.5
Total gains (losses) included in:
Net income (1)		16.2			7.7
Other comprehensive income (loss)		22.2			(23.1	)
Purchases, issuances, settlements – net		(16.2	)		(8.1	)
Transfers out of Level 3		0.2			(0.2	)
Balance, June 30		19.8			10.8
Total gains (losses) included in:
Net income (1)		18.2			7.6
Other comprehensive income (loss)		(31.4	)		(10.1	)
Purchases, issuances, settlements – net		(16.1	)		(6.7	)
Transfers out of Level 3		--			(2.3	)
Balance, September 30	$	(9.5	)	$	(0.7	)

(1) There were $6.4 million and $4.1 million of unrealized gains included in these amounts for the three and nine months ended September 30, 2010, respectively. There were $3.3 million and $3.5 million of unrealized losses included in these amounts for the three and nine months ended September 30, 2009, respectively.

Nonfinancial Assets and Liabilities

During the nine months ended September 30, 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.

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During the nine months ended September 30, 2009, certain river terminal and marine barge assets recorded as property, plant and equipment and other current assets were adjusted to fair value based on the present value of expected future cash flows (Level 3), resulting in non-cash asset impairment charges of $25.0 million. In addition, we recorded an impairment charge of $1.3 million related to goodwill during this period. These impairment charges resulted from reduced levels of throughput at the affected river terminals, the indefinite suspension of expansion plans for certain river terminals, and the determination that an underground gas storage cavern and certain marine transportation barges were obsolete. The affected river terminals were subject to a throughput contract with a third party. See Note 15 for information regarding a related $28.7 million charge for deficiency fees related to the reduced levels of throughput at the affected river terminals.

The impairment charges we recorded during the nine months ended September 30, 2010 and 2009 are a component of operating costs and expenses.

Note 5. Inventories

Our inventory amounts were as follows at the dates indicated:

	September 30,		December 31,
	2010		2009
Working inventory (1)	$	788.9	$	466.4
Forward sales inventory (2)		421.1		245.5
Total inventory	$	1,210.0	$	711.9

(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. The increase since December 31, 2009 is primarily related to increased marketing activities of refined products. (2) Forward sales inventory consists of identified natural gas, NGL, refined product and crude oil volumes dedicated to the fulfillment of forward sales contracts. The increase since December 31, 2009 is primarily related to higher refined products forward sales volumes.

In those instances where we take ownership of inventory 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.

The following table presents our cost of sales and lower of cost or market (“LCM”) adjustments for the periods indicated:

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2010		2009		2010		2009
Cost of sales (1)	$	6,814.0	$	5,581.3	$	20,499.5	$	13,820.1
LCM adjustments		0.2		0.5		7.1		6.2
(1) Cost of sales is a component of “Operating costs and expenses,” as presented on our Unaudited Condensed Statements of Consolidated Operations. Period-to-period fluctuations in these amounts are primarily due to changes in energy commodity prices and sales volumes associated with our marketing activities.

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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	September 30, 2010		December 31, 2009
Plants and pipelines (1)	3-45 (6)	$	18,869.7	$	17,681.9
Underground and other storage facilities (2)	5-40 (7)		1,426.6		1,280.5
Platforms and facilities (3)	20-31		637.6		637.6
Transportation equipment (4)	3-10		102.6		60.1
Marine vessels (5)	15-30		599.8		559.4
Land			91.7		82.9
Construction in progress			1,467.7		1,207.2
Total			23,195.7		21,509.6
Less accumulated depreciation			4,385.7		3,820.4
Property, plant and equipment, net		$	18,810.0	$	17,689.2

(1) Plants and pipelines include processing plants; NGL, petrochemical, crude 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; 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 vehicles and similar assets used in our operations. (5) Marine vessels include tow and push boats, barges and related equipment used in our marine transportation business. (6) In general, the estimated useful lives of major components of this category are as follows: 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 major components of this category are as follows: underground storage facilities, 5-35 years; storage tanks, 10-40 years; and water wells, 5-35 years.

In May 2010, we recorded approximately $293.4 million of property, plant and equipment in connection with the acquisition of the State Line and Fairplay natural gas gathering systems from subsidiaries of M2 Midstream LLC (“Momentum”). See Note 8 for additional information regarding this business combination.

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

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2010		2009		2010		2009
Depreciation expense (1)	$	184.9	$	174.8	$	552.9	$	502.7
Capitalized interest (2)		12.5		11.4		33.5		39.5
(1) Depreciation expense is a component of “Costs and expenses” as presented on 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.

Operating costs and expenses for the three and nine months ended September 30, 2010 include $9.9 million of non-cash charges resulting from the disposition of two pipeline segments in south Texas that were in natural gas gathering service.

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 AROs primarily result from (i) right-of-way agreements associated with our pipeline operations, (ii)

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leases of plant sites and (iii) regulatory requirements triggered by the abandonment or retirement of certain underground storage assets and offshore facilities. In addition, our AROs may result from the renovation or demolition of certain assets containing hazardous substances such as asbestos.

The following table presents information regarding our AROs since December 31, 2009:

ARO liability balance, December 31, 2009	$	54.8
Revisions in estimated cash flows		14.4
Accretion expense		3.0
Liabilities incurred during period		0.1
Liabilities settled during period		(8.1	)
ARO liability balance, September 30, 2010	$	64.2

Property, plant and equipment at September 30, 2010 and December 31, 2009 includes $29.7 million and $26.7 million, respectively, of asset retirement costs capitalized as an increase in the associated long-lived assets. The following table presents forecasted accretion expense associated with our AROs for the periods indicated:

Remainder of 2010				2011				2012				2013				2014
$	1.0			$	4.1			$	4.3			$	4.6			$	5.0

Certain of our unconsolidated affiliates had AROs recorded at September 30, 2010 and December 31, 2009 relating to contractual agreements and regulatory requirements. These amounts were immaterial to our consolidated financial statements.

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Note 7. Investments in Unconsolidated Affiliates

We hold ownership interests in a number of midstream energy businesses that are accounted for using the equity method of accounting. The following table presents our investments in unconsolidated affiliates (according to the business segment to which they relate) and our ownership interests at the dates indicated:

	Ownership Interest at September 30, 2010	September 30, 2010		December 31, 2009
NGL Pipelines & Services:
Venice Energy Service Company, L.L.C.	13.1%	$	31.8	$	32.6
K/D/S Promix, L.L.C. (“Promix”)	50%		45.1		48.9
Baton Rouge Fractionators LLC	32.2%		22.0		22.2
Skelly-Belvieu Pipeline Company, L.L.C.	50%		33.8		37.9
Onshore Natural Gas Pipelines & Services:
Evangeline (1)	49.5%		6.1		5.6
White River Hub, LLC	50%		26.5		26.4
Onshore Crude Oil Pipelines & Services:
Seaway Crude Pipeline Company (“Seaway”)	50%		174.7		178.5
Offshore Pipelines & Services:
Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”)	36%		58.8		61.7
Cameron Highway Oil Pipeline Company	50%		233.3		239.6
Deepwater Gateway, L.L.C.	50%		99.1		101.8
Neptune Pipeline Company, L.L.C.	25.7%		54.2		53.8
Petrochemical & Refined Products Services:
Baton Rouge Propylene Concentrator, LLC	30%		10.6		11.1
Centennial Pipeline LLC (“Centennial”)	50%		65.1		66.7
Other (2)	Various		3.6		3.8
Other Investments:
Energy Transfer Equity	17.5%		1,455.0		1,513.5
LE GP	40.6%		11.5		12.1
Total		$	2,331.2	$	2,416.2

(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.

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:

	September 30,		December 31,
	2010		2009
NGL Pipelines & Services	$	25.9	$	27.1
Onshore Crude Oil Pipelines & Services		19.9		20.4
Offshore Pipelines & Services		16.4		17.3
Petrochemical & Refined Products Services		3.0		4.0
Other Investments (1)		1,545.5		1,573.0
Total	$	1,610.7	$	1,641.8

(1) The Parent Company’s initial investment in Energy Transfer Equity and LE GP exceeded its share of the historical cost of the underlying net assets of such investees by $1.67 billion. At September 30, 2010, this basis differential decreased to $1.55 billion (after taking into account related amortization amounts) and consisted of the following: $496.6 million attributed to fixed assets; $513.5 million attributed to the IDRs (an indefinite-life intangible asset) held by Energy Transfer Equity in the cash flows of ETP; $199.6 million attributed to amortizable intangible assets and $335.8 million attributed to equity method goodwill.

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ENTERPRISE GP HOLDINGS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

We amortize the 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 indicated:

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2010		2009		2010		2009
NGL Pipelines & Services	$	0.2	$	0.2	$	0.7	$	0.7
Onshore Crude Oil Pipelines & Services		0.1		0.1		0.5		0.5
Offshore Pipelines & Services		0.3		0.3		0.9		0.9
Petrochemical & Refined Products Services		0.1		1.0		1.0		3.0
Other Investments		9.2		9.2		27.5		27.5
Total	$	9.9	$	10.8	$	30.6	$	32.6

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

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2010			2009			2010			2009
NGL Pipelines & Services	$	5.1		$	4.0		$	12.1		$	7.5
Onshore Natural Gas Pipelines & Services		1.2			1.4			3.4			3.9
Onshore Crude Oil Pipelines & Services		1.6			1.2			7.5			7.4
Offshore Pipelines & Services		10.1			10.6			33.0			22.1
Petrochemical & Refined Products Services		(0.5	)		(2.2	)		(5.8	)		(8.9	)
Other Investments		(11.9	)		(0.9	)		(7.0	)		25.7
Total	$	5.6		$	14.1		$	43.2		$	57.7

Summarized Income Statement Information of Unconsolidated Affiliates

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

	Summarized Income Statement Information for the Three Months Ended
	September 30, 2010							September 30, 2009
	Revenues		Operating Income		Net Income (Loss)			Revenues		Operating Income		Net Income
NGL Pipelines & Services	$	78.3	$	17.3	$	17.3		$	60.0	$	10.9	$	11.2
Onshore Natural Gas Pipelines & Services		63.8		2.6		2.4			54.5		2.9		2.7
Onshore Crude Oil Pipelines & Services		16.6		5.8		5.8			20.7		6.9		6.8
Offshore Pipelines & Services		49.4		25.3		25.1			43.2		24.7		24.0
Petrochemical & Refined Products Services		15.1		2.5		0.2			12.8		2.4		--
Other Investments (1)		1,587.8		202.1		(15.3	)		1,129.8		173.5		47.0
(1) Net income for Energy Transfer Equity represents net income attributable to the partners of Energy Transfer Equity.

	Summarized Income Statement Information for the Nine Months Ended
	September 30, 2010							September 30, 2009
	Revenues		Operating Income		Net Income (Loss)			Revenues		Operating Income		Net Income (Loss)
NGL Pipelines & Services	$	227.8	$	43.8	$	43.7		$	161.7	$	23.7	$	24.2
Onshore Natural Gas Pipelines & Services		159.8		7.0		6.7			137.1		8.0		7.6
Onshore Crude Oil Pipelines & Services		57.1		23.9		23.9			62.2		25.6		25.6
Offshore Pipelines & Services		155.8		81.3		80.5			106.4		39.2		37.7
Petrochemical & Refined Products Services		39.3		0.5		(6.6	)		41.1		5.2		(2.5	)
Other Investments (1)		4,822.3		720.2		116.7			3,911.5		744.6		302.9
(1) Net income for Energy Transfer Equity represents net income attributable to the partners of Energy Transfer Equity.

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ENTERPRISE GP HOLDINGS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 8. Business Combinations

State Line and Fairplay Natural Gas Gathering Systems

In May 2010, we acquired 100% ownership of the State Line and Fairplay natural gas gathering systems and related assets from Momentum for approximately $1.2 billion in cash. The effective date of the acquisition was May 1, 2010. These systems are located in northwest Louisiana and east Texas and gather natural gas produced from the Haynesville/Bossier Shales and the Cotton Valley and Taylor Sand formations. Enterprise Products Partners used a portion of the net proceeds from its April 2010 equity offering, together with borrowings under EPO’s Multi-Year Revolving Credit Facility, to fund this acquisition.

The State Line system is located in Desoto and Caddo Parishes, Louisiana and Panola County, Texas. The system currently includes approximately 188 miles of natural gas gathering pipelines having an aggregate gathering capacity of approximately 700 million cubic feet per day (“MMcf/d”) and two natural gas treating facilities. The State Line system began operations in February 2009 and is currently gathering approximately 375 MMcf/d of natural gas. The Fairplay system is located in Rusk, Panola, Gregg and Nacogdoches counties, Texas. The system includes approximately 249 miles of natural gas gathering pipelines having an aggregate gathering capacity of approximately 285 MMcf/d. The Fairplay system is currently gathering approximately 150 MMcf/d of natural gas. Our operations related to the Fairplay system include providing natural gas processing services using third-party processing facilities. The State Line and Fairplay systems are supported by long-term acreage dedication agreements totaling approximately 210,000 acres, as well as volumetric commitments from producers.

Our acquisition of the State Line system complements our Haynesville Extension natural gas pipeline project. The Haynesville Extension, which is under development by Acadian Gas, LLC, is expected to provide shippers with takeaway capacity from the Haynesville Shale producing basin and flexible options for reaching attractive markets for their natural gas, including access to nine interstate gas pipeline systems. The Fairplay system is expected to extend our asset base through planned future interconnects with our Texas Intrastate System, along with supporting deliveries of NGLs into our Panola pipeline and further to our fractionation, storage and distribution complex in Mont Belvieu, Texas.

On a combined basis, our consolidated revenues and net income from the State Line and Fairplay systems were $75.0 million and $8.1 million, respectively, for the five months we owned these assets.

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ENTERPRISE GP HOLDINGS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Pro forma financial information. Since the effective date of the State Line and Fairplay acquisitions was May 1, 2010, our Unaudited Condensed Statements of Consolidated Operations do not include earnings from these businesses prior to this date. The following table presents selected unaudited pro forma earnings information for the periods presented as if the acquisitions had been completed on January 1 of each year presented. This pro forma information was prepared using historical financial data for the State Line and Fairplay systems and reflects certain estimates and assumptions made by our management. Our unaudited pro forma financial information is not necessarily indicative of what our consolidated financial results would have been had we actually acquired the State Line and Fairplay systems on January 1 of each year presented.

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2010		2009		2010		2009
Pro forma earnings data:
Revenues	$	8,067.8	$	6,823.7	$	24,221.1	$	17,199.5
Costs and expenses		7,530.2		6,482.5		22,616.4		16,029.9
Operating income		543.2		355.3		1,647.9		1,227.3
Net income		347.6		175.4		1,098.9		389.7
Net income attributable to Enterprise GP Holdings L.P.		37.0		25.3		161.2		127.0

Basic earnings per unit:
As reported basic units outstanding		139.2		139.2		139.2		137.4
Pro forma basic units outstanding		139.2		139.2		139.2		137.4
As reported basic earnings per unit	$	0.27	$	0.18	$	1.16	$	0.93
Pro forma basic earnings per unit	$	0.27	$	0.18	$	1.16	$	0.92
Diluted earnings per unit:
As reported diluted units outstanding		139.2		139.2		139.2		137.4
Pro forma diluted units outstanding		139.2		139.2		139.2		137.4
As reported diluted earnings per unit	$	0.27	$	0.18	$	1.16	$	0.93
Pro forma diluted earnings per unit	$	0.27	$	0.18	$	1.16	$	0.92

Other 2010 Transactions

In June 2010, we acquired a marine transportation business located in south Louisiana for $12.0 million in cash. This business is engaged in crude oil gathering and included three tug boats and five barges. This business is part of our Petrochemical & Refined Products Services business segment. In August 2010, we acquired a crude oil trucking business located in North Dakota for $4.0 million. This business is part of our Onshore Crude Oil Pipelines & Services business segment. On a pro forma consolidated basis after giving effect to these two transactions, our revenues, costs and expenses, operating income, net income attributable to Enterprise GP Holdings L.P. and earnings per unit amounts would not have differed materially from those we reported for the three and nine months ended September 30, 2010 and 2009.

See Note 17 for information regarding a September 2010 drop down transaction whereby we acquired ownership interests in EPCO’s trucking business.

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ENTERPRISE GP HOLDINGS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Purchase Price Allocations

We accounted for our 2010 business combinations using the acquisition method of accounting. Accordingly, such costs have been allocated to assets acquired and liabilities assumed based on fair values that were developed using recognized business valuation techniques. The following table depicts the allocation of the fair value of assets acquired and liabilities assumed at the effective date for each business combination:

	State Line and Fairplay Systems			Other			Total
Assets acquired in business combination:
Current assets	$	--		$	1.6		$	1.6
Property, plant and equipment, net		293.4			10.1			303.5
Identifiable intangible assets		895.0			--			895.0
Total assets acquired		1,188.4			11.7			1,200.1
Liabilities assumed in business combination:
Current liabilities		--			(0.1	)		(0.1	)
Long-term debt		--			(1.3	)		(1.3	)
Other long-term liabilities		(0.1	)		--			(0.1	)
Total liabilities assumed		(0.1	)		(1.4	)		(1.5	)
Total assets acquired plus liabilities assumed		1,188.3			10.3			1,198.6
Total cash used for business combinations		1,214.5			18.5			1,233.0
Goodwill (see Note 9)	$	26.2		$	8.2		$	34.4

The State Line and Fairplay property, plant and equipment assets are a component of our Onshore Natural Gas Pipelines & Services business segment. Of the $895.0 million of identifiable intangible assets (i.e., customer relationships) we recorded in connection with this acquisition, $103.4 million is attributable to natural gas processing activities and $791.6 million to natural gas gathering operations. We classify earnings and assets associated with natural gas processing activities as part of our NGL Pipelines & Services segment. Earnings and assets associated with natural gas gathering activities are reported within our Onshore Natural Gas Pipelines & Services segment. See Note 9 for additional information regarding the customer relationship intangible assets we acquired in connection with the State Line and Fairplay systems.

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ENTERPRISE GP HOLDINGS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 9. Intangible Assets and Goodwill

Identifiable Intangible Assets

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

	September 30, 2010							December 31, 2009
	Gross Value		Accum. Amort.			Carrying Value		Gross Value		Accum. Amort.			Carrying Value
NGL Pipelines & Services:
Customer relationship intangibles (1)	$	340.8	$	(101.3	)	$	239.5	$	237.4	$	(86.5	)	$	150.9
Contract-based intangibles		321.9		(171.7	)		150.2		321.4		(156.7	)		164.7
Segment total		662.7		(273.0	)		389.7		558.8		(243.2	)		315.6
Onshore Natural Gas Pipelines & Services:
Customer relationship intangibles (1)		1,163.6		(149.1	)		1,014.5		372.0		(124.3	)		247.7
Contract-based intangibles		565.3		(313.4	)		251.9		565.3		(285.8	)		279.5
Segment total		1,728.9		(462.5	)		1,266.4		937.3		(410.1	)		527.2
Onshore Crude Oil Pipelines & Services:
Customer relationship intangibles		9.6		(3.7	)		5.9		9.6		(3.4	)		6.2
Contract-based intangibles		0.4		(0.1	)		0.3		0.4		(0.1	)		0.3
Segment total		10.0		(3.8	)		6.2		10.0		(3.5	)		6.5
Offshore Pipelines & Services:
Customer relationship intangibles		205.8		(115.0	)		90.8		205.8		(105.3	)		100.5
Contract-based intangibles		1.2		(0.2	)		1.0		1.2		(0.2	)		1.0
Segment total		207.0		(115.2	)		91.8		207.0		(105.5	)		101.5
Petrochemical & Refined Products Services:
Customer relationship intangibles		104.7		(22.5	)		82.2		104.6		(18.8	)		85.8
Contract-based intangibles		41.7		(17.7	)		24.0		42.1		(13.9	)		28.2
Segment total		146.4		(40.2	)		106.2		146.7		(32.7	)		114.0
Total all segments	$	2,755.0	$	(894.7	)	$	1,860.3	$	1,859.8	$	(795.0	)	$	1,064.8

(1) In May 2010, we acquired $895.0 million of customer relationship intangible assets in connection with the State Line and Fairplay natural gas gathering systems. See Note 8 for additional information regarding this business combination.

The following table presents amortization expense related to our intangible assets for the periods indicated:

		For the Three Months Ended September 30,								For the Nine Months Ended September 30,
		2010				2009

Enterprise GP Holdings L.P. 10-Q