Enterprise GP 10Q 2005 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2005 or

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

For the transition period from _______ to _______.

Commission file number: 1-32610

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)

2727 North Loop West, Houston, Texas 77008-1044
(Address of Principal Executive Offices) (Zip Code)

Registrant’s Telephone Number, including area code: (713) 426-4500

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 o NO x

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

YES o NO x

There were 88,884,116 common units of Enterprise GP Holdings L.P. outstanding at October 31, 2005. Enterprise GP Holdings L.P.’s common units trade on the New York Stock Exchange under the symbol “EPE.”

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
	and Comprehensive Income......................................................................	3
	Unaudited Condensed Statements of Consolidated Cash Flows..................	4
	Unaudited Condensed Statements of Consolidated Partners’ Equity...........	5
	Notes to Unaudited Condensed Consolidated Financial Statements:
	1. Partnership Organization and Basis of Financial
	Statement Presentation ....................................................................	6
	2. General Accounting Policies and Related Matters ..............................	9
	3. Business Combinations.........................................................................	15
	4. Inventories............................................................................................	17
	5. Property, Plant and Equipment.............................................................	18
	6. Investments in and Advances to Unconsolidated Affiliates.................	19
	7. Intangible Assets and Goodwill............................................................	21
	8. Debt Obligations...................................................................................	22
	9. Partners' Equity.....................................................................................	27
	10. Related Party Transactions....................................................................	29
	11. Supplemental Cash Flows Disclosure....................................................	32
	12. Financial Instruments.............................................................................	33
	13. Business Segment Information...............................................................	34
	14. Earnings Per Unit...................................................................................	38
	15. Condensed Financial Information of Operating Partnership..................	39
	16. Commitments and Contingencies.........................................................	40
	17. Certain Significant Risks and Uncertainties - Hurricanes....................	42
	18. Subsequent Event ............................................................................	43
Item 2.	Management's Discussion and Analysis of Financial Condition
	and Results of Operations. .........................................................................	44
Item 3.	Quantitative and Qualitative Disclosures about Market Risk. .................	73
Item 4.	Controls and Procedures. .............................................................................	75

PART II. OTHER INFORMATION.
Item 1.	Legal Proceedings. .........................................................................................	77
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds. ...................	77
Item 3.	Defaults upon Senior Securities. ..................................................................	77
Item 4.	Submission of Matters to a Vote of Security Holders. ................................	77
Item 5.	Other Information. .........................................................................................	77
Item 6.	Exhibits. ..........................................................................................................	78

Signature page	...........................................................................................................................	85

PART I. FINANCIAL INFORMATION.

ITEM 1. FINANCIAL STATEMENTS.

ENTERPRISE GP HOLDINGS L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

				September 30,	December 31,
ASSETS				2005	2004

Current assets
	Cash and cash equivalents			$ 33,155	$ 25,006
	Restricted cash			6,893	26,157
	Accounts and notes receivable - trade, net of allowance for doubtful accounts
		of $24,620 at September 30, 2005 and $24,310 at December 31, 2004		1,292,571	1,058,375
	Accounts receivable - related parties			202	25,151
	Inventories			573,091	189,019
	Assets held for sale				36,562
	Prepaid and other current assets			105,430	80,893
			Total current assets	2,011,342	1,441,163
Property, plant and equipment, net				8,415,573	7,831,467
Investments in and advances to unconsolidated affiliates				470,033	519,164
Intangible assets, net of accumulated amortization of $141,682 at
	September 30, 2005 and $74,183 at December 31, 2004			941,484	980,601
Goodwill				489,444	459,198
Deferred tax asset				5,530	6,467
Long-term receivables				14,741	14,931
Other assets				41,969	62,910
			Total assets	$ 12,390,116	$ 11,315,901

LIABILITIES AND PARTNERS' EQUITY
Current liabilities
	Current maturities of debt			$ 164,000	$ 18,450
	Accounts payable - trade			82,321	203,144
	Accounts payable - related parties			17,985	41,293
	Accrued gas payables			1,392,426	1,021,294
	Accrued expenses			82,436	130,051
	Accrued interest			71,702	73,151
	Other current liabilities			131,856	104,979
			Total current liabilities	1,942,726	1,592,362
Long-term debt				4,788,840	4,629,219
Other long-term liabilities				74,337	63,739
Minority interest				4,879,358	4,956,543
Commitments and contingencies
Partners' equity
	Limited partners			684,659	49,478
	General partner			10	6
	Accumulated other comprehensive income			20,186	24,554
			Total partners' equity	704,855	74,038
			Total liabilities and partners’ equity	$ 12,390,116	$ 11,315,901

See Notes to Unaudited Condensed Consolidated Financial Statements

ENTERPRISE GP HOLDINGS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS

AND COMPREHENSIVE INCOME

(Dollars in thousands, except per unit amounts)

	For the Three Months		For the Nine Months
	Ended September 30,		Ended September 30,
	2005	2004	2005	2004
REVENUES
Third parties	$ 3,130,327	$ 1,801,946	$ 8,218,476	$ 4,862,082
Related parties	118,964	238,325	258,105	596,425
Total	3,249,291	2,040,271	8,476,581	5,458,507
COST AND EXPENSES
Operating costs and expenses
Third parties	2,967,579	1,704,953	7,748,068	4,537,821
Related parties	77,766	246,614	211,054	688,571
Total operating costs and expenses	3,045,345	1,951,567	7,959,122	5,226,392
General and administrative costs
Third parties	5,014	4,576	19,161	8,706
Related parties	8,640	5,724	28,528	18,363
Total general and administrative costs	13,654	10,300	47,689	27,069
Total costs and expenses	3,058,999	1,961,867	8,006,811	5,253,461
EQUITY IN INCOME OF UNCONSOLIDATED AFFILIATES	3,703	14,289	14,563	42,224
OPERATING INCOME	193,995	92,693	484,333	247,270
OTHER INCOME (EXPENSE)
Interest expense	(61,348)	(32,471)	(171,507)	(96,956)
Interest expense – related parties	(3,978)		(15,306)
Other, net	1,408	599	3,590	932
Other expense	(63,918)	(31,872)	(183,223)	(96,024)
INCOME BEFORE PROVISION FOR INCOME TAXES, MINORITY
INTEREST AND CHANGES IN ACCOUNTING PRINCIPLES	130,077	60,821	301,110	151,246
Provision for income taxes	(3,223)	(662)	(3,958)	(2,706)
INCOME BEFORE MINORITY INTEREST AND
CHANGES IN ACCOUNTING PRINCIPLES	126,854	60,159	297,152	148,540
Minority interest	(111,553)	(56,499)	(261,549)	(127,085)
INCOME BEFORE CHANGES IN ACCOUNTING PRINCIPLES	15,301	3,660	35,603	21,455
Cumulative effect of changes in accounting principles (see Note 2)				216
NET INCOME	15,301	3,660	35,603	21,671
Cash flow financing hedges		(85,126)		19,405
Amortization of cash flow financing hedges	(1,017)	(105)	(3,018)	(311)
Change in fair value of commodity hedges	84		(1,350)
COMPREHENSIVE INCOME	$ 14,368	$ (81,571)	$ 31,235	$ 40,765
ALLOCATION OF NET INCOME:
Limited partners' interest in net income	$ 15,299	$ 3,660	$ 35,599	$ 21,669
General partner interest in net income	$ 2		$ 4	$ 2
EARNINGS PER UNIT: (see Note 14)
Basic and diluted net income per unit	$ 0.19	$ 0.05	$ 0.46	$ 0.29

See Notes to Unaudited Condensed Consolidated Financial Statements

ENTERPRISE GP HOLDINGS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Dollars in thousands)

		For the Nine Months
		Ended September 30,
		2005	2004
OPERATING ACTIVITIES
Net income		$ 35,603	$ 21,671
Adjustments to reconcile net income to cash flows provided by operating activities:
	Depreciation and amortization in operating costs and expenses	304,041	94,674
	Depreciation in general and administrative costs	5,075	302
	Amortization in interest expense	(117)	2,868
	Equity in income of unconsolidated affiliates	(14,563)	(42,224)
	Distributions received from unconsolidated affiliates	47,388	54,580
	Provision for impairment of long-lived asset		4,016
	Cumulative effect of changes in accounting principles		(216)
	Operating lease expense paid by EPCO, Inc.	1,584	6,820
	Minority interest	261,549	127,085
	Loss (gain) on sale of assets	(4,742)	158
	Deferred income tax expense	5,827	6,293
	Changes in fair market value of financial instruments	122	82
	Net effect of changes in operating accounts (see Note 11)	(312,546)	(240,137)
Cash provided by operating activities		329,221	35,972
INVESTING ACTIVITIES
Capital expenditures		(627,913)	(39,435)
Contributions in aid of construction costs		40,368	490
Proceeds from sale of assets		43,220	110
Decrease (increase) in restricted cash		19,263	(3,036)
Cash used for business combinations, net of cash received		(325,080)	(1,065,269)
Acquisition of intangible asset		(1,750)
Investments in unconsolidated affiliates		(80,833)	(1,076)
Advances from unconsolidated affiliates		3,361	497
Return of investment from unconsolidated affiliate		47,500
Cash used in investing activities		(881,864)	(1,107,719)
FINANCING ACTIVITIES
Borrowings under debt agreements		3,912,345	3,958,000
Repayments of debt		(3,767,463)	(2,164,677)
Debt issuance costs		(8,380)	(3,450)
Borrowing proceeds held in escrow for tender offers			(1,100,000)
Distributions paid to minority interests		(478,900)	(259,289)
Contributions from minority interests		554,954	747,299
Distributions paid to partners		(24,764)	(8,728)
Net proceeds from issuance of common units in initial public offering		373,000
Settlement of cash flow financing hedges			19,405
Cash provided by financing activities		560,792	1,188,560
NET CHANGE IN CASH AND CASH EQUIVALENTS		8,149	116,813
CASH AND CASH EQUIVALENTS, JANUARY 1		25,006	30,466
CASH AND CASH EQUIVALENTS, SEPTEMBER 30		$ 33,155	$ 147,279

See Notes to Unaudited Condensed Consolidated Financial Statements

ENTERPRISE GP HOLDINGS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED PARTNERS’ EQUITY

(See Note 9 for Unit History)

(Dollars in thousands)

				Accumulated
				Other
		Limited	General	Comprehensive
		Partners	Partner	Income	Total
Balance, December 31, 2004		$ 49,478	$ 6	$ 24,554	$ 74,038
	Net income	35,599	4		35,603
	Distributions to partners	(24,764)			(24,764)
	Operating leases paid by EPCO, Inc.	44			44
	Amortization of equity-related awards	34			34
	Acquisition of minority interest from El Paso	90,845			90,845
	Contribution of net assets from sponsor affiliates
	in connection with initial public offering	160,604			160,604
	Net proceeds from initial public offering	373,000			373,000
	Change in fair value of commodity hedges			(1,350)	(1,350)
	Interest rate hedging financial instruments
	recorded as cash flow hedges:
	Amortization of gain as component
	of interest expense			(3,018)	(3,018)
	Other	(181)			(181)
Balance, September 30, 2005		$ 684,659	$ 10	$ 20,186	$ 704,855

See Notes to Unaudited Condensed Consolidated Financial Statements

ENTERPRISE GP HOLDINGS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1.	PARTNERSHIP ORGANIZATION AND BASIS
		OF FINANCIAL STATEMENT PRESENTATION

Partnership organization and formation

Enterprise GP Holdings L.P. is a publicly traded Delaware limited partnership listed on the New York Stock Exchange ("NYSE") under ticker symbol “EPE.” Enterprise GP Holdings L.P. ("Enterprise GP Holdings") was formed in April 2005 and completed its initial public offering of 14,216,784 common units in August 2005. For information regarding the initial public offering of Enterprise GP Holdings, see Note 9.

Enterprise GP Holdings is the sole member of Enterprise Products GP, LLC (“Enterprise Products GP”), which is the general partner of Enterprise Products Partners L.P. ("Enterprise Products Partners"). The primary business purpose of Enterprise Products GP is to manage the affairs and operations of Enterprise Products Partners, a North American energy company providing a wide range of processing, storage and transportation or midstream services to producers and consumers of natural gas, natural gas liquids (“NGLs”), and crude oil, and an industry leader in the development of pipeline and other midstream infrastructure in the continental United States and deepwater Gulf of Mexico. Enterprise Products Partners conducts substantially all of its business through a wholly owned subsidiary, Enterprise Products Operating L.P. (the “Operating Partnership”).

We are owned 99.99% by our limited partners and 0.01% by EPE Holdings LLC (our general partner, referred to as “EPE Holdings”). Enterprise GP Holdings, Enterprise Products GP, EPE Holdings, and Enterprise Products Partners are all affiliates and under common control of Dan L. Duncan, the Chairman and the controlling shareholder of EPCO, Inc. (“EPCO”). We and Enterprise Products GP have no independent operations outside those of Enterprise Products Partners.

Unless the context requires otherwise, references to “we,” “us,” “our,” “Enterprise GP Holdings” or the “Company” within these notes shall mean Enterprise GP Holdings L.P. and its consolidated subsidiaries, which include Enterprise Products GP and Enterprise Products Partners. On a standalone basis, Enterprise GP Holdings is referred to as the “parent company.” Also, “GulfTerra Merger” refers to the merger of GulfTerra Energy Partners, L.P. with a wholly owned subsidiary of Enterprise Products Partners on September 30, 2004 and the various transactions related thereto. References to “GulfTerra” mean Enterprise GTM Holdings L.P., the successor to GulfTerra Energy Partners, L.P. References to “GulfTerra GP” mean Enterprise GTMGP, L.L.C., which was formerly known as GulfTerra Energy Company, L.L.C., the general partner of GulfTerra Energy Partners, L.P. Enterprise GTMGP, L.L.C. is the general partner of Enterprise GTM Holdings L.P.

Contributions made by affiliates of EPCO in August 2005 in connection

with the initial public offering of Enterprise GP Holdings

In connection with the initial public offering of Enterprise GP Holdings, affiliates of EPCO contributed certain ownership interests in Enterprise Products Partners to Enterprise GP Holdings consisting of (i) 13,454,498 common units of Enterprise Products Partners acquired from an affiliate of El Paso Corporation ("El Paso") in January 2005 and (ii) a 100% ownership interest in Enterprise Products GP. Concurrent with the contribution of these ownership interests, Enterprise GP Holdings assumed $160 million of debt and $0.5 million of accrued interest from EPCO.

common control of EPCO. As consideration for these transfers, affiliates of EPCO received 74,667,332 common units (the “sponsor units”) of Enterprise GP Holdings.

Basis of presentation of consolidated financial statements

Our results of operations for the three and nine months ended September 30, 2005 are not necessarily indicative of results expected for the full year.

Except per unit amounts, or as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.

In accordance with generally accepted accounting principles, the transfer of net assets to us from affiliates of EPCO in August 2005 was accounted for as a reorganization of entities under common control in a manner similar to a pooling of interests. As a result, the historical consolidated financial information of Enterprise GP Holdings presented in this quarterly report on Form 10-Q for periods prior to its receipt of such contributions from EPCO has been presented using the consolidated financial information of Enterprise Products GP, which has been deemed the predecessor company of Enterprise GP Holdings.

The presentation of such unaudited predecessor condensed consolidated financial statements assumes that (i) the historical ownership interest in Enterprise Products GP held by El Paso (during the fourth quarter of 2004 and a portion of January 2005) was a third-party minority ownership interest in the net assets of such subsidiary and (ii) the historical ownership interests in Enterprise Products GP held by affiliates of EPCO (prior to the contribution of net assets from EPCO to us in August 2005) were owned by us. This method of presentation is substantially on the same basis that our consolidated results of operations and financial condition have been presented since the contribution of net assets from EPCO.

Since we own the general partner of Enterprise Products Partners, our unaudited condensed consolidated financial statements reflect the consolidated financial results of Enterprise Products Partners and its general partner. The amount of net earnings of Enterprise Products Partners allocated to its limited partner interests not owned by us is reflected as minority interest expense in our consolidated results of operations. Likewise, the amount of net assets of Enterprise Products Partners allocated to its limited partner interests not owned by us is reflected as minority interest in our consolidated balance sheet. Apart from such minority interest-related amounts, debt and interest expense recognized in connection with the parent company's borrowings, our consolidated financial statements do not differ materially from those of Enterprise Products Partners.

In the opinion of the Company, the accompanying unaudited condensed consolidated financial statements include all adjustments consisting of normal recurring accruals necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with generally accepted accounting principles in the United States of America ("GAAP") have been condensed or omitted pursuant to the rules and regulations of the U.S. Securities and Exchange Commission ("SEC").

Enterprise GP Holdings parent company-only financial information

Enterprise GP Holdings (the “parent company”) has no separate operating activities apart from those conducted by the Operating Partnership (see Note 15). The principal sources of cash flow for the parent company are its investments in the limited and general partner ownership interests in Enterprise Products Partners. The parent company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. The parent company-only assets and liabilities of Enterprise GP Holdings are not available to satisfy the debts and other obligations of Enterprise Products Partners and its consolidated subsidiaries.

In order to fully understand the financial condition and results of operations of the parent company on a standalone basis, we are providing the financial information of Enterprise GP Holdings apart from that of our consolidated partnership information included within this Item 1. The following financial statements reflect the transactions of Enterprise GP Holdings on a standalone basis since its formation in April 2005.

The following table shows the parent company's balance sheet data at September 30, 2005:

ASSETS
Current assets				$ 517
Investments in affiliates (1)				837,565
			Total assets	$ 838,082

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
	Current maturities of debt (2)			$ 149,000
	Other current liabilities (3)			4,405
		Total current liabilities		153,405
Partners’ equity (4)				684,677
			Total liabilities and partners’ equity	$ 838,082

(1) Represents Enterprise GP Holdings’ equity-method investments in Enterprise Products GP and Enterprise Products Partners. These ownership interests were contributed to Enterprise GP Holdings by affiliates of EPCO in August 2005 in connection with the initial public offering of Enterprise GP Holdings. These parent company-only investments are eliminated in the process of consolidating the financial statements of Enterprise GP Holdings with those of Enterprise Products GP and Enterprise Products Partners. (2) Represents borrowings outstanding under Enterprise GP Holdings $525 Million Credit Facility. For additional information regarding this parent company debt obligation, see Note 8. (3) Represents current payable amounts primarily related to accrued initial public offering expenses and interest. (4) Represents partner capital accounts recorded under generally accepted accounting principles including $373 million in net proceeds resulting from Enterprise GP Holdings’ initial public offering in August 2005.

The following table shows the parent company's statement of operations since its formation in April, 2005.

Equity in income of affiliates (1)	$ 2,146
General and administrative costs (2)	92
Operating income	2,054
Other income (expense)
Interest expense (3)	(1,109)
Interest income	13
Net income	$ 958

(1) Represents Enterprise GP Holdings’ earnings from its equity-method investments in Enterprise Products GP and Enterprise Products Partners. Enterprise GP Holdings obtained these investments as a result of net asset contributions from affiliates of EPCO that were made in connection with Enterprise GP Holdings initial public offering in August 2005; therefore, the equity earnings shown are for the period since the assets were contributed. (2) Represents parent company-only general and administrative costs since late August 2005. (3) Primarily represents interest expense associated with Enterprise GP Holdings $525 Million Credit Facility.

The following table shows the parent company's statement of cash flow since its formation in April 2005. As with Enterprise GP Holdings’ statement of operations, the cash flow information presented below primarily reflects activity since Enterprise GP Holdings’ initial public offering in late August 2005.

Operating activities
Net income		$ 958
Adjustments to reconcile net income to cash flows
used in operating activities:
	Equity in income of affiliates	(2,146)
	Net effect of changes in operating accounts	4,262
Cash used in operating activities		3,074
Investing activities
Investments in affiliates (1)		(364,456)
Cash used in investing activities		(364,456)
Financing activities
Borrowings under debt agreements (2)		525,000
Repayments of debt (3)		(536,246)
Contribution from general partner		1
Proceeds from issuance of common units in initial public offering (4)		373,000
Cash provided by financing activities		361,755
Net change in cash and cash equivalents		373
Cash and cash equivalents, beginning of period		-
Cash and cash equivalents, end of period		$ 373

(1) Represents cash contribution made to Enterprise Products GP in August 2005 using proceeds from Enterprise GP Holdings Credit Facility. Enterprise Products GP used this contribution to repay indebtedness owed to an affiliate of EPCO. (2) Represents Enterprise GP Holdings’ borrowings under its $525 Million Credit Facility (the “Enterprise GP Holdings' Credit Facility”) to repay (i) $364.5 million of indebtedness owed by Enterprise Products GP to an affiliate of EPCO that was originally incurred to finance Enterprise Products GP’s purchase of a 50% interest in the general partner of GulfTerra Energy Partners, L.P. in September 2004 and (ii) $160.5 million of debt assumed from EPCO as part of the contribution of net assets to Enterprise GP Holdings in August 2005. (3) Represents repayment of (i) $160.5 million of debt assumed from affiliates of EPCO using borrowings under Enterprise GP Holdings $525 Million Credit Facility and (ii) $376 million of borrowings under Enterprise GP Holdings Credit Facility using proceeds from Enterprise GP Holdings initial public offering. (4) Represents net proceeds from Enterprise GP Holdings’ initial public offering in August 2005.

Enterprise GP Holdings did not receive any cash distributions from Enterprise Products Partners or Enterprise Products GP during the period after the completion of its initial public offering, August 29, 2005, through September 30, 2005. Conversely, Enterprise GP Holdings did not make any parent company distributions to its partners during this period.

2. GENERAL ACCOUNTING POLICIES AND RELATED MATTERS

Use of estimates

In accordance with GAAP, we use estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during each reporting period. Our actual results could differ from these estimates.

New accounting pronouncements

Statement of Financial Accounting Standards ("SFAS") No. 123(R), “Share-Based Payment.” This accounting guidance, which is applicable for public companies the first fiscal year beginning on or after June 15, 2005, replaces SFAS No. 123, “Accounting for Stock-Based Compensation” and supersedes Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees.” This Statement eliminates the ability to account for share-based compensation transactions using APB No. 25, and generally requires instead that such transactions be accounted for using a fair-value-based method. We are continuing to evaluate the provisions of SFAS No. 123(R) and will adopt the standard on January 1, 2006. Upon the required effective date, we will apply this statement using a modified prospective application as described in the standard.

On March 29, 2005, the SEC issued Staff Accounting Bulletin ("SAB") 107 to provide public companies additional guidance in applying the provisions of SFAS No. 123(R). Among other things, SAB 107 describes the SEC staff’s expectations in determining the assumptions that underlie the fair value estimates and discusses the interaction of SFAS No. 123(R) with certain existing SEC guidance. The guidance is also beneficial to users of financial statements in analyzing the information provided under SFAS No. 123(R). We will apply the provisions of SAB 107 upon the adoption of SFAS No. 123(R).

FASB Interpretation ("FIN") 46(R)-5, “Implicit Variable Interests Under FASB Interpretation No. 46(R), Consolidation of Variable Interest Entities.” On March 3, 2005, the Financial Accounting Standards Board (“FASB”) issued this guidance to address whether a reporting enterprise has an implicit variable interest in a variable interest entity or potential variable interest entity when specific conditions exist. FIN 46(R)-5 covers issues that commonly arise in leasing arrangements among related parties, as well as other types of arrangements involving both related and unrelated parties. Implicit variable interests are implied financial interests in an entity’s net assets exclusive of variable interests. An implicit variable interest acts the same as in an explicit variable interest except it involves the absorbing and (or) receiving of variability indirectly from the entity (rather than directly). The identification of an implicit variable interest is a matter of judgment that depends on the relevant facts and circumstances. This guidance was effective for our fiscal quarter ended June 30, 2005, and our adoption of this guidance had no impact on our financial position, results of operations or cash flows.

FIN 47, "Accounting for Conditional Asset Retirement Obligations." Under SFAS No. 143, "Accounting for Asset Retirement Obligations," a company must record a liability for its legal obligations resulting from the eventual retirement of its tangible long-lived assets, whether that obligation results from the acquisition, construction, or development of the asset. However, many companies have not recorded a liability, concluding that either (1) the conditional nature of the obligation does not create a liability until the retirement activity occurs or (2) the timing and/or the method of settling the obligation is unknown. FIN 47 concludes otherwise. If required legally, an obligation associated with the asset’s retirement is inevitable even though uncertainties exist about the timing and/or method of settling the obligation. According to FIN 47, these uncertainties affect the fair value of the liability, rather than prevent the need to record one at all. Additionally, the ability of a company to postpone indefinitely the settlement of the obligation, or to sell the asset prior to its retirement, does not relieve a company of its present duty to settle the obligation. We are currently determining the effect of adopting FIN 47 on our asset retirement obligations. We will adopt FIN 47 in December 2005.

SFAS No. 154, "Accounting Changes and Error Corrections." This accounting guidance, which replaces APB No. 20, "Accounting Changes" and SFAS No. 3, "Reporting Accounting Changes in Interim Financial Statements - an amendment of APB No. 28," provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to the newly adopted accounting principle. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. We will adopt the provisions of SFAS No. 154 as applicable beginning in fiscal 2006.

Emerging Issues Task Force ("EITF") Issue No. 04-13, "Accounting for Purchases and Sale of Inventory With the Same Counterparty," In September 2005, the FASB ratified the EITF consensus relating to entities that may sell inventory to another entity in the same line of business from which it also purchases inventory. The purchase and sale transactions may be pursuant to a single contractual arrangement or separate contractual arrangements and the inventory purchased or sold may be in the form of raw materials, work-in-process, or finished goods. The EITF reached a consensus that two or more inventory transactions with the same counterparty should be viewed as a single nonmonetary transaction for purposes of applying APB No. 29, ”Accounting for Nonmonetary Transactions," if the transactions were entered into in contemplation of one another. The EITF reached a consensus to account for exchanges of inventory in the same line of business at fair value or recorded amounts based on inventory classification. This guidance is effective for new (including renegotiated or modified) inventory arrangements entered into in the first interim or annual reporting period beginning after March 15, 2006. We are studying this guidance to determine if it has any effect on us.

Financial statements – changes in accounting principles and reclassifications

The cumulative effect of changes in accounting principles during 2004 represents the combined impact of changing (i) the method our Belvieu Environmental Fuels, L.P. (“BEF”) subsidiary uses to account for its planned major maintenance activities from the accrue-in-advance method to the expense-as-incurred method and (ii) the method we used to account for our investment in Venice Energy Services Company, LLC (“VESCO”). The cumulative effect of these changes in accounting principles resulted in a benefit of $10.8 million, of which $10.6 million was recorded as a reduction to minority interest expense.

Certain reclassifications have been made to the prior year’s financial statements to conform to the current year presentation. In accordance with SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements,” we have reclassified amounts related to our adoption of EITF 03-16, “Accounting for Investments in Limited Liability Companies,” on July 1, 2004. Our adoption of EITF 03-16 on that date required us to change our method of accounting for our 13.1% investment in VESCO to the equity method from the cost method. Since this change in accounting principle was made during the third quarter of 2004, our statement of consolidated operations and statement of consolidated cash flows for the three and nine months ended September 30, 2004 has been recast for comparability purposes.

During the second quarter of 2005, we changed the classification of changes in restricted cash to present such changes as an investing activity in our Unaudited Condensed Consolidated Statement of Cash Flows. We previously presented such changes as an operating activity. In the accompanying Unaudited Condensed Consolidated Statement of Cash Flows for the nine months ended September 30, 2004, we reclassified the change in restricted cash to be consistent with our 2005 presentation which resulted in a $3 million increase to cash flows used in investing activities and a corresponding increase to cash provided by operating activities from the amounts previously presented.

Accounting for equity awards

Unit option plan accounting. Our unit option plan accounting is based on the intrinsic-value method described in APB No. 25, “Accounting for Stock Issued to Employees.” Under this method, no compensation expense is recorded related to options granted when the exercise price is equal to or greater than the market price of the underlying equity on the date of grant.

Employee Partnership equity-award accounting. In connection with our initial public offering in August 2005, EPE Unit L.P. (the “Employee Partnership”) was formed to allow certain employees of EPCO to increase their ownership in us and to serve as an incentive arrangement for such employees through a “profits interest” in the Employee Partnership. The Employee Partnership was formed on August 23, 2005 with EPCO as the general partner, Duncan Family Interests, Inc. (“DFI”) a subsidiary of EPCO, as the Class A limited partner, and certain EPCO employees, excluding Dan L. Duncan, as Class B limited partners. The Class B limited partners were admitted to the Employee Partnership without any capital contribution.

On August 29, 2005, DFI contributed $51 million to the Employee Partnership as a capital contribution with respect to its Class A limited partner interest, and the Employee Partnership used the funds to purchase 1,821,428 of our common units at our initial public offering price of $28.00 per unit. Pursuant to the terms of the partnership agreement of the Employee Partnership, DFI is entitled to receive (i) the Class A Capital Base, initially equal to the $51 million that DFI contributed to the Employee Partnership, and (ii) the Class A Preference Return, which is defined in the partnership agreement as a annual rate of return of 6.25% payable to DFI on the outstanding Class A Capital Base (which includes any accrued and unpaid Class A Preference Return).

The Employee Partnership will liquidate in August 2010, on the five-year anniversary of our initial public offering. Upon liquidation, the “profits interest” in the Employee Partnership will be distributed to the Class B limited partners. The value of the profits interest is equal to the then current market value of our common units multiplied by the 1,821,428 common units owned by the Employee Partnership, less the return to DFI of the Class A Capital Base outstanding.

EPCO will account for this share-based compensation arrangement under APB No. 25 until it adopts SFAS No. 123(R) on January 1, 2006. Under APB No. 25, the value of the Class B limited partnership interest (the “profits interest”) will be accounted for similar to a stock appreciation right. EPCO's compensation expense related to this share-based compensation arrangement is allocated to us and other affiliates of EPCO. For the three and nine months ended September 30, 2005, we were allocated $0.6 million of compensation expense associated with this share-based compensation arrangement.

Neither we, our general partner, Enterprise Products Partners nor Enterprise Products GP will reimburse EPCO, the Employee Partnership or any of their affiliates or partners, through the Administrative Services Agreement or otherwise, for (i) any expenses related to the Employee Partnership, (ii) the $51 million contribution to the Employee Partnership or (iii) the purchase of our units by the Employee Partnership.

Pro forma disclosures under SFAS No. 123. In accordance with SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure,” we disclose the pro forma effect on our earnings as if the fair value method of SFAS No. 123, “Accounting for Stock-Based Compensation” had been used instead of APB No. 25 to account for our equity awards. The effects of applying SFAS No. 123 in the following pro forma disclosure may not be indicative of future amounts as additional awards in future years are anticipated.

The fair value of each option grant of Enterprise Products Partners' units is estimated on the date of grant using the Black-Scholes option pricing model and various assumptions. For those options granted during 2005, we used the following assumptions to develop our Black-Scholes model estimates: (i) expected life of options of 7 years; (ii) risk-free interest rate of 4.2%, (iii) expected dividend yield on the units of 9.2% and (iv) expected unit price volatility of 20%.

The fair value of the Class B partnership equity award is estimated on the date of grant using the Black-Scholes option pricing model and various assumptions. We used the following assumptions to develop our Black-Scholes model estimate: (i) expected life of award of 5 years; (ii) risk-free interest rate of 4.1%; (iii) expected dividend yield on our units of 3.0% and (iv) expected unit price volatility on our units of 30%.

The following table shows the pro forma effects for the periods indicated.

		For the Three Months		For the Nine Months
		Ended September 30,		Ended September 30,
		2005	2004	2005	2004
Reported net income		$ 15,301	$ 3,660	$ 35,603	$ 21,671
Additional unit option-based compensation
	expense estimated using fair value-based method	(10)	(5)	(28)	(14)
Reduction in compensation expense related to
Employee Partnership equity awards		20		20
Pro forma net income		15,311	3,655	35,595	21,657
Multiplied by general partner ownership interest		0.01%	0.01%	0.01%	0.01%
General partner interest in pro forma net income		$ 2	$ 0	$ 4	$ 2

Pro forma net income		$ 15,311	$ 3,655	$ 35,595	$ 21,657
Less general partner interest in pro forma net income		(2)	(0)	(4)	(2)
Pro forma net income available to limited partners		$ 15,309	$ 3,655	$ 35,591	$ 21,655

Basic and diluted earnings per unit, net of general partner interest:
	Historical units outstanding	80,522	74,677	76,640	74,677
	As reported	$ 0.19	$ 0.05	$ 0.47	$ 0.29
	Pro forma	$ 0.19	$ 0.05	$ 0.46	$ 0.29

Accounting for employee benefit plans

During the first quarter of 2005, we acquired additional ownership interests in Dixie Pipeline Company (“Dixie”) that resulted in Dixie becoming a consolidated subsidiary of ours (see Note 3). Dixie employs the personnel who operate the Dixie pipeline. Dixie's employees are eligible to participate in Dixie's company-sponsored defined contribution plan. Additionally, certain Dixie employees are eligible to participate in Dixie's pension and postretirement benefit plans. At September 30, 2005, the preliminary estimated fair value of Dixie's employee benefit plan obligations was approximately $6.6 million, and is included in other long-term liabilities on our Unaudited Condensed Consolidated Balance Sheet. This valuation could change due to this transaction being so recent and future refinement of our estimate.

Defined contribution plan. Dixie sponsors a defined contribution plan in which its employees are eligible to participate. Dixie contributes 3% of eligible compensation to the plan (the "Automatic Contribution") for employees hired on or after July 1, 2004. Plan participants may contribute from 1% to 16% of their eligible compensation to the plan, and Dixie matches each participant's contributions up to a maximum of 6% of eligible compensation, less the Automatic Contribution amount. For the three and nine months ended September 30, 2005, Dixie contributed approximately $0.1 million and $0.2 million, respectively, to its defined contribution plan.

Pension and postretirement benefit plans. Certain Dixie employees hired prior to July 1, 2004, are eligible to participate in Dixie's pension and postretirement benefit plans. Dixie's pension plan is a noncontributory defined benefit plan that provides for the payment of benefits to retirees based on age at retirement, years of credited service, and average compensation. Dixie's postretirement benefit plan provides medical and life insurance to retired employees. The medical plan is contributory and the life insurance plan is noncontributory. Any Dixie employee retiring on or after July 1, 2004 will receive postretirement benefits only until such retiree becomes eligible for Medicare benefits.

The following table shows the components of Dixie's net pension and postretirement benefit costs for the periods indicated:

	Pension plan		Postretirement plan
	Three	Nine	Three	Nine
	Months	Months	Months	Months
	Ended	Ended	Ended	Ended
	September 30, 2005		September 30, 2005
Service cost	$ 113	$ 263	$ 22	$ 52
Interest cost	128	300	60	140
Expected return on plan assets	(89)	(208)
Amortization of transition obligation			37	86
Amortization of prior service cost	(3)	(8)	(67)	(156)
Amortization of net loss	21	49	3	6
Net periodic benefit cost	$ 170	$ 396	$ 55	$ 128

During the remainder of 2005, Dixie expects to contribute approximately $0.1 million to its postretirement benefit plan. Dixie does not expect to make additional contributions to its pension plan during the remainder of 2005.

Minority interest

Minority interest represents third-party and related party ownership interests in the net assets of certain of our subsidiaries. For financial reporting purposes, the assets and liabilities of our majority owned subsidiaries are consolidated with those of our own, with any third-party investor's ownership in our consolidated balance sheet amounts shown as minority interest. The following table shows the components of minority interest at the dates indicated:

	September 30,	December 31,
	2005	2004
Third-party owners of Enterprise Products GP		$ 90,845
Limited partners of Enterprise Products Partners:
Non-affiliates of Enterprise Products GP	$ 4,344,811	4,305,309
Affiliates of Enterprise Products GP	444,316	489,349
Joint venture partners	90,231	71,040
Total minority interest on consolidated balance sheet	$ 4,879,358	$ 4,956,543

The minority interest attributable to third-party ownership of Enterprise Products GP consists of El Paso’s 9.9% member interest during the fourth quarter of 2004. We granted El Paso a 9.9% member interest in Enterprise Products GP in connection with the GulfTerra Merger. In January 2005, an affiliate of EPCO acquired El Paso’s 9.9% membership interest in Enterprise Products GP and 13,454,498 common units of Enterprise Products Partners from El Paso for approximately $425 million in cash. Upon completion of EPCO’s purchase of El Paso’s 9.9% ownership interest in Enterprise Products GP, EPCO and its affiliates owned 100% of the membership interests in Enterprise Products GP.

The minority interest attributable to the limited partners of Enterprise Products Partners consists of common units held by the public and affiliates of the Company (primarily EPCO), and is net of unamortized deferred compensation of $15.5 million and $10.9 million at September 30, 2005 and December 31, 2004, respectively, which represents the value of restricted common units of Enterprise Products Partners issued to key employees of EPCO.

The minority interest attributable to joint venture partners as of September 30, 2005, is primarily attributable to our partners in Tri-States, Seminole, Wilprise, Independence Hub, Dixie and Belle Rose. As of December 31, 2004, the minority interest attributable to joint venture partners is primarily attributable to our partners in Tri-States, Seminole, Wilprise, Independence Hub and the Mid-America pipeline system.

The following table reflects the components of minority interest expense for the periods indicated:

		For the Three Months		For the Nine Months
		Ended September 30,		Ended September 30,
		2005	2004	2005	2004
Limited partners of Enterprise Products Partners		$ 110,599	$ 53,350	$ 258,362	$ 120,238
Joint venture partners and other		954	3,149	3,187	6,847
	Minority interest expense	$ 111,553	$ 56,499	$ 261,549	$ 127,085

The following table shows distributions paid to and contributions from minority interests attributable to each component of minority interest for the periods indicated:

		For the Three Months		For the Nine Months
		Ended September 30,		Ended September 30,
		2005	2004	2005	2004
Distributions paid to minority interests:
	Limited partners of Enterprise Products Partners	$ 162,323	$ 88,962	$ 473,409	$ 253,964
	Joint venture partners	1,337	3,272	5,491	5,325
		$ 163,660	$ 92,234	$ 478,900	$ 259,289
Contributions from minority interests:
	Limited partners of Enterprise Products Partners	$ 11,767	$ 337,447	$ 526,467	$ 747,299
	Joint venture partners	4,923		28,487
		$ 16,690	$ 337,447	$ 554,954	$ 747,299

Distributions paid to the limited partners of Enterprise Products Partners primarily represent the quarterly cash distributions paid by Enterprise Products Partners in accordance with its partnership agreement. Contributions from the limited partners of Enterprise Products Partners primarily represent proceeds Enterprise Products Partners received from common unit offerings. For additional information regarding our distributions, please see Note 10.

Use of industry terms in report

As used within this quarterly report, the following industry terms have the following meanings:

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

3. BUSINESS COMBINATIONS

As summarized below, during the nine months ended September 30, 2005, we completed several acquisitions and recorded purchase accounting adjustments related to the GulfTerra Merger.

Indian Springs acquisition in January 2005. In January 2005, we paid $74.5 million for membership interests in Teco Gas Gathering, LLC and Teco Gas Processing, LLC. As a result of this acquisition, we indirectly own an 80% equity interest in the 89-mile Indian Springs Gathering System and a 75% equity interest in the Indian Springs natural gas processing facility, both of which are located in East Texas. The Indian Springs processing facility has capacity to process up to 120 MMcf/d of natural gas and there is an idle 20 MMcf/d production train available for restart to support increases in natural gas volumes.

The natural gas processed at the Indian Springs processing facility is sourced from the Indian Springs Gathering System, as well as our nearby Big Thicket Gathering System.

Acquisition of additional interests in Dixie in January and February 2005. We purchased an approximate 20% interest in Dixie in January 2005 for $31 million and an approximate 26% interest in Dixie in February 2005 for $40 million. As a result of these acquisitions, our ownership interest in Dixie increased to approximately 66% and Dixie became a consolidated subsidiary of ours in February 2005. Dixie owns and operates a 1,301-mile natural gas liquid ("NGL") pipeline, which transports propane from supply areas in Texas, Louisiana and Mississippi to markets throughout the southeastern United States.

Acquisition of additional interests in Mid-America and Seminole Pipelines in June 2005. We exercised our option to acquire a 2% indirect ownership interest in the Mid-America Pipeline System and a 1.6% indirect interest in the Seminole pipeline for a total purchase price of $25 million. As a result of this transaction, we indirectly own 100% of the Mid-America Pipeline System and 90% of the Seminole pipeline. The Mid-America Pipeline System is a 7,226-mile NGL pipeline system located in the central and western regions of the United States. The Seminole pipeline is a 1,281-mile NGL pipeline that interconnects with the Mid-America Pipeline System at the Hobbs Hub on the Texas-New Mexico border and extends to Mont Belvieu, Texas.

Acquisition of NGL underground storage and terminaling assets in July 2005. We purchased three NGL underground storage facilities and four propane terminals from Ferrellgas L.P. ("Ferrellgas") in July 2005 for $144 million in cash. The underground storage facilities are located in Kansas, Arizona and Utah and have a combined capacity of 6.1 MMBbls. Approximately 70% of the aggregate storage capacity is leased to third party customers under fee-based contracts. The four propane terminals are located in Minnesota and North Carolina. The Minnesota facilities are connected to our Mid-America Pipeline System, and the North Carolina terminals are connected by rail to our facilities on the Gulf Coast. As part of the transaction, Ferrellgas has contracted with us to maintain a certain level of storage volume and terminal throughput for five years with the option to extend for an additional five years.

Other. During the nine months ended September 30, 2005, we made purchase price adjustments related to the GulfTerra Merger, and we revised our preliminary purchase price allocation related to the GulfTerra Merger. The purchase price adjustments of $7 million, which increased our overall consideration paid to complete the GulfTerra Merger, were primarily attributable to merger-related financial advisory services and involuntary severance costs, both of which were attributable to the GulfTerra Merger. As of September 30, 2005, our purchase price and purchase price allocation related to the GulfTerra Merger were final.

The GulfTerra Merger was completed on September 30, 2004, when GulfTerra merged with a wholly owned subsidiary of Enterprise. The aggregate value of total consideration Enterprise paid or issued to complete the GulfTerra Merger was approximately $4 billion. Our final purchase price allocation for the GulfTerra Merger includes an estimated recovery of $26.2 million, which represents the probable recovery of expenditures for property damage to certain offshore operations due to the effects of Hurricane Ivan, a Category 3 hurricane that struck the U.S. Gulf Coast in September 2004 prior to the GulfTerra Merger. If our final recovery is different than this amount, we will recognize an income impact at that time. See Note 17 for additional information regarding loss contingencies associated with such storm events.

In addition, we purchased an approximate 41.7% interest in Belle Rose NGL Pipeline LLC ("Belle Rose) in June 2005 for approximately $4.5 million in cash. As a result of this acquisition, our indirect ownership interest in Belle Rose increased to 83.4% and Belle Rose became a consolidated subsidiary of ours in June 2005. The 48-mile Belle Rose NGL pipeline transports mixed NGLs to NGL fractionation facilities located in Louisiana.

Allocation of purchase price for 2005 business combinations and

other purchase accounting adjustments

The acquisitions and purchase price adjustments described previously were accounted for under the purchase method of accounting and, accordingly, the cost of each has been allocated to the assets acquired and liabilities assumed based on their estimated preliminary fair values as follows:

						Mid-
				Indian		America &	Ferrellgas
				Springs	Dixie	Seminole	Assets	Other (2)	Total
Purchase price allocation:
	Assets acquired in business combination:
		Current assets		$ 252	$ 1,729		$ 3,679	$ 2,217	$ 7,877
		Property, plant and equipment, net		41,572	91,417	$ 9,390	137,472	20,968	300,819
		Investments in and advances to
		unconsolidated affiliates (1)			(36,279)			(10,017)	(46,296)
		Intangible assets		19,095			6,528	1,009	26,632
		Other assets			31,515			(3,694)	27,821
			Total assets acquired	60,919	88,382	9,390	147,679	10,483	316,853
	Liabilities assumed in business combination:
		Current liabilities			(4,963)		14	(4,761)	(9,710)
		Long-term debt			(9,982)				(9,982)
		Other long-term liabilities			(5,949)		(3,693)		(9,642)
		Minority interest			(4,615)	15,610		(4,007)	6,988
			Total liabilities assumed		(25,509)	15,610	(3,679)	(8,768)	(22,346)
			Total assets acquired less liabilities assumed	60,919	62,873	25,000	144,000	1,715	294,507
			Total consideration given	74,854	68,608	25,000	144,000	12,618	325,080
	Goodwill			$ 13,935	$ 5,735	$ -	$ -	$ 10,903	$ 30,573

(1) Represents carrying value of our investment prior to consolidation. (2) Includes purchase accounting adjustments for the GulfTerra Merger and Belle Rose transactions.

The purchase price allocations related to our Indian Springs, Dixie, Ferrellgas and Belle Rose acquisitions are preliminary. We engaged an independent third-party business valuation expert to assess the fair value of the tangible and intangible assets pertaining to these transactions. This information will assist management in the development of definitive allocations of the overall purchase prices for these transactions. The allocation of the purchase price for additional interests in Dixie reflects preliminary estimates of Dixie’s pension and postretirement obligations. Management independently developed the fair value estimates for our acquisition of additional interests in the Mid-America and Seminole pipelines using recognized business valuation techniques.

4. INVENTORIES

Our inventories consisted of the following at the dates indicated:

	September 30,	December 31,
	2005	2004
Working inventory	$ 399,351	$ 171,485
Forward-sales inventory	173,740	17,534
Inventory	$ 573,091	$ 189,019

Our regular trade (or “working”) inventory is comprised of inventories of natural gas, NGLs, and petrochemical products that are available for sale or used in the provision of services. The forward sales inventory is comprised of segregated NGL volumes dedicated to the fulfillment of forward-sales contracts. Both inventories are valued at the lower of average cost or market.

Costs and expenses, as shown on our Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income, include cost of sales related to inventories. For the three months ended September 30, 2005 and 2004, such consolidated cost of sales amounts were $2.7 billion and $1.8 billion, respectively. We recorded $7.1 billion and $4.8 billion of such consolidated cost of sales amounts for the nine months ended September 30, 2005 and 2004, respectively.

Due to fluctuating prices in the NGL, natural gas and petrochemical industry, we recognize lower of cost or market adjustments when the carrying values of our inventories exceed their net realizable value. These non-cash adjustments are charged to cost of sales within operating costs and expenses in the period they are recognized. For the three months ended September 30, 2005 and 2004, we recognized $0.5 million and $0.1 million, respectively, of such adjustments. We recorded $17.5 million and $6.1 million of such adjustments for the nine months ended September 30, 2005 and 2004, respectively.

5. PROPERTY, PLANT AND EQUIPMENT

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

	Estimated Useful	September 30,	December 31,
	Life in Years	2005	2004
Plants and pipelines (1)	5-35 (5)	$ 8,014,849	$ 7,691,197
Underground and other storage facilities (2)	5-35 (6)	678,154	531,394
Platforms and facilities (3)	23-31	163,214	162,645
Transportation equipment (4)	3-10	11,129	7,240
Land		30,324	29,142
Construction in progress		580,648	230,375
Total		9,478,318	8,651,993
Less accumulated depreciation		1,062,745	820,526
Property, plant and equipment, net		$ 8,415,573	$ 7,831,467

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

Depreciation expense for the three months ended September 30, 2005 and 2004 was $81.8 million and $28.6 million, respectively. We recorded $239.9 million and $83.3 million of depreciation expense for the nine months ended September 30, 2005 and 2004, respectively. Capitalized interest on our construction projects for the three months ended September 30, 2005 and 2004 was $4.6 million and $0.1 million, respectively. We recorded $12.2 million and $0.5 million of capitalized interest on our construction projects for the nine months ended September 30, 2005 and 2004, respectively.

6. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES

We own interests in a number of related businesses that are accounted for using the equity method. Our investments in and advances to our unconsolidated affiliates are grouped according to the business segment to which they relate. For a general discussion of our business segments, see Note 13. The following table shows our investments in and advances to unconsolidated affiliates at the dates indicated.

		Ownership	Investments in and advances to
		Percentage at	Unconsolidated Affiliates at
		September 30,	September 30,	December 31,
		2005	2005	2004
Offshore Pipelines & Services:
	Poseidon Oil Pipeline, L.L.C. (“Poseidon”)	36%	$ 63,053	$ 63,944
	Cameron Highway Oil Pipeline Company (“Cameron Highway”) (1)	50%	57,634	114,354
	Deepwater Gateway, L.L.C. (“Deepwater Gateway”)(2)	50%	116,927	56,527
	Neptune Pipeline Company, L.L.C. (“Neptune”)	25.67%	68,740	72,052
	Nemo Gathering Company, LLC (“Nemo”)	33.92%	11,691	12,586
Onshore Natural Gas Pipelines & Services:
	Evangeline (3)	49.5%	3,162	2,810
	Coyote Gas Treating, LLC (“Coyote”)	50%	1,776	2,441
NGL Pipelines & Services:
	Dixie Pipeline Company (“Dixie”) (4)			32,514
	Venice Energy Services Company, LLC (“VESCO”)	13.1%	38,731	38,437
	Belle Rose NGL Pipeline LLC (“Belle Rose”) (5)			10,172
	K/D/S Promix LLC (“Promix”)	50%	62,144	65,748
	Baton Rouge Fractionators LLC (“BRF”)	32.3%	25,933	27,012
Petrochemical Services:
	Baton Rouge Propylene Concentrator, LLC (“BRPC”)	30%	15,031	15,617
	La Porte (6)	50%	5,211	4,950
Total			$ 470,033	$ 519,164

(1) Cameron Highway began deliveries of Gulf of Mexico crude oil production to major refining markets along the Texas Gulf Coast during the first quarter of 2005. In June 2005, we received a $47.5 million return of our investment in Cameron Highway due to the refinancing of Cameron Highway’s project debt. For additional information regarding the refinancing of Cameron Highway's debt, please read Note 8. (2) In March 2005, we contributed $72 million to Deepwater Gateway to fund our share of the repayment of its $144 million term loan. For additional information regarding Deepwater Gateway's repayment of its term loan, please read Note 8. (3) Refers to our ownership interests in Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp., collectively. (4) We acquired an additional 20% ownership interest in Dixie in January 2005 and an additional 26.1% ownership interest in February 2005. As a result of these acquisitions, Dixie became a consolidated subsidiary. (5) We acquired an additional 41.7% ownership interest in Belle Rose in June 2005. As a result of this acquisition, Belle Rose became a consolidated subsidiary. (6) Refers to our ownership interests in La Porte Pipeline Company, L.P. and La Porte GP, LLC, collectively.

In connection with obtaining regulatory approval for the GulfTerra Merger, we were required by the U.S. Federal Trade Commission ("FTC") to sell our ownership interest in Starfish Pipeline Company, LLC ("Starfish") by March 31, 2005. The $36.6 million carrying value of this investment was classified as "Assets held for sale" on our balance sheet at December 31, 2004. On March 31, 2005, we sold this asset to a third-party for $42.1 million in cash and realized a gain on the sale of $5.5 million.

On occasion, the price we pay to acquire an investment exceeds the carrying value of the underlying historical net assets (i.e., the underlying equity account balances on the books of the investee) that we purchase. These excess cost amounts are a component of our investments in and advances to unconsolidated affiliates. At September 30, 2005, our investments in Promix, La Porte, Neptune, Poseidon, Cameron Highway and Nemo included excess cost. At September 30, 2005, excess cost amounts included in our investments in and advances to unconsolidated affiliates totaled $48.6 million, which was attributed to tangible assets. Amortization of our excess cost amounts attributed to tangible assets was $0.5 million and $0.4 million during the three months ended September 30, 2005 and 2004, respectively. For the nine months

ended September 30, 2005 and 2004, amortization of such amounts was $1.7 million and $1.3 million, respectively.

The following table shows our equity in income of unconsolidated affiliates by business segment for the periods indicated:

		For the Three Months		For the Nine Months
		Ended September 30,		Ended September 30,
		2005	2004	2005	2004
Offshore Pipelines & Services (1)		$ 2,321	$ 720	$ 4,221	$ 2,576
Onshore Natural Gas Pipelines & Services		604	158	1,866	314
NGL Pipelines & Services		773	2,407	8,058	6,349
Petrochemical Services		5	245	418	960
Other (2)			10,759		32,025
	Total	$ 3,703	$ 14,289	$ 14,563	$ 42,224

(1) Equity earnings from Cameron Highway for the nine months ended September 30, 2005 were reduced by a charge of $11.5 million for costs associated with the refinancing of Cameron Highway's project debt (see Note 8). The reduction in equity earnings from Cameron Highway for the nine months ended September 30, 2005, is offset by increases in equity earnings from investments we acquired in connection with the GulfTerra Merger. (2) This category represents equity income from GulfTerra GP. In connection with the GulfTerra Merger, GulfTerra GP became a wholly owned consolidated subsidiary on September 30, 2004. We had previously accounted for our 50% ownership interest in GulfTerra GP as an equity method investment from December 15, 2003 through September 29, 2004.

Summarized financial information of unconsolidated affiliates

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

	Summarized Income Statement Information for the Three Months Ended
	September 30, 2005			September 30, 2004
		Operating	Net		Operating	Net
	Revenues	Income	Income	Revenues	Income	Income
Offshore Pipelines & Services	$ 364,873	$ 34,044	$ 26,591	$ 25,030	$ 14,695	$ 12,209
Onshore Natural Gas Pipelines & Services	96,809	633	1,216	80,360	3,290	1,292
NGL Pipelines & Services	54,816	5,267	5,671	60,563	9,867	9,889
Petrochemical Services	3,782	281	298	4,377	1,094	1,104

	Summarized Income Statement Information for the Nine Months Ended
	September 30, 2005			September 30, 2004
		Operating	Net		Operating	Net
	Revenues	Income	Income	Revenues	Income	Income
Offshore Pipelines & Services	$ 925,738	$ 67,840	$ 25,026	$ 60,129	$ 28,740	$ 22,680
Onshore Natural Gas Pipelines & Services	232,217	6,835	3,539	200,519	9,695	3,695
NGL Pipelines & Services	194,162	33,100	34,102	87,896	15,003	15,029
Petrochemical Services	11,829	2,130	2,169	13,928	4,012	4,023

7. INTANGIBLE ASSETS AND GOODWILL

Intangible assets

The following table summarizes our intangible assets (which primarily consists of contracts and customer relationships) by segment at the dates indicated:

	At September 30, 2005			At December 31, 2004
	Gross	Accum.	Carrying	Accum.	Carrying
	Value	Amort.	Value	Amort.	Value
Offshore Pipelines & Services	$ 207,012	$ (26,436)	$ 180,576	$ (6,965)	$ 200,047
Onshore Natural Gas Pipelines & Services	457,798	(35,383)	422,415	(8,875)	446,267
NGL Pipelines & Services	361,682	(73,161)	288,521	(53,135)	282,963
Petrochemical Services	56,674	(6,702)	49,972	(5,208)	51,324
Total	$ 1,083,166	$ (141,682)	$ 941,484	$ (74,183)	$ 980,601

During the nine months ended September 30, 2005, we recorded an additional $28.4 million of intangible assets primarily due to acquisitions and changes in our purchase accounting estimates.

The following table shows amortization expense by segment associated with our intangible assets for the periods indicated:

		For the Three Months		For the Nine Months
		Ended September 30,		Ended September 30,
		2005	2004	2005	2004
Offshore Pipelines & Services		$ 6,261		$ 19,471
Onshore Natural Gas Pipelines & Services		8,690		26,510
NGL Pipelines & Services		6,555	$ 3,413	20,027	$ 10,066
Petrochemical Services		498	493	1,495	1,485
	Total	$ 22,004	$ 3,906	$ 67,503	$ 11,551

For the remainder of 2005, amortization expense associated with these intangible assets is currently estimated at $21.7 million.

Goodwill

The following table summarizes our goodwill amounts by segment at the dates indicated. Of the $489.4 million of goodwill we have recorded as of September 30, 2005, $387.1 million relates to goodwill we recorded in connection with the GulfTerra Merger.

		September 30,	December 31,
		2005	2004
Offshore Pipelines & Services		$ 82,386	$ 62,348
Onshore Natural Gas Pipelines & Services		282,840	290,397
NGL Pipelines & Services		50,528	32,763
Petrochemical Services		73,690	73,690
	Totals	$ 489,444	$ 459,198

8. DEBT OBLIGATIONS

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

			September 30,	December 31,
			2005	2004
Parent company debt obligation:
	$525 Million Credit Facility, variable rate, due February 2006		$ 149,000
Enterprise Products GP related party obligation:
	$370 Million Note, 6.25% fixed-rate, repaid August 2005 (1)			$ 366,433
Operating Partnership debt obligations:
	364-Day Acquisition Credit Facility, variable rate, repaid in February 2005 (2)			242,229
	Multi-Year Revolving Credit Facility, variable rate, due October 2010 (3)		335,000	321,000
	30-Day Promissory Note, variable rate, repaid October 2005 (4)		100,000
	Seminole Notes, 6.67% fixed-rate, due December 2005		15,000	15,000
	Pascagoula MBFC Loan, 8.70% fixed-rate, due March 2010		54,000	54,000
	Senior Notes A, 8.25% fixed-rate, repaid March 2005			350,000
	Senior Notes B, 7.50% fixed-rate, due February 2011		450,000	450,000
	Senior Notes C, 6.375% fixed-rate, due February 2013		350,000	350,000
	Senior Notes D, 6.875% fixed-rate, due March 2033		500,000	500,000
	Senior Notes E, 4.00% fixed-rate, due October 2007		500,000	500,000
	Senior Notes F, 4.625% fixed-rate, due October 2009		500,000	500,000
	Senior Notes G, 5.60% fixed-rate, due October 2014		650,000	650,000
	Senior Notes H, 6.65% fixed-rate, due October 2034		350,000	350,000
	Senior Notes I, 5.00% fixed-rate, due March 2015		250,000
	Senior Notes J, 5.75% fixed-rate, due March 2035		250,000
	Senior Notes K, 4.95% fixed-rate, due June 2010		500,000
	Dixie revolving credit facility, due June 2007		17,000
	GulfTerra Senior Notes and Senior Subordinated Notes (5)		5,673	6,469
		Total principal amount	4,975,673	4,655,131
Other, including unamortized discounts and premiums and changes in fair value (6)			(22,833)	(7,462)
		Subtotal long-term debt	4,952,840	4,647,669
Less current maturities of debt (7)			(164,000)	(18,450)
		Long-term debt	$ 4,788,840	$ 4,629,219

Standby letters of credit outstanding			$ 66,411	$ 139,052

(1) This amount was repaid in August 2005 using borrowings under our $525 Million Credit Facility. (2) Enterprise Products Partners used the proceeds from its February 2005 common unit offering to fully repay and terminate the 364-Day Acquisition Credit Facility. (3) At September 30, 2005 and December 31, 2004, the Multi-Year Revolving Credit Facility had a $750 million borrowing capacity, which was reduced by the amount of standby letters of credit outstanding. In October 2005, the Operating Partnership executed an amended Multi-Year Revolving Credit Facility, which among other things, (i) increased the borrowing capacity to $1.25 billion, which is reduced by the amount of standby letters of credit outstanding, (ii) extended the maturity date from September 2009 to October 2010 and (iii) removed the $100 million limit on the total amount of standby letters of credit that can be outstanding under the facility. For additional information regarding the amended Multi-Year Revolving Credit Facility, please see Note 18. (4) The Operating Partnership used borrowings under the Multi-Year Revolving Credit Facility to repay the 30-Day Promissory Note in October 2005. (5) GulfTerra’s remaining $0.8 million of 6.25% Senior Notes due June 2010 were called and retired in February 2005. Additionally, in October 2005, we called and retired $0.6 million of GulfTerra' Senior Subordinated Notes. (6) The September 30, 2005 amount includes $8.5 million related to fair value hedges and $14.3 million in net unamortized discounts. (7) In accordance with SFAS No. 6, "Classification of Short-Term Obligations Expected to Be Refinanced," long-term and current maturities of debt at September 30, 2005, reflected our repayment of the 30-Day Promissory Note in October 2005 using borrowings under our Multi-Year Revolving Credit Facility, which is due October 2010. Additionally, in accordance with SFAS No. 6, long-term and current maturities of debt at December 31, 2004 reflected (i) our refinancing of Senior Notes A with proceeds from our Senior Notes I and J in March 2005 and (ii) the repayment of our 364-Day Acquisition Credit Facility using proceeds from an equity offering completed in February 2005.

Letters of credit

At September 30, 2005, we had $66.4 million in standby letters of credit outstanding, of which $40 million was associated with a letter of credit facility we entered into during November 2004 in connection with our Independence Trail capital project and the remaining amounts were issued under our Multi-Year Revolving Credit Facility. At December 31, 2004, we had $139.1 million of standby letters of credit outstanding, of which $115 million was associated with the Independence Trail letter of credit facility. The decrease in standby letters of credit outstanding since December 31, 2004 under our Independence Trail letter of credit facility is the result of construction payments made in connection with the Independence Trail capital project. In late October 2005, the letter of credit facility associated with the Independence Trail capital project expired.

Parent company debt obligation

$525 Million Credit Facility. On August 29, 2005, we entered into a $525 million credit facility consisting of a $475 million term loan and a $50 million revolving credit facility, both maturing in February 2006. Additionally, on August 29, 2005, we borrowed $525 million under the new facility to repay (i) the indebtedness owed by Enterprise Products GP to an affiliate of EPCO that was originally incurred to finance Enterprise Products GP's purchase of a 50% interest in GulfTerra's general partner and (ii) the $160.5 million of debt we assumed from EPCO as part of the contribution of net assets to us (see Note 1) by affiliates of EPCO. We used the proceeds from our August 2005 initial public offering to repay some of the borrowings under the new credit facility. At September 30, 2005, we had approximately $124.5 million of borrowings outstanding under the $475 million term loan portion of the new credit facility and approximately $25.5 million of liquidity under the $50 million revolving portion of the new credit facility.

Borrowings under the credit facility are secured by (i) a pledge by us of the 13,454,498 common units of Enterprise Products Partners that we own and (ii) a pledge by us of our 100% membership interest in Enterprise Products GP.

As defined by the credit facility, variable interest rates charged under this facility generally will bear interest, at our election at the time of each borrowing, at (1) the greater of (a) the interest rate per annum publicly announced by Citibank N.A. as its prime rate or (b) the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System arranged by Federal funds brokers, as published by the Federal Reserve Bank of New York plus ½ of 1%, in either case plus an applicable margin of 1%; or LIBOR plus an applicable margin of 2.25%.

The credit facility contains various covenants related to our ability, and the ability of certain of its subsidiaries (including Enterprise Products GP), to incur certain indebtedness, grant certain liens, make fundamental structural changes, make distributions following an event of default and enter into certain restrictive agreements. The credit facility also requires us to satisfy certain financial covenants at the end of each fiscal quarter.

Enterprise Products GP related party obligation

$370 Million Note Payable. In September 2004, Enterprise Products GP borrowed $370 million from an affiliate of EPCO to fund the cash portion of consideration paid to El Paso for a 50% membership interest in GulfTerra's general partner. This related party promissory note bore a fixed-interest rate of 6.25%. Installment payments of $6.6 million were due quarterly from November 2004 through November 2019. Under terms of the note agreement, we were allowed to defer up to $13.2 million of scheduled quarterly installment payments at any time, except that all principal and accrued interest must be repaid by the November 2019 maturity date. On August 29, 2005, this note payable was repaid in full using borrowings under Enterprise GP Holdings' new $525 million credit facility.

Enterprise Products Partners-Subsidiary guarantor relationships

Enterprise Products Partners acts as guarantor of the debt obligations of the Operating Partnership, with the exception of the Seminole Notes, the Dixie revolving credit facility and the senior subordinated notes of GulfTerra. If the Operating Partnership were to default on any debt Enterprise Products Partners guarantees, Enterprise Products Partners would be responsible for full repayment of that obligation.

The Operating Partnership’s senior indebtedness is structurally subordinated to and ranks junior in right of payment (but only to the extent that payment is dependent upon the assets and operations of GulfTerra, Dixie and Seminole) to the indebtedness of GulfTerra, Dixie and Seminole. The Seminole Notes are unsecured obligations of Seminole Pipeline Company (of which we own 90% of its capital stock). The Dixie revolving credit facility is an unsecured obligation of Dixie (of which we own 66% of its capital stock). The senior subordinated notes of GulfTerra are unsecured obligations of GulfTerra (of which we own 100% of its limited and general partnership interests).

Operating Partnership debt obligations

Multi-Year Revolving Credit Facility. In October 2005, the borrowing capacity under this facility was increased from $750 million to $1.25 billion. See Note 18 for additional information.

30-Day Promissory Note. In September 2005, the Operating Partnership borrowed $100 million under a 30-day promissory note to provide the Operating Partnership with additional borrowing capacity ahead of the amended Multi-Year Revolving Credit Facility. The promissory note was repaid using borrowings under the Operating Partnership's amended Multi-Year Revolving Credit Facility. For additional information regarding the amended Multi-Year Revolving Credit Facility, please see Note 18.

Senior Notes E, F, G and H. In September 2004, the Operating Partnership priced a private offering of an aggregate of $2 billion in principal amount of senior unsecured notes in a transaction exempt from the registration requirements under the Securities Act of 1933, as amended, and in October 2004, these notes were issued. In January 2005, we filed a registration statement for an offer to exchange these notes for registered debt securities with identical terms. The exchange of notes was completed in March 2005.

Senior Notes I and J. In February 2005, the Operating Partnership sold $500 million in principal amount of senior notes in a Rule 144A private placement offering, comprised of $250 million in principal amount of 10-year senior unsecured notes and $250 million in principal amount of 30-year senior unsecured notes. The 10-year notes ("Senior Notes I") were issued at 99.379% of their principal amount and have annual fixed-rate interest of 5.00% and a maturity date of March 1, 2015. The 30-year notes ("Senior Note J") were issued at 98.691% of their principal amount and have annual fixed-rate interest of 5.75% and a maturity date of March 1, 2035. The Operating Partnership used the net proceeds from the issuance of Senior Notes I and J to repay $350 million of indebtedness outstanding under Senior Notes A, which was due on March 15, 2005, and the remaining proceeds for general partnership purposes, including the temporary repayment of indebtedness outstanding under the Multi-Year Revolving Credit Facility. In July 2005, we filed a registration statement for an offer to exchange these notes for registered debt securities with identical terms. The exchange of notes was completed in August 2005.

These fixed-rate notes are unsecured obligations of the Operating Partnership and rank equally with its existing and future unsecured and unsubordinated indebtedness. The Operating Partnership’s borrowings under these notes are non-recourse to Enterprise Products GP. Enterprise Products Partners has guaranteed repayment of amounts due under these notes through an unsecured and unsubordinated guarantee, which is also non-recourse to Enterprise Products GP. These notes were issued under an indenture containing certain covenants, which restrict our ability, with certain exceptions, to incur debt secured by liens and engage in sale and leaseback transactions.

Senior Notes K. In June 2005, the Operating Partnership sold $500 million in principal amount of five-year senior unsecured notes. These notes were issued at 99.834% of their principal amount and have a

fixed-rate interest of 4.95% and a maturity date of June 1, 2010. The Operating Partnership used the net proceeds from the issuance of these notes to temporarily reduce indebtedness outstanding under the Multi-Year Revolving Credit Facility and for general partnership purposes, including capital expenditures and business combinations.

Dixie. Dixie has a senior unsecured revolving credit facility with a borrowing capacity of $28 million. As defined by the credit agreement, variable interest rates charged under this facility generally bear interest, at our election at the time of each borrowing, at either (i) a Eurodollar rate plus an applicable margin or (ii) the greater of (a) the Prime Rate or (b) the Federal Funds Rate by 1/2%. This revolving credit agreement contains various covenants related to Dixie’s ability to incur certain indebtedness; grant certain liens; enter into merger transactions; and make certain investments. The loan agreement also requires Dixie to satisfy a minimum net worth financial covenant.

Petal Industrial Development Revenue Bonds. In April 2004, Petal Gas Storage L.L.C. ("Petal"), one of our wholly owned subsidiaries, borrowed $52 million from the Mississippi Business Finance Corporation ("MBFC") pursuant to a loan agreement between Petal and the MBFC. On the same date, the MBFC issued $52 million in Industrial Development Bonds to another one of our wholly owned subsidiaries. Petal had the option to repay the loan agreement without penalty, and thus cause the Industrial Development Revenue Bonds to be redeemed, any time after one year from their date of issue. In August 2005, Petal exercised its option to repay the loan agreement and the $52 million in Industrial Development Bonds were redeemed and retired.

Prior to redemption, we netted the loan amount and the bond amount and the interest payable and interest receivable amounts on our balance sheet. Additionally, we netted the interest expense and interest income amounts attributable to these instruments on our statements of consolidated operations and comprehensive income. This presentation was reflected in accordance with the provisions of FIN 39, "Offsetting of Amounts Related to Certain Contracts," and SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities," since we had the ability and intent to offset these items.

Covenants

We are in compliance with all covenants of our consolidated debt agreements at September 30, 2005 and December 31, 2004.

Information regarding variable interest rates paid

The following table shows the range of interest rates paid and weighted-average interest rate paid on our significant consolidated variable-rate debt obligations during the nine months ended September 30, 2005.

	Range of	Weighted-average
	interest rates	interest rate
	paid	paid
Enterprise GP Holdings' Credit Facility	5.91% to 7.50%	5.96%
Enterprise Products Partners' 364-Day Acquisition Credit Facility	3.25% to 3.40%	3.30%
Enterprise Products Partners' Multi-Year Revolving Credit Facility	3.22% to 6.75%	3.91%
Enterprise Products Partners' 30-Day Promissory Note	4.66%	4.66%

Consolidated debt maturity table

The following table shows scheduled maturities of the principal amounts of our debt obligations for the next 5 years and in total thereafter.

2005	$ 15,000
2006	149,000
2007	517,000
2009	500,000
Thereafter	3,794,673
Total scheduled principal payments	$ 4,975,673

In accordance with SFAS No. 6, "Classification of Short-Term Obligations Expected to Be Refinanced," the amount shown in the table above for 2005 excludes the $100 million due under our 30-Day Promissory Note at September 30, 2005. We refinanced this short-term obligation using borrowings from our Multi-Year Revolving Credit Facility in October 2005. As a result, we have reclassified this amount to long-term debt and shown it as a component of principal amounts due after 2009.

Joint venture debt obligations

We have three unconsolidated affiliates with long-term debt obligations. The following table shows (i) our ownership interest in each entity at September 30, 2005, (ii) total long-term debt obligations (including current maturities) of each unconsolidated affiliate at September 30, 2005, on a 100% basis to the joint venture and (iii) the corresponding scheduled maturities of such long-term debt.

	Our		Scheduled Maturities of Long-Term Debt
	Ownership							After
	Interest	Total	2005	2006	2007	2008	2009	2009
Cameron Highway	50.0%	$ 415,000		$ 415,000
Poseidon	36.0%	96,000				$ 96,000
Evangeline	49.5%	35,650	$ 5,000	5,000	$ 5,000	5,000	$ 5,000	$ 10,650
Total		$ 546,650	$ 5,000	$ 420,000	$ 5,000	$ 101,000	$ 5,000	$ 10,650

The credit agreements of our joint ventures each contain various affirmative and negative covenants, including financial covenants. Our joint ventures were in compliance with all such covenants at September 30, 2005.

Extinguishment of Deepwater Gateway credit agreement in March 2005. In accordance with terms of its credit agreement, Deepwater Gateway had the right to repay the principal amount plus any accrued interest due under its term loan at any time without penalty. During the first quarter of 2005, Deepwater Gateway exercised this right and extinguished its term loan. We and our 50% joint venture partner in Deepwater Gateway made equal cash contributions of $72 million to Deepwater Gateway to fund the repayment of the $144 million in principal amount owed under Deepwater Gateway's term loan.

Refinancing of Cameron Highway debt in June 2005. In June 2005, Cameron Highway executed an Amended and Restated Credit Agreement with a total credit commitment of $415 million and borrowed the full amount. This 364-day loan matures in June 2006 and is secured by (i) mortgages on and pledges of substantially all of the assets of Cameron Highway, (ii) mortgages on and pledges of certain assets related to certain rights of way and pipeline assets of an indirect wholly-owned subsidiary of Enterprise Products Partners that serves as the operator of the Cameron Highway Oil Pipeline, (iii) pledges by Enterprise Products Partners and its joint venture partner in Cameron Highway of their 50% partnership interests in Cameron Highway, and (iv) letters of credit in the amount of $14 million each issued by the Operating Partnership and an affiliate of our joint venture partner. Except for the foregoing, the Cameron Highway lenders do not have any recourse against the assets of Enterprise Products Partners under the amended credit agreement.

A portion of the proceeds of the loan were used to refinance Cameron Highway’s existing $325 million project debt and to make cash distributions to the owners of Cameron Highway. In connection with this refinancing, Cameron Highway incurred approximately $22 million in one-time make whole premiums and related fees and costs, which include $6.3 million of non-cash charges. Our equity earnings from Cameron Highway for the second quarter of 2005 were reduced by our 50% share of such costs.

As defined in the amended credit agreement, variable interest rates charged to Cameron Highway under this loan generally bear interest, at Cameron Highway’s election from time to time, at either (i) the greater of (a) the Prime Rate or (b) the Federal Funds Rate plus 1/2%, or (ii) a Eurodollar rate plus an applicable margin.

The amended credit agreement contains various covenants restricting Cameron Highway’s ability to incur certain indebtedness; grant certain liens; enter into certain merger or consolidation transactions; make certain investments; make certain restricted payments; enter into certain hedging agreements; enter into certain transactions with affiliates; form any subsidiaries; make any material changes in the Cameron Highway pipeline system; enter into any sale and leaseback transaction; or enter into or amend certain other agreements. The amended loan agreement also requires Cameron Highway to satisfy certain financial covenants at the end of each fiscal quarter.

9.	PARTNERS’ EQUITY

General

We are a Delaware limited partnership that was formed in April 2005 to become the sole member of Enterprise Products GP, which is the general partner of Enterprise Products Partners. We are owned 99.99% by our limited partners and 0.01% by EPE Holdings. EPE Holdings is owned 100% by Dan Duncan, LLC, which is wholly-owned by Dan L. Duncan. In connection with the contribution of net assets by affiliates of EPCO to us in August 2005 (see Note 1), EPCO affiliates received 74,667,332 of our common units.

Our common units represent limited partner interests, which give the holders thereof the right to participate in distributions and to exercise the other rights or privileges available to them under our First Amended and Restated Agreement of Limited Partnership (the "Partnership Agreement"). Our common units trade on the NYSE under the ticker symbol "EPE." We are managed by our general partner, EPE Holdings.

Capital accounts, under the Partnership Agreement, are maintained for our general partner and our limited partners. The capital account provisions of our Partnership Agreement incorporate principles established for U.S. Federal income tax purposes and are not comparable to the equity accounts reflected under GAAP in our consolidated financial statement. Earnings and cash distributions are allocated to our partners in accordance with their respective percentage interests.

In April 2005, we filed a registration statement regarding an initial public offering of our common units. In August 2005, we sold 14,216,784 common units under this registration statement (including an over-allotment amount of 1,616,784 common units) at an offering price of $28.00 per common unit. Total net proceeds from the sale of these common units was approximately $373 million after deducting applicable underwriting discounts, commissions, structuring fees and other offering expenses of $25.6 million. The net proceeds from this initial public offering were used to reduce debt outstanding under Enterprise GP Holdings' $525 Million Credit Facility.

Unit History

The following table details the outstanding balance of our common units for the periods and at the dates indicated:

Common units issued to affiliates of EPCO in connection with the contribution
of net assets to us in August 2005 (the “sponsor units”)	74,667,332
Common units issued in August 2005 in connection with initial public offering	14,216,784
Balance, September 30, 2005	88,884,116

As described in Note 1, the consolidated financial information presented under Item 1 of this quarterly report for periods prior to August 2005 is based on the consolidated financial information of our predecessor, Enterprise Products GP. Our earnings per unit amounts for periods prior to our initial public offering in August 2005 assume that affiliates of EPCO owned the sponsor units during those periods.

Accumulated Other Comprehensive Income

The following table summarizes the effect of our cash flow hedging financial instruments (see Note 12) on accumulated other comprehensive income (“AOCI”) since December 31, 2004.

		Interest Rate Fin. Instrs.		Accumulated
			Forward-	Other
	Commodity		Starting	Comprehensive
	Financial	Treasury	Interest	Income
	Instruments	Locks	Rate Swaps	Balance
Balance, December 31, 2004	$ 1,434	$ 4,572	$ 18,548	$ 24,554
Change in fair value of commodity financial instruments	(1,350)			(1,350)
Reclassification of gain on settlement of treasury locks to interest expense		(331)		(331)
Reclassification of gain on settlement of forward-starting swaps to interest expense			(2,687)	(2,687)
Balance, September 30, 2005	$ 84	$ 4,241	$ 15,861	$ 20,186

During the remainder of 2005, we will reclassify a combined $1 million from accumulated other comprehensive income as a reduction in interest expense from our treasury locks and forward-starting interest rate swaps. In addition, we reclassified an approximate $1.4 million gain into income from accumulated other comprehensive income related to a commodity cash flow hedge acquired in the GulfTerra Merger. This gain is primarily due to an increase in fair value from that recorded for the commodity cash flow hedge at September 30, 2004.

Distributions

Our cash distribution policy is consistent with the terms of our Partnership Agreement, which requires that we distribute to partners our available cash (as defined in our Partnership Agreement) no later than 50 days after the end of each fiscal quarter. Our quarterly cash distributions are not cumulative. As a result, if distributions on our units are not paid at the targeted levels, our unitholders will not be entitled to receive such payments in the future.

Our cash generating assets currently consist only of our partnership interests in Enterprise Products Partners from which we receive quarterly distributions. At September 30, 2005, Enterprise GP Holdings' assets (on a parent company basis) consist of the following partnership interests in Enterprise Products Partners:

•

a 100% ownership interest of Enterprise Products GP, which owns a 2% general partner interest in Enterprise Products Partners that entitles Enterprise GP Holdings to receive 2% of the cash distributed by Enterprise Products Partners;

•

the incentive distribution rights associated with Enterprise Products GP's general partner interest in Enterprise Products Partners, which entitle Enterprise GP Holdings to receive increasing percentages of the cash distributed by Enterprise Products Partners (up to a maximum of 25% of Enterprise Products Partners' quarterly distributions that exceed $0.3085 per unit); and

•

13,454,498 common units of Enterprise Products Partners, representing an approximate 3.4% limited partner interest in Enterprise Products Partners.

Since our primary source of operating cash flow currently consists of cash distributions from Enterprise Products Partners, the amount of distributions we are able to make to our unitholders may fluctuate based on the level of distributions Enterprise Products Partners makes to its partners. If Enterprise Products Partners does not have sufficient available cash from Operating Surplus (as defined in Enterprise Products Partners' Partnership Agreement), or if the Operating Partnership is not able to satisfy certain financial covenants in accordance with its credit agreements, Enterprise Products Partners will be restricted from making distributions to its partners.

The primary restriction on our Operating Partnership’s ability to make cash distributions to Enterprise Products Partners and hence to us, is a financial covenant in the Operating Partnership’s Multi-Year Revolving Credit Facility that requires the Operating Partnership to maintain capital accounts of at least $4 billion. At September 30, 2005, the Operating Partnership’s equity accounts totaled $5.6 billion.

In addition, if we are not able to satisfy certain financial covenants in accordance with our $525 Million Credit Facility, we will be restricted from making distributions to our partners. As of September 30, 2005, we and Enterprise Products Partners are in compliance with the various covenants of our debt agreements.

On November 10, 2005, we expect to pay a prorated quarterly distribution of $0.092 per unit (based on our initial declared quarterly distribution of $0.265 per unit) for the 32-day period beginning on August 30, 2005 (the day after the completion date of our initial public offering) to September 30, 2005.

10. RELATED PARTY TRANSACTIONS

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

		For the Three Months		For the Nine Months
		Ended September 30,		Ended September 30,
		2005	2004	2005	2004
Revenues from consolidated operations
	EPCO and subsidiaries	$ 1	$ 129	$ 287	$ 2,347
	Shell		148,821		397,805
	Unconsolidated affiliates	118,963	89,375	257,818	196,273
	Total	$ 118,964	$ 238,325	$ 258,105	$ 596,425
Operating costs and expenses
	EPCO and subsidiaries	$ 62,326	$ 49,762	$ 176,499	$ 128,389
	TEPPCO	3,976		12,625
	Shell		189,442		536,284
	Unconsolidated affiliates	11,464	7,410	21,930	23,898
	Total	$ 77,766	$ 246,614	$ 211,054	$ 688,571
Selling, general and administrative expenses
	EPCO	$ 8,640	$ 5,724	$ 28,528	$ 18,363
Interest Expense
	EPCO	$ 3,978		$ 15,306

Historically, Shell Oil Company, its subsidiaries and affiliates ("Shell") were collectively considered a related party because Shell owned more than 10% of Enterprise Products Partners' limited partner interests and, prior to September 2003, owned a 30% ownership interest in Enterprise Products GP. As a result of Shell selling a portion of its limited partner interests in Enterprise Products Partners to third parties in December 2004 and during the first seven months of 2005, Shell now owns less than 10% of

Enterprise Products Partners' common units. Shell sold its 30% interest in Enterprise Products GP to an affiliate of EPCO in September 2003. As a result of Shell's reduced equity interest in Enterprise Products Partners and its lack of control of Enterprise Products GP, Shell ceased to be considered a related party beginning in the first quarter of 2005.

Relationship with EPCO

We have an extensive and ongoing relationship with EPCO. Collectively, EPCO and its affiliates own an 86.5% equity interest in us at September 30, 2005. EPCO is controlled by Dan L. Duncan, who is also a director and Chairman of our general partner and Enterprise Products GP. Additionally, all of the executive officers and non-independent directors of our general partner also serve as executive officers or directors of Enterprise Products GP.

In August 2005, affiliates of EPCO contributed certain partnership interests in Enterprise Products Partners to the parent company consisting of (i) a 100% ownership of Enterprise Products GP and (ii) 13,454,498 common units of Enterprise Products Partners acquired from an affiliate of El Paso in January 2005, representing an approximate 3.4% limited partner interest in Enterprise Products Partners.

Administrative Services Agreement. We have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to the Administrative Services Agreement. We reimburse EPCO for the costs of its employees who perform operating functions for us and for costs related to its other management and administrative employees. Additionally, we reimburse EPCO for the costs associated with the office space we occupy related to our partnership's headquarters.

In August 2005, the Third Amended and Restated Administrative Services Agreement (the "Amended Agreement") was executed, which was effective as of February 24, 2005. The Amended Agreement reflects the following changes:

•

Enterprise GP Holdings, EPE Holdings, and the TEPPCO Parties (i.e., TEPPCO Partners, L.P., Texas Eastern Products Pipeline Company, LLC, TE Products Pipeline Company, Limited Partnership, TEPPCO Midstream Companies, L.P., TCTM, L.P. and TEPPCO GP, Inc.) were added as parties to the Agreement;

•

substantial revisions were made to the "Business Opportunities" section of the Agreement (see below);

•

an Exhibit was added to the Agreement describing the structure of corporate governance, policies and procedures (see below); and

•

other changes to reflect the new parties and procedures.

The "Business Opportunities" section of the Amended Agreement addresses conflicts that may arise among Enterprise Products Partners, Enterprise Products GP, Enterprise GP Holdings, EPE Holdings and the EPCO Group (defined as EPCO and its affiliates other than the parties to the Amended Agreement). This section of the Amended Agreement provides, among other things, that:

•

if a business opportunity to acquire equity securities (as defined in the Amended Agreement) is presented to the EPCO Group, Enterprise Products Partners, Enterprise Products GP, Enterprise GP Holdings or EPE Holdings, then Enterprise GP Holdings will have the first right to pursue such opportunity, and Enterprise Products Partners will have the second right to pursue such opportunity.

•

if any business opportunity not covered by the preceding bullet point is presented to the EPCO Group, Enterprise Products Partners, Enterprise Products GP, Enterprise GP Holdings or EPE Holdings, Enterprise Products Partners will have the first right to pursue such opportunity, and Enterprise GP Holdings will have the second right to pursue such opportunity.

Additionally, an Exhibit was added to the Amended Agreement, which outlines the corporate governance structure and policies and procedures to address potential conflicts among, protect the

confidential information of, and govern the sharing of EPCO personnel between the Partnership Entities ("Enterprise Products Partners, Enterprise Products GP, the Operating Partnership and the general partner of the Operating Partnership"), the TEPPCO Parties and Enterprise GP Holdings. The Exhibit provides, among other things, that:

•

there shall be no overlap in the independent directors of Enterprise Products GP, EPE Holdings and Texas Eastern Products Pipeline Company, LLC ("TEPPCO GP");

•

there shall be no overlap in the EPCO employees performing commercial and development activities involving certain defined potential overlapping assets for the Partnership Entities and Enterprise GP Holdings on one hand and the TEPPCO Parties on the other hand; and

•

certain screening procedures are to be followed if an EPCO employee performing commercial and development activities becomes privy to commercial information relating to a potential overlapping asset of any entity for which such employee does not perform commercial and development activities.

Other related party transactions with EPCO. The following is a summary of other significant ongoing related party transactions between EPCO and us.

•

We have entered into an agreement with an affiliate of EPCO to provide trucking services to us for the transportation of NGLs and other products.

•

In the normal course of business, we buy from and sell certain NGL products to an affiliate of EPCO.

In September 2004, our subsidiary, Enterprise Products GP, borrowed $370 million from an affiliate of EPCO to finance the purchase of a 50% membership interest in GulfTerra GP. This promissory note bore fixed-rate interest of 6.25% and was repaid in August 2005 using borrowings under the Enterprise GP Holdings Credit Facility. We recorded $3.1 million and $15.3 million in interest related to this promissory note for the three and nine months ended September 30, 2005.

We, Enterprise Products GP and Enterprise Products Partners are all separate legal entities from EPCO and its other affiliates, with assets and liabilities that are separate from those of EPCO and its other affiliates. EPCO depends on cash distributions it receives as an equity owner in us and Enterprise Products Partners to fund most of its other operations and to meet its debt obligations. For the nine months ended September 30, 2005 and 2004, EPCO affiliates received $185 million and $136.4 million in distributions from us, respectively. The ownership interests in Enterprise Products Partners and Enterprise Products GP that are owned or controlled by EPCO and its affiliates, other than Dan Duncan LLC and trusts affiliated with Dan L. Duncan, are pledged as security under an EPCO affiliate credit facility. In the event of a default under such credit facility, a change in control of Enterprise Products Partners or Enterprise Products GP could occur.

Relationship with TEPPCO

On February 24, 2005, an affiliate of EPCO acquired Texas Eastern Products Pipeline Company, LLC ("TEPPCO GP"), the general partner of TEPPCO Partners, L.P. (“TEPPCO”) from Duke Energy Field Services, LLC, and 2,500,000 common units of TEPPCO from Duke Energy Corporation for approximately $1.2 billion in cash. TEPPCO GP owns a 2% general partner interest in TEPPCO and is the managing partner of TEPPCO and its subsidiaries. Subsequently, EPCO reconstituted the board of directors of TEPPCO GP and Dr. Ralph Cunningham (a former independent director of Enterprise Products GP) was named Chairman of TEPPCO GP. Due to EPCO's ownership of TEPPCO GP and TEPPCO GP's ability to direct the management of TEPPCO, TEPPCO GP and TEPPCO became related parties to EPCO and the Company during the first quarter of 2005. The employees of TEPPCO became EPCO employees on June 1, 2005. Our related party transactions with TEPPCO consist of the purchase of NGL pipeline transportation and storage services.

On March 11, 2005, the Bureau of Competition of the FTC delivered written notice to EPCO’s legal advisor that it was conducting a non-public investigation to determine whether EPCO’s acquisition of

TEPPCO GP may tend substantially to lessen competition. No filings were required under the Hart-Scott-Rodino Act in connection with EPCO’s purchase of TEPPCO GP. EPCO and its affiliates, including us, may receive similar inquiries from other regulatory authorities and intend to cooperate fully with any such investigations and inquiries. In response to such FTC investigation or any inquiries EPCO and its affiliates may receive from other regulatory authorities, we may be required to divest certain assets. In the event we are required to divest significant assets, our financial condition could be affected.

Relationship with unconsolidated affiliates

Our significant related party transactions with unconsolidated affiliates consist of the sale of natural gas to Evangeline, purchase of pipeline transportation services from Dixie (prior to its consolidation with our results beginning in February 2005, see Note 3) and the purchase of NGL storage, transportation and fractionation services from Promix. In addition, we sell natural gas to Promix and process natural gas at VESCO.

11. SUPPLEMENTAL CASH FLOW DISCLOSURE

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

		For the Nine Months
		Ended September 30,
		2005	2004
Decrease (increase) in:
	Accounts and notes receivable	$ (201,932)	$ (204,275)
	Inventories	(386,057)	(187,519)
	Prepaid and other current assets	(31,636)	6,244
	Long-term receivables	202
	Other assets	49,484	(195)
Increase (decrease) in:
	Accounts payable	(143,166)	(28,275)
	Accrued gas payable	369,568	197,115
	Accrued expenses	20,325	2,038
	Accrued interest	(1,435)	(30,503)
	Other current liabilities	11,850	5,800
	Other liabilities	251	(567)
Net effect of changes in operating accounts		$ (312,546)	$ (240,137)

During the first nine months of 2005, we completed several acquisitions, made adjustments to the September 2004 purchase price allocation for the GulfTerra Merger and consolidated entities that had been previously accounted for using the equity method. See Note 3 for information regarding these transactions, including a table showing the various balance sheet accounts affected in the allocation of the various purchase prices.

On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of the capital expenditures associated with such projects. As a result of completing the GulfTerra Merger, the number of such arrangements has increased, particularly for projects involving pipeline construction and production well tie-ins. These reimbursements for the nine months ended September 30, 2005 and 2004, were $40.4 million and $0.5 million, respectively, and are reflected as a source of investing cash inflows under the caption "Contributions in aid of construction costs" on our Unaudited Condensed Statements of Consolidated Cash Flows.

Net income for the nine months ended September 30, 2005 includes a gain on the sale of assets of $4.7 million (recorded as a reduction in operating costs and expenses), which is primarily related to the sale of our 50% interest in Starfish. In connection with gaining regulatory approval for the GulfTerra Merger, we were required to sell our 50% interest in Starfish by March 31, 2005.

In June 2005, we received $47.5 million in cash from Cameron Highway as a return of investment. These funds were distributed to us in connection with the refinancing of Cameron Highway’s project debt (see Note 8).

In August 2005, various non-cash amounts were recorded by the parent company in connection with the contribution of net assets from affiliates of EPCO (see Note 1). In general, these contributions impacted investments, debt and partners’ equity.

12. FINANCIAL INSTRUMENTS

We are exposed to financial market risks, including changes in commodity prices and interest rates. We may use financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to mitigate the risks of certain identifiable and anticipated transactions. In general, the type of risks we attempt to hedge are those related to the variability of future earnings, fair values of certain debt instruments and cash flows resulting from changes in applicable interest rates or commodity prices. As a matter of policy, we do not use financial instruments for speculative (or “trading”) purposes.

Interest rate risk hedging program

Our interest rate exposure results from variable and fixed rate borrowings under debt agreements. We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar arrangements, which allow us to convert a portion of fixed rate debt into variable rate debt or a portion of variable rate debt into fixed rate debt.

In August 2005, the Operating Partnership entered into two additional interest rate swap agreements with an aggregate notional amount of $200 million in which we exchanged the payment of fixed rate interest on a portion of the principal outstanding under Senior Notes K for variable rate interest. We have designated these two interest rate swaps as fair value hedges under SFAS No. 133 , "Accounting for Derivative Instruments and Hedging Activities" (as amended and interpreted), since they mitigate changes in the fair value of the underlying fixed rate debt. Under each swap agreement, we will pay the counterparty a variable interest rate based on six-month LIBOR rates (plus an applicable margin as defined in each swap agreement) and receive back from the counterparty a fixed interest rate payment of 4.95%, which is the stated interest rate of Senior Notes K. We will settle amounts receivable from or payable to the counterparty every six months (the "settlement period"), with the first settlement occurring on December 1, 2005. The settlement amount will be amortized ratably to earnings as either an increase or a decrease in interest expense over the settlement period.

As summarized in the following table, we had eleven interest rate swap agreements outstanding at September 30, 2005 that were accounted for as fair value hedges.

		Number	Period Covered	Termination	Fixed to	Notional
Hedged Fixed Rate Debt		Of Swaps	by Swap	Date of Swap	Variable Rate (1)	Amount
Senior Notes B, 7.50% fixed rate, due Feb. 2011		1	Jan. 2004 to Feb. 2011	Feb. 2011	7.50% to 7.26%	$50 million
Senior Notes C, 6.375% fixed rate, due Feb. 2013		2	Jan. 2004 to Feb. 2013	Feb. 2013	6.375% to 5.81%	$200 million
Senior Notes G, 5.6% fixed rate, due Oct. 2014		6	4th Qtr. 2004 to Oct. 2014	Oct. 2014	5.6% to 4.36%	$600 million
Senior Notes K, 4.95% fixed rate, due June 2010		2	Aug. 2005 to June 2010	June 2010	4.95% to 4.34%	$200 million
	(1) The variable rate indicated is the all-in variable rate for the current settlement period.

The total fair value of these eleven interest rate swaps at September 30, 2005, was a liability of $9.6 million, with an offsetting decrease in the fair value of the underlying debt. The total fair value of the nine interest rate swaps we had outstanding at December 31, 2004, was an asset of $0.5 million, with an offsetting increase in the fair value of the underlying debt. Interest expense for the three months ended September 30, 2005 and 2004 reflects a benefit of $2.3 million and $1.7 million, respectively, from interest

rate swap agreements. For the nine months ended September 30, 2005 and 2004, interest expense reflects a benefit of $7.5 million and $5.3 million, respectively, from interest rate swap agreements.

During 2004, we entered into two groups of four forward-starting interest rate swap transactions having an aggregate notional amount of $2 billion each in anticipation of our financing activities associated with the closing of the GulfTerra Merger. These interest rate swaps were accounted for as cash flow hedges and were settled during 2004 at a net gain to us of $19.4 million, which will be reclassified from accumulated other comprehensive income to reduce interest expense over the life of the associated debt.

Commodity risk hedging program

The prices of natural gas, NGLs and petrochemical products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control. In order to manage the risks associated with natural gas and NGLs, we may enter into commodity financial instruments. The primary purpose of our commodity risk management activities is to hedge our exposure to price risks associated with (i) natural gas purchases, (ii) NGL production and inventories, (iii) related firm commitments, (iv) fluctuations in transportation revenues where the underlying fees are based on natural gas index prices and (v) certain anticipated transactions involving either natural gas or NGLs.

At September 30, 2005 and December 31, 2004, we had a limited number of commodity financial instruments in our portfolio, which primarily consisted of natural gas cash flow and fair value hedges. The fair value of our commodity financial instrument portfolio at September 30, 2005 and December 31, 2004 was an asset of $0.1 million and $0.2 million, respectively. Excluding the reclassification of amounts from AOCI (see Note 9), we recorded nominal amounts of earnings from our commodity financial instruments during the three and nine months ended September 30, 2005 and 2004.

13. BUSINESS SEGMENT INFORMATION

Business segments are components of a business about which separate financial information is available. The components are regularly evaluated by the CEO of Enterprise Products GP, the general partner of Enterprise Products Partners, in deciding how to allocate resources and in assessing performance. Generally, financial information is required to be reported on the basis that it is used internally for evaluating segment performance and deciding how to allocate resources to segments. Our business segments are generally organized and managed according to the type of services rendered and products produced and/or sold, as applicable. We have revised our prior segment information in order to conform to the current business segment operations and presentation.

We have segregated our business activities into four reportable business segments: Offshore Pipelines & Services, Onshore Natural Gas Pipelines & Services, NGL Pipelines & Services and Petrochemical Services. The Offshore Pipelines & Services business segment consists of (i) approximately 1,150 miles of offshore natural gas pipelines strategically located to serve production areas in some of the most active drilling and development regions in the Gulf of Mexico, (ii) approximately 810 miles of Gulf of Mexico offshore crude oil pipeline systems and (iii) seven multi-purpose offshore hub platforms located in the Gulf of Mexico.

The Onshore Natural Gas Pipelines & Services business segment consists of approximately 17,200 miles of onshore natural gas pipeline systems that provide for the gathering and transmission of natural gas in Alabama, Colorado, Louisiana, Mississippi, New Mexico and Texas. In addition, this segment includes two salt dome natural gas storage facilities located in Mississippi, which are strategically located to serve the Northeast, Mid-Atlantic and Southeast domestic natural gas markets. This segment also includes leased natural gas storage facilities located in Texas and Louisiana.

and (iii) NGL fractionation facilities located in Texas and Louisiana. This segment also includes our import and export terminaling operations.

The Petrochemical Services business segment includes four propylene fractionation facilities, an isomerization complex and an octane additive production facility. This segment also includes 530 miles of petrochemical pipeline systems.

The Other non-segment category is presented for financial reporting purposes only to reflect the historical equity earnings we received from GulfTerra GP. We acquired a 50% membership interest in GulfTerra GP on December 15, 2003 in connection with Step One of the GulfTerra Merger. Our investment in GulfTerra GP was accounted for using the equity method until the GulfTerra Merger was completed on September 30, 2004. On that date, GulfTerra GP became a wholly owned consolidated subsidiary of ours. Since the historical equity earnings of GulfTerra GP were based on net income amounts allocated to it by GulfTerra, it is impractical for us to allocate the equity income we received during the periods presented to each of our new business segments. Therefore, we have segregated equity earnings from GulfTerra GP from our other segment results to aid in comparability between the periods presented.

Our revenues are derived from a wide customer base. All consolidated revenues were earned in the United States. Most of our plant-based operations are located either along the western Gulf Coast in Texas, Louisiana and Mississippi or in New Mexico. Our natural gas, NGL and oil pipelines and related operations are in a number of regions of the United States including the Gulf of Mexico offshore Texas and Louisiana; the south and southeastern United States (primarily in Texas, Louisiana, Mississippi and Alabama); and certain regions of the central and western United States. Our marketing activities are headquartered in Houston, Texas, at our main office and serve customers in a number of regions in the United States including the Gulf Coast, West Coast and Mid-Continent areas.

We evaluate segment performance based on segment gross operating margin. Gross operating margin (either in total or by individual segment) is an important performance measure of the core profitability of our operations. This measure forms the basis of our internal financial reporting and is used by senior management in deciding how to allocate capital resources among business segments. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results.

We define total (or consolidated) segment gross operating margin as operating income before: (i) depreciation and amortization expense; (ii) operating lease expenses for which we do not have the payment obligation; (iii) gains and losses on the sale of assets; and (iv) general and administrative expenses. Gross operating margin is exclusive of other income and expense transactions, provision for income taxes, minority interest, extraordinary charges and the cumulative effect of changes in accounting principles. Gross operating margin by segment is calculated by subtracting segment operating costs and expenses (net of the adjustments noted above) from segment revenues, with both segment totals before the elimination of intercompany transactions.

Segment revenues and expenses include intersegment and intrasegment transactions, which are generally based on transactions made at market-related rates. Our consolidated revenues reflect the elimination of all material intercompany (both intersegment and intrasegment) transactions.

We include equity earnings from unconsolidated affiliates in our measurement of segment gross operating margin. Our equity investments with industry partners are a vital component of our business strategy. They are a means by which we conduct our operations to align our interests with those of our customers, which may be a supplier of raw materials or a consumer of finished products. This method of operation also enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed versus what we could accomplish on a stand-alone basis. Many of these businesses perform supporting or complementary roles to our other business operations. For example, we use the Promix NGL fractionator to process a portion of the mixed NGLs extracted by our gas plants. Another example was our use of the Dixie pipeline to transport propane sold to customers through our NGL marketing activities (prior to the consolidation of Dixie’s results with ours beginning in February 2005, see

Note 3). See Note 10 for additional information regarding our related party relationships with unconsolidated affiliates.

Consolidated property, plant and equipment and investments in and advances to unconsolidated affiliates are allocated to each segment on the basis of each asset's or investment's principal operations. The principal reconciling item between consolidated property, plant and equipment and segment assets is construction-in-progress. Segment assets represents those facilities and projects that contribute to gross operating margin and is net of accumulated depreciation on these assets. Since assets under construction generally do not contribute to segment gross operating margin, these assets are excluded from the business segment totals until they are deemed operational. Consolidated intangible assets and goodwill are allocated to each segment based on the classification of the assets to which they relate.

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

			For the Three Months		For the Nine Months
			Ended September 30,		Ended September 30,
			2005	2004	2005	2004
Revenues (1)			$ 3,249,291	$ 2,040,271	$ 8,476,581	$ 5,458,507
Less:	Operating costs and expenses (1)		(3,045,345)	(1,951,567)	(7,959,122)	(5,226,392)
Add:	Equity in income of unconsolidated affiliates (1)		3,703	14,289	14,563	42,224
	Depreciation and amortization in operating costs and expenses (2)		103,028	32,439	304,041	94,674
	Retained lease expense, net in operating expenses allocable to us
	and minority interest (3)		528	2,273	1,584	6,820
	Loss (gain) on sale of assets in operating costs and expenses (2)		611	43	(4,742)	158
		Total gross operating margin	$ 311,816	$ 137,748	$ 832,905	$ 375,991

(1) These amounts are taken from our Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income. (2) These non-cash expenses are taken from the operating activities section of our Unaudited Condensed Statements of Consolidated Cash Flows. (3) These non-cash expenses represent the value of the operating leases contributed by EPCO to us for which EPCO has retained the cash payment obligation (i.e., the “retained leases”). The value of the retained leases contributed directly to us is shown on our Unaudited Condensed Statements of Consolidated Cash Flows under the line item titled “Operating lease expense paid by EPCO.”

A reconciliation of our measurement of total segment gross operating margin to operating income and income before provision for income taxes, minority interest and the cumulative effect of changes in accounting principles follows:

		For the Three Months		For the Nine Months
		Ended September 30,		Ended September 30,
		2005	2004	2005	2004
Total gross operating margin		$ 311,816	$ 137,748	$ 832,905	$ 375,991
Adjustments to reconcile total gross operating margin
	to operating income:
	Depreciation and amortization in operating costs and expenses	(103,028)	(32,439)	(304,041)	(94,674)
	Retained lease expense, net in operating costs and expenses	(528)	(2,273)	(1,584)	(6,820)
	Gain (loss) on sale of assets in operating costs and expenses	(611)	(43)	4,742	(158)
	General and administrative costs	(13,654)	(10,300)	(47,689)	(27,069)
Consolidated operating income		193,995	92,693	484,333	247,270
	Other expense	(63,918)	(31,872)	(183,223)	(96,024)
Income before provision for income taxes, minority interest
	and cumulative effect of changes in accounting principles	$ 130,077	$ 60,821	$ 301,110	$ 151,246

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

			Operating Segments
			Offshore	Onshore	NGL			Adjustments
			Pipelines	Pipelines	Pipelines	Petrochem.	Non-Segmt.	and	Consolidated
			& Services	& Services	& Services	Services	Other	Eliminations	Totals
Revenues from third parties:
		Three months ended September 30, 2005	$ 25,018	$ 304,215	$ 2,426,672	$ 374,422			$ 3,130,327
		Three months ended September 30, 2004		77,432	1,361,317	363,197			1,801,946
		Nine months ended September 30, 2005	86,550	810,362	6,229,322	1,092,242			8,218,476
		Nine months ended September 30, 2004		285,206	3,599,905	976,971			4,862,082

Revenues from related parties:
		Three months ended September 30, 2005	203	106,870	11,869	22			118,964
		Three months ended September 30, 2004		84,891	151,002	2,432			238,325
		Nine months ended September 30, 2005	642	241,901	15,489	73			258,105
		Nine months ended September 30, 2004		189,328	399,537	7,560			596,425

Intersegment and intrasegment revenues:
		Three months ended September 30, 2005	403	10,047	792,744	106,598		$ (909,792)
		Three months ended September 30, 2004		3,171	543,439	65,378		(611,988)
		Nine months ended September 30, 2005	1,031	28,464	2,289,451	248,485		(2,567,431)
		Nine months ended September 30, 2004		6,508	1,312,481	185,195		(1,504,184)

Total revenues:
		Three months ended September 30, 2005	25,624	421,132	3,231,285	481,042		(909,792)	3,249,291
		Three months ended September 30, 2004		165,494	2,055,758	431,007		(611,988)	2,040,271
		Nine months ended September 30, 2005	88,223	1,080,727	8,534,262	1,340,800		(2,567,431)	8,476,581
		Nine months ended September 30, 2004		481,042	5,311,923	1,169,726		(1,504,184)	5,458,507

Equity in income in unconsolidated
	affiliates (see Note 6):
		Three months ended September 30, 2005	2,321	604	773	5			3,703
		Three months ended September 30, 2004	720	158	2,407	245	$ 10,759		14,289
		Nine months ended September 30, 2005	4,221	1,866	8,058	418			14,563
		Nine months ended September 30, 2004	2,576	314	6,349	960	32,025		42,224

Gross operating margin by individual
	business segment and in total:
		Three months ended September 30, 2005	16,922	93,513	153,760	47,621			311,816
		Three months ended September 30, 2004	721	7,186	83,560	35,522	10,759		137,748
		Nine months ended September 30, 2005	62,180	257,774	427,392	85,559			832,905
		Nine months ended September 30, 2004	2,577	18,928	231,730	90,731	32,025		375,991

Segment assets:
		At September 30, 2005	632,080	3,617,489	3,085,667	499,689		580,648	8,415,573
		At December 31, 2004	648,181	3,729,650	2,753,934	469,327		230,375	7,831,467

Investments in and advances
	to unconsolidated affiliates (see Note 6):
		At September 30, 2005	318,045	4,938	126,808	20,242			470,033
		At December 31, 2004	319,463	5,251	173,883	20,567			519,164

Intangible Assets (see Note 7):
		At September 30, 2005	180,576	422,415	288,521	49,972			941,484
		At December 31, 2004	200,047	446,267	282,963	51,324			980,601

Goodwill (see Note 7):
		At September 30, 2005	82,386	282,840	50,528	73,690			489,444
		At December 31, 2004	62,348	290,397	32,763	73,690			459,198

Revenues from the sale and marketing of NGL products within the NGL Pipelines & Services business segment accounted for 60% and 69% of total consolidated revenues for the three months ended September 30, 2005 and 2004, and 59% and 68% for the nine months ended September 30, 2005 and 2004, respectively. Revenues from the other businesses within this segment accounted for 15% of total consolidated revenues for the three and nine months ended September 30, 2005. Revenues from the sale of petrochemical products within the Petrochemical Services segment accounted for 12% of total consolidated revenues for the three months ended September 30, 2004, and 11% and 13% for the nine months ended September 30, 2005 and 2004, respectively. Revenues from the transportation, sale and storage of natural gas using onshore assets accounted for 13% and 12% of total consolidated revenues for the three and nine months ended September 30, 2005, respectively.

14. EARNINGS PER UNIT

Basic earnings per unit is computed by dividing net income or loss allocated to limited partner interests by the weighted-average number of distribution-bearing common units outstanding during a period. We currently have no dilutive securities. The amount of net income allocated to limited partner interests is derived by subtracting our general partner's share of our net income from net income. In connection with the contribution of net assets to us by affiliates of EPCO in August 2005 (see Note 1), such affiliates of EPCO received 74,667,332 of our common units as consideration.

The following table shows the allocation of net income to our general partner for the periods indicated:

	For the Three Months		For the Nine Months
	Ended September 30,		Ended September 30,
	2005	2004	2005	2004
Net income	$ 15,301	$ 3,660	$ 35,603	$ 21,671
Multiplied by general partner ownership interest	0.01%	0.01%	0.01%	0.01%
General partner interest in net income	$ 2	$ *	$ 4	$ 2

* Amount is negligible

The following tables show our calculation of limited partners' interest in net income and basic and diluted earnings per unit.

		For the Three Months		For the Nine Months
		Ended September 30,		Ended September 30,
		2005	2004	2005	2004
Income before changes in accounting principles
and general partner interest		$ 15,301	$ 3,660	$ 35,603	$ 21,455
Cumulative effect of changes in accounting principles					216
Net income		15,301	3,660	35,603	21,671
General partner interest in net income		(2)	*	(4)	(2)
Net income available to limited partners		$ 15,299	$ 3,660	$ 35,599	$ 21,669

BASIC & DILUTED EARNINGS PER UNIT
Numerator
	Income before changes in accounting principles
	and general partner interest	$ 15,301	$ 3,660	$ 35,603	$ 21,455
	Cumulative effect of changes in accounting principles				216
	General partner interest in net income	(2)	*	(4)	(2)
	Limited partners' interest in net income	$ 15,299	$ 3,660	$ 35,599	$ 21,669
Denominator
	Common units	80,522	74,667	76,640	74,667
Basic & Diluted earnings per unit
	Income before changes in accounting principles
	and general partner interest	$ 0.19	$ 0.05	$ 0.46	$ 0.29
	Cumulative effect of changes in accounting principles				*
	General partner interest in net income	*	*	*	*
	Limited partners' interest in net income	$ 0.19	$ 0.05	$ 0.46	$ 0.29

* Amount is negligible

15. CONDENSED FINANCIAL INFORMATION OF OPERATING PARTNERSHIP

The Operating Partnership and its subsidiaries conduct substantially all of the business of Enterprise Products Partners. Currently, neither we, Enterprise Products GP nor Enterprise Products Partners have any independent operations and any material assets outside of those of the Operating Partnership. Enterprise Products Partners acts as guarantor of all the Operating Partnership’s consolidated debt obligations, with the exception of the Seminole Notes, the Dixie revolving credit facility and the remaining amounts outstanding under GulfTerra’s senior subordinated notes. If the Operating Partnership were to default on any debt Enterprise Products Partners guarantees, Enterprise Products Partners would be responsible for full repayment of that obligation. Enterprise Products Partners' guarantee of these debt obligations is full and unconditional and non-recourse to Enterprise Products GP. For additional information regarding our consolidated debt obligations, see Note 8.

The number and dollar amounts of reconciling items between our consolidated financial statements and those of the Operating Partnership are substantially the same as the differences between our consolidated financial statements and those of Enterprise Products Partners, as discussed in Note 1.

The following table shows condensed consolidated balance sheet data for the Operating Partnership at the dates indicated:

		September 30,	December 31,
		2005	2004
ASSETS
Current assets		$ 2,001,530	$ 1,425,574
Property, plant and equipment, net		8,415,573	7,831,467
Investments in and advances to unconsolidated affiliates		470,033	519,164
Intangible assets, net		941,483	980,601
Goodwill		489,444	459,198
Deferred tax asset		5,530	6,467
Long-term receivables		14,741	14,931
Other assets		31,422	43,208
	Total	$ 12,369,756	$ 11,280,610

LIABILITIES AND PARTNERS' EQUITY
Current liabilities		$ 1,793,933	$ 1,582,911
Long-term debt		4,788,840	4,266,236
Other long-term liabilities		74,106	63,521
Minority interest		93,042	73,858
Partners' equity		5,619,835	5,294,084
	Total	$ 12,369,756	$ 11,280,610

Total Operating Partnership debt obligations guaranteed by Enterprise Products Partners		$ 4,789,000	$ 4,267,229

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

	For the Three Months		For the Nine Months
	Ended September 30,		Ended September 30,
	2005	2004	2005	2004
Revenues	$ 3,249,291	$ 2,040,271	$ 8,476,581	$ 5,458,507
Costs and expenses	3,058,042	1,960,313	8,003,909	5,251,042
Equity in income of unconsolidated affiliates	3,703	16,414	14,563	42,213
Operating income	194,952	96,372	487,235	249,678
Other income (expense)	(59,483)	(33,863)	(167,699)	(95,566)
Income before provision for income taxes, minority
interest and changes in accounting principles	135,469	62,509	319,536	154,112
Provision for income taxes	(3,223)	(662)	(3,958)	(2,706)
Income before minority interest and changes
in accounting principles	132,246	61,847	315,578	151,406
Minority interest	(902)	(3,152)	(3,235)	(6,800)
Income before changes in accounting principles	131,344	58,695	312,343	144,606
Cumulative effect of changes in
accounting principles				10,781
Net income	$ 131,344	$ 58,695	$ 312,343	$ 155,387

16. COMMITMENTS AND CONTINGENCIES

Operating leases. We lease certain property, plant and equipment under noncancelable and cancelable operating leases. Our material agreements consist of operating leases, with original terms ranging from 5 to 24 years, for natural gas and NGL underground storage facilities. We generally have the option to renew these leases, under the terms of the agreements, for one or more renewal terms ranging from 2 to 10 years. Lease expense is charged to operating costs and expenses on a straight-line basis over the period of expected economic benefit. Contingent rental payments are expensed as incurred. Third-party lease and rental expense included in operating income for the three months ended September 30, 2005 and 2004 was approximately $7.6 million and $5.5 million, respectively. We recorded $24.7 million and

$15.8 million of third-party lease and rental expense for the nine months ended September 30, 2005 and 2004, respectively.

Litigation. We are sometimes named as a defendant in litigation relating to our normal business operations, including litigation related to various federal, state and local regulatory and environmental matters. Although we insure against various business risks, to the extent management believes it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings as a result of ordinary business activity. Management is not aware of any significant litigation, pending or threatened, that would have a significant adverse effect on our financial position or results of operations.

We own an octane-additive production facility that historically produced, and is currently capable of producing, methyl tertiary butyl ether ("MTBE"), a motor gasoline additive that enhances octane and is used in reformulated motor gasoline. We operate the facility, which is located within our Mont Belvieu complex. The production of MTBE was primarily driven by oxygenated fuel programs enacted under the federal Clean Air Act Amendments of 1990. In recent years, MTBE has been detected in water supplies. The major source of ground water contamination appears to be leaks from underground storage tanks. As a result of environmental concerns, several states enacted legislation to ban or significantly limit the use of MTBE in motor gasoline within their jurisdictions. The Energy Bill approved by the U.S. Congress in July 2005 (and signed by the President in August 2005) eliminates oxygenates in motor gasoline.

A number of lawsuits have been filed by municipalities and other water suppliers against a number of manufacturers of reformulated gasoline containing MTBE, although generally such suits have not named manufacturers of MTBE as defendants, and there have been no such lawsuits filed against our subsidiary that owns the facility. It is possible, however, that MTBE manufacturers such as our subsidiary could ultimately be added as defendants in such lawsuits or in new lawsuits. In connection with our purchase of ownership interests in the octane-additive production facility in 2003 from an affiliate of Devon Energy Corporation (“Devon”) and in 2004 from an affiliate of Sunoco, Inc. (“Sun”), Devon and Sun indemnified us for any liability (including liabilities described above) that are in respect of periods prior to the date we purchased such interests.

Performance Guaranty. In December 2004, our Independence Hub, LLC subsidiary entered into the Independence Hub Agreement (the "Agreement") with six oil and natural gas producers. The Agreement obligates Independence Hub, LLC (i) to construct an offshore platform production facility to process 850 MMcf/d of natural gas and condensate and (ii) to process certain natural gas and condensate production of the six producers following construction of the platform facility.

In conjunction with the Agreement, the Operating Partnership guaranteed the performance of its Independence Hub, LLC subsidiary under the Agreement up to $397.5 million. In December 2004, 20% of this guaranteed amount was assumed by Cal Dive, our joint venture partner in the Independence Hub project. The remaining $318 million represents our share of the anticipated cost of the platform facility. This amount represents the cap on the Operating Partnership's potential obligation to the six producers for our share of the cost of constructing the platform in the unlikely scenario where the six producers take over the construction of the platform facility. Our performance guarantee continues until the earlier to occur of (i) all of the guaranteed obligations of Independence Hub, LLC shall have been terminated or expired, or shall have been indefeasibly paid or otherwise performed or discharged in full, (ii) upon mutual written consent of the Operating Partnership and the producers or (iii) mechanical completion of the production facility. We expect that mechanical completion will occur on or about November 1, 2006; therefore, we anticipate that the performance guaranty will exist until at least this future date.

In accordance with FIN 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," we recorded the fair value of the performance guaranty using an expected present value approach. Given the remote probability that the Operating Partnership would be required to perform under the guaranty, we have estimated the fair value of the performance guaranty at approximately $1.2 million, which is a component of current and other long-term liabilities on our unaudited condensed consolidated balance sheet at September 30, 2005.

17. SIGNIFICANT RISKS AND UNCERTAINTIES – HURRICANES

We participate as named insureds in EPCO’s current insurance program, which provides us with property damage, business interruption and other coverages, which are customary for the nature and scope of our operations. Historically, most of the insurance carriers in EPCO’s portfolio of coverage were rated “A” or higher by recognized ratings agencies. The financial impact of recent storm events such as Hurricanes Katrina and Rita has resulted in the lowering of credit ratings of many insurance carriers, with a number of providers also being placed on negative credit watch. We are unaware of any of our existing carriers dropping below the “A” rating level. At present, there is no indication of any insurance carrier in the EPCO insurance program being unable or unwilling to meet its coverage obligations.

We believe that EPCO maintains adequate insurance coverage on behalf of us, although insurance will not cover every type of interruption that might occur. As a result of insurance market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available for only reduced amounts of coverage. As a result, EPCO may not be able to renew existing insurance policies on behalf of us or procure other desirable insurance on commercially reasonable terms, if at all. At present, the annualized cost of insurance premiums allocated to us by EPCO for all lines of coverage is approximately $27 million. This amount includes a $1.8 million increase in premiums related to Hurricane Katrina that we recognized during the third quarter of 2005 Additional premium increases from our insurance carriers resulting from damage caused by Hurricane Rita in September 2005 are possible but not yet determinable due to the recent nature of the event.

If we were to incur a significant liability for which we were not fully insured, it could have a material impact on our consolidated financial position and results of operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur. Any event that interrupts the revenues generated by our consolidated operations, or which causes us to make significant expenditures not covered by insurance, could reduce our ability to pay distributions to partners and, accordingly, adversely affect the market price of our common units and those of Enterprise Products Partners.

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

Hurricane Ivan insurance claims

Our final purchase price allocation for the GulfTerra Merger includes the expected recovery of $26.2 million, which represents the probable recovery of property damage insurance claims related to completed expenditures for damage to certain assets due to the significant effects of Hurricane Ivan, which struck the eastern U.S. Gulf Coast region in September 2004 prior to the GulfTerra Merger. These expenditures represent our total costs to restore the former GulfTerra damaged facilities to operation. Since this loss event occurred prior to completion of the GulfTerra Merger, the claim was filed under the insurance program of GulfTerra and El Paso. We expect to receive these proceeds directly from the insurance carriers or from the former owners on our behalf during the first quarter of 2006. If the final recovery of funds is different than the amount previously expended, we will recognize an income impact at that time.

In addition, we have submitted business interruption insurance claims for our estimated losses caused by Hurricane Ivan. During the fourth quarter of 2005, we expect to receive $6.6 million from such claims. In addition, we estimate an additional $15 million to $16 million will be received during the first quarter of 2006. To the extent we receive cash proceeds from such business interruption claims, they will be recorded as a gain in our statements of consolidated operations and comprehensive income in the period of receipt.

Hurricanes Katrina and Rita insurance claims

Hurricanes Katrina and Rita, both significant storms, affected certain of our Gulf Coast assets in August and September of 2005, respectively. Inspection and evaluation of damage to our facilities is a continuing effort. We expensed $5 million during the third quarter of 2005 related to property damage insurance deductibles for both storms. To the extent that insurance proceeds from property damage claims do not cover our expenditures (in excess of the insurance deductibles we have expensed), such shortfall will be expensed when realized. In addition, we expect to file business interruption claims for losses related to these hurricanes. To the extent we receive cash proceeds from such business interruption claims, they will be recorded as a gain in our statements of consolidated operations and comprehensive income in the period of receipt.

18. SUBSEQUENT EVENT

October 2005 Amendment to Multi-Year Revolving Credit Facility

In October 2005, the Operating Partnership executed an amendment to its Multi-Year Revolving Credit Facility which increased borrowing capacity from $750 million to $1.25 billion. Additionally, the amendment provides that the borrowing capacity under the Multi-Year Revolving Credit Facility may be increased further to $1.4 billion, subject to certain conditions. The amendment also reduces by 0.375% the aggregate total facility fee and the Eurodollar borrowing rate that was previously in effect. The maturity date of the credit facility was extended from September 2009 to October 2010, and the Operating Partnership may make up to two requests for one-year extensions of the maturity date (subject to certain restrictions). Additionally, the amendment removed the $100 million limit on the total amount of standby letters of credit that can be outstanding under the credit facility.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS.

For the three and nine months ended September 30, 2005 and 2004.

Enterprise GP Holdings L.P. is a publicly traded Delaware limited partnership listed on the New York Stock Exchange ("NYSE") under the ticker symbol “EPE.” Enterprise GP Holdings L.P. ("Enterprise GP Holdings") was formed in April 2005 and completed its initial public offering of 14,216,784 common units in August 2005.

Enterprise GP Holdings is currently the sole member of Enterprise Products GP, LLC (“Enterprise Products GP”), which is the general partner of Enterprise Products Partners L.P. ("Enterprise Products Partners"). The primary business purpose of Enterprise Products GP is to manage the affairs and operations of Enterprise Products Partners, a North American energy company providing a wide range of processing, storage and transportation or midstream services to producers and consumers of natural gas, natural gas liquids (“NGLs”), and crude oil, and an industry leader in the development of pipeline and other midstream infrastructure in the continental United States and deepwater Gulf of Mexico. Enterprise Products Partners conducts substantially all of its business through a wholly owned subsidiary, Enterprise Products Operating L.P. (the “Operating Partnership”).

We are owned 99.99% by our limited partners and 0.01% by EPE Holdings LLC (our general partner, referred to as “EPE Holdings”). Enterprise GP Holdings, Enterprise Products GP, and Enterprise Products Partners are all affiliates and under common control of Dan L. Duncan, the Chairman and the controlling shareholder of EPCO, Inc. (“EPCO”). EPCO and its affiliates own 86.5% of Enterprise GP Holdings at September 30, 2005. We and Enterprise Products GP have no independent operations outside those of Enterprise Products Partners.

Unless the context requires otherwise, references to “we,” “us,” “our,” “Enterprise GP Holdings” or the “Company” within these notes shall mean Enterprise GP Holdings L.P. and its consolidated subsidiaries, which include Enterprise Products GP and Enterprise Products Partners. Also, “GulfTerra Merger” refers to the merger of GulfTerra Energy Partners, L.P. with a wholly owned subsidiary of Enterprise Products Partners on September 30, 2004 and the various transactions related thereto. References to “GulfTerra” mean Enterprise GTM Holdings L.P., the successor to GulfTerra Energy Partners, L.P. References to “GulfTerra GP” mean Enterprise GTMGP, L.L.C., which was formerly known as GulfTerra Energy Company, L.L.C., the general partner of GulfTerra Energy Partners, L.P. Enterprise GTMGP, L.L.C. is the general partner of Enterprise GTM Holdings L.P."

This quarterly report contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us. Please read “Cautionary Statement Regarding Forward-Looking Statements and Risk Factors” for additional information.

Unless otherwise indicated, the dollar amounts presented in the tabular data within this discussion and analysis are stated in thousands of dollars.

In addition, as generally used in the industry and in this discussion and analysis, the identified terms have the following meanings:

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

BASIS OF PRESENTATION

Currently, Enterprise GP Holdings (the “parent company”) has no separate operating activities apart from those conducted by the Operating Partnership of Enterprise Products Partners. The principal sources of cash flow for the parent company are its investments in limited and general partner ownership interests of Enterprise Products Partners. The parent company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. The parent company-only assets and liabilities of Enterprise GP Holdings are not available to satisfy the debts and other obligations of Enterprise Products Partners and its consolidated subsidiaries.

In order to fully understand the financial condition and results of operations of the parent company on a standalone basis, we have included discussions of parent company matters apart from those of our consolidated partnership. In general, our discussion of parent company matters pertains to the period since Enterprise GP Holdings’ initial public offering on August 23, 2005.

The historical consolidated financial information of Enterprise GP Holdings presented in this quarterly report on Form 10-Q for periods prior to August 2005 has been presented using the consolidated financial information of Enterprise Products GP, which has been deemed the predecessor company of Enterprise GP Holdings. For additional information regarding the basis of presentation of our consolidated financial information, please read Note 1 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

RECENT DEVELOPMENTS

The following summarizes our recent significant developments since December 31, 2004.

•

In January 2005, we paid $74.5 million for an indirect 80% equity interest in the 89-mile Indian Springs Gathering System and an indirect 75% equity interest in the Indian Springs natural gas processing facility, both of which are located in East Texas.

•

In January 2005, we purchased an approximate 20% interest in Dixie Pipeline Company (“Dixie”) for $31 million. Additionally, we purchased an approximate 26% interest in Dixie in February 2005 for $40 million. We currently own approximately 66% of Dixie.

•

In February 2005, Enterprise Products Partners sold 17,250,000 common units (including the over-allotment amount of 2,250,000 common units which closed on March 11, 2005), which generated net proceeds of approximately $456.7 million.

•

In February 2005, the Operating Partnership sold $500 million in principal amount of senior notes in a private offering, comprised of $250 million in principal amount of our 10-year Senior Notes I and $250 million in principal amount of our 30-year Senior Notes J.

•

In March 2005, Enterprise Products Partners filed a universal shelf registration statement with the U.S. Securities and Exchange Commission ("SEC") registering the issuance of $4 billion of partnership equity and public debt obligations. In June 2005, the Operating Partnership sold $500 million in principal amount of 4.95% senior notes due June 2010 (“Senior Notes K”) under this universal shelf registration statement.

•

Cameron Highway Oil Pipeline Company ("Cameron Highway") began deliveries of Gulf of Mexico crude oil production to major refining markets along the Texas Gulf Coast during the first quarter of 2005. The Cameron Highway Oil Pipeline is designed to gather production from the deepwater areas of the Gulf of Mexico, primarily the South Green Canyon area, for delivery to refineries and terminals in Port Arthur and Texas City, Texas. This pipeline can currently transport up to 500 MBPD of crude oil production. We own a 50% equity interest in Cameron Highway.

•

In June 2005, we announced our plans to construct a new NGL fractionator near Hobbs, New Mexico. See “--Capital Spending” for additional information regarding this growth project.

•

In June 2005, we exercised our option to acquire a 2% indirect ownership interest in the Mid-America pipeline and a 1.6% indirect ownership interest in the Seminole pipeline for a total purchase price of $25 million. This transaction was completed on June 30, 2005, and as a result, we now own 100% of the Mid-America pipeline and 90% of the Seminole pipeline.

•

In July 2005, we purchased three NGL underground storage facilities and four propane terminals from Ferrellgas L.P. (“Ferrellgas”) for $144 million in cash. See “--Capital Spending” for additional information regarding this acquisition.

•

In August 2005, the parent company, Enterprise GP Holdings, sold 14,216,784 common units in connection with its initial public offering (see the following discussion, “Parent Company – Enterprise GP Holdings” for additional information regarding this recent event).

•

In late August 2005, Hurricane Katrina, a Category 4 hurricane, struck the U.S. Gulf Coast regions of Alabama, Louisiana and Mississippi. Additionally, in late September 2005, Hurricane Rita, a Category 3 hurricane, struck the U.S. Gulf Coast regions of Louisiana and Texas. Certain of our assets on the U.S. Gulf Coast and offshore in the Gulf of Mexico in the paths of Hurricane Katrina and Hurricane Rita incurred structural damage as a result of the hurricanes. In addition to this damage, certain of our operations were interrupted from damage to production and other facilities that supply our assets. For information regarding the general status of insurance claims associated with Hurricanes Katrina and Rita, please read “– Capital Spending – Significant Risks and Uncertainties – Hurricanes” included within this Item 2. Also, for information regarding the impact that these storm events had on our results of operations, please read "— Our Consolidated Results of Operations" included within this Item 2.

Parent Company – Enterprise GP Holdings

In April 2005, the parent company filed a registration statement regarding its initial public offering of our common units. In August 2005, we sold 14,216,784 common units under this registration statement (including an over-allotment amount of 1,616,784 common units) at an offering price of $28.00 per common unit. Total net proceeds from the sale of these common units was approximately $373 million after deducting applicable underwriting discounts, commissions, structuring fees and other offering expenses of $25.6 million. The net proceeds from this initial public offering were used to reduce debt outstanding under Enterprise GP Holdings' $525 Million Credit Facility.

Paso Corporation ("El Paso") in January 2005 and (ii) a 100% ownership interest in Enterprise Products GP. Concurrent with the contribution of these ownership interests, Enterprise GP Holdings assumed $160 million in debt and $0.5 million of accrued interest from EPCO.

In accordance with Statement of Financial Accounting Standard (“SFAS”) No. 141, the transfer of such net assets from affiliates of EPCO to Enterprise GP Holdings was recorded at the transferors’ net historical carrying amounts of $160.6 million since both the transferors and transferee are under the common control of EPCO. As consideration for these transfers, affiliates of EPCO received 74,667,332 common units (the “sponsor units”) of Enterprise GP Holdings.

CAPITAL SPENDING

We are committed to the long-term growth and viability of the Company. As owner of the general (or managing) partner of Enterprise Products Partners, part of our business strategy for Enterprise Products Partners and its subsidiaries involves expansion through business combinations, growth capital projects and investments in joint ventures. We have no capital spending program apart from that of Enterprise Products Partners and its subsidiaries.

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

We believe that Enterprise Products Partners is well positioned to continue to grow through acquisitions that will expand its system of assets and through growth capital projects. We estimate our consolidated capital spending over the next six months (fourth quarter of 2005 and first quarter of 2006) will approximate $570 million, which includes estimated expenditures of approximately $510 million for growth capital projects and acquisitions and $60 million for sustaining capital expenditures.

Our forecast of consolidated capital expenditures is based upon our strategic operating and growth plans for Enterprise Products Partners and its subsidiaries, which are also dependent upon our ability to provide capital from operating cash flows or otherwise obtain the capital necessary to accomplish our objectives. Enterprise Products Partners' forecast may change due to factors beyond our control, such as weather related issues, changes in supplier prices or deteriorating economic conditions. Furthermore, our forecast may change as a result of decisions made at a later date, which may include acquisitions or decisions to take on additional partners.

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

The following table summarizes our consolidated capital spending by activity for the periods indicated:

			For the Nine Months
			Ended September 30,
			2005	2004
Capital spending for business combinations:
	GulfTerra Merger		$ 7,028	$ 1,007,334
	NGL underground storage and terminaling assets purchased from Ferrellgas		144,000
	Indirect interests in the Indian Springs natural gas gathering and processing assets		74,854
	Additional ownership interests in Dixie Pipeline Company ("Dixie")		68,608
	Additional ownership interests in Mid-America and Seminole pipeline systems		25,000
	Additional ownership interest in Seminole Pipeline Company ("Seminole")			28,010
	Additional ownership interest in Tri-States NGL Pipeline LLC ("Tri States")		900	16,485
	Additional ownership interest in Belvieu Environmental Fuels, L.P. ("BEF")			13,440
	Other business combinations		4,690
		Total capital spending related to business combinations	325,080	1,065,269
Capital spending for property, plant and equipment:
	Growth capital projects		524,767	22,944
	Sustaining capital projects		62,778	16,001
		Total capital spending for property, plant and equipment	587,545	38,945
Capital spending attributable to unconsolidated affiliates:
	Investments in unconsolidated affiliates, excluding advances		80,833	1,076
		Total capital spending	$ 993,458	$ 1,105,290

Capital spending for consolidated property, plant and equipment as shown in the preceding table, is shown net of contributions in aid of construction costs of $40.4 million and $0.5 million for the nine months ended September 30, 2005 and 2004, respectively. On certain of Enterprise Products Partners’ capital projects, third parties are obligated to reimburse it for all or a portion of the capital expenditures associated with such projects. As a result of completing the GulfTerra Merger, the number of such arrangements has increased, particularly for projects involving pipeline construction and production well tie-ins.

At September 30, 2005, we had approximately $179.4 million in outstanding purchase commitments related to capital projects, the majority of which pertain to pipeline and platform growth projects in the Gulf of Mexico that are expected to be placed in service during 2005 and 2006.

Significant Announced Growth Capital Projects

Western Expansion Project – NGL fractionation. In June 2005, we announced plans to construct a new NGL fractionator, designed to handle up to 75 MBPD of mixed NGLs, located at the interconnection of our Mid-America pipeline system and our Seminole pipeline system near Hobbs, New Mexico. Additionally, we will construct a purity ethane storage well near the new fractionator and reconfigure the interconnection between the Mid-America pipeline and the Seminole pipeline. These projects are expected to cost approximately $150 million and be placed in service by mid-2007.

In January 2005, we announced that we had commenced initial permitting, engineering and design work for our Western Expansion Project, which included adding 50 MBPD of transportation capacity on the Rocky Mountain segment of our Mid-America pipeline system and a new 60 MBPD NGL fractionator at our Mont Belvieu complex. After additional analysis, we decided to build the new fractionator at Hobbs (as described in the previous paragraph) instead of the previously announced 60 MBPD fractionator at our Mont Belvieu complex because the Hobbs fractionator will provide more commercial and operating flexibility for the handling of increased Rocky Mountain volumes.

Purchase of NGL underground storage and terminaling assets. In July 2005, we purchased three NGL underground storage facilities and four propane terminals from Ferrellgas for $144 million in cash. The underground storage facilities are located in Kansas, Arizona and Utah and have a combined capacity

of 6.1 MMBbls. Approximately 70% of the aggregate storage capacity is leased to third party customers under fee-based contracts. The four propane terminals are located in Minnesota and North Carolina. The Minnesota facilities are connected to our Mid-America pipeline system, and the North Carolina terminals are connected by rail to our facilities on the Gulf Coast. As part of the transaction, Ferrellgas has contracted with us to maintain a certain level of storage volume and terminal throughput for five years with the option to extend for an additional five years.

Significant Risks and Uncertainties – Hurricanes

Hurricane Ivan insurance claims

Hurricanes Katrina and Rita insurance claims

RESULTS OF OPERATIONS

Parent Company Only – Enterprise GP Holdings

The parent company has no separate operating activities apart from those conducted by Enterprise Products Partners and its Operating Partnership. The principal sources of earnings for the parent company are its equity investments in limited and general partner ownership interests of Enterprise Products Partners. The following table summarizes the key components of the results of operations of the parent company since its formation in April 2005.

Equity in income of affiliates	$ 2,146
Interest expense	1,109
Net income	958

For additional information regarding the standalone financial results of the parent company, please see Note 1 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report. The following is a discussion of the highlights of the parent company's results of operations since its initial public offering in August 2005.

Equity income. The parent company recorded $2.1 million in equity earnings from its investments in Enterprise Products Partners’ limited and general partner ownership interests. Of this amount, $0.6 million results from our investment in the general partner of Enterprise Products Partners and the remainder from our investment in 13,454,498 common units of Enterprise Products Partners.

Interest expense. The parent company recorded $1.1 million in interest expense during the period primarily due to borrowings incurred under its $525 Million Credit Facility. Included in this interest expense amount is $0.3 million related to the $160 million in principal amount of debt Enterprise GP Holdings assumed from affiliates of EPCO in August 2005. This debt was repaid in late August 2005 using borrowings under the $525 Million Credit Facility.

Consolidated Results of Operations

Since we own the general partner of Enterprise Products Partners, our primary financial results reflect the consolidated financial results of Enterprise Products Partners and its general partner. The following is a discussion of our consolidated results of operations.

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

The Offshore Pipelines & Services business segment consists of (i) approximately 1,150 miles of offshore natural gas pipelines strategically located to serve production areas in some of the most active drilling and development regions in the Gulf of Mexico, (ii) approximately 810 miles of Gulf of Mexico offshore crude oil pipeline systems and (iii) seven multi-purpose offshore hub platforms located in the Gulf of Mexico.

The NGL Pipelines & Services business segment includes our (i) natural gas processing business and related NGL marketing activities, (ii) NGL pipelines aggregating approximately 12,810 miles and related storage facilities, which include our strategic Mid-America and Seminole NGL pipeline systems and (iii) NGL fractionation facilities located in Texas and Louisiana. This segment also includes our import and export terminaling operations.

The Other non-segment category is presented for financial reporting purposes only to reflect the historical equity earnings we received from GulfTerra GP. We acquired a 50% membership interest in GulfTerra GP on December 15, 2003, in connection with the GulfTerra Merger. Our investment in GulfTerra GP was accounted for using the equity method until the GulfTerra Merger was completed on September 30, 2004. On that date, GulfTerra GP became a wholly owned consolidated subsidiary of ours. Since the historical equity earnings of GulfTerra GP were based on net income amounts allocated to it by GulfTerra, it is impractical for us to allocate the equity income we received during the periods presented to each of our new business segments. Therefore, we have segregated equity earnings from GulfTerra GP from our other segment results to aid in comparability between the periods presented.

We evaluate segment performance based on the non-GAAP financial measure of gross operating margin. Gross operating margin (either in total or by individual segment) is an important performance measure of the core profitability of our operations. This measure forms the basis of our internal financial reporting and is used by senior management in deciding how to allocate capital resources among business segments. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results. The GAAP measure most directly comparable to total segment gross operating margin is operating income. Our non-GAAP financial measure of total segment gross operating margin should not be considered as an alternative to GAAP operating income.

We have historically included equity earnings from unconsolidated affiliates in our measurement of segment gross operating margin and operating income. Our equity investments with industry partners are a vital component of our business strategy. They are a means by which we conduct our operations to align our interests with those of our customers, which may be suppliers of raw materials or consumers of finished products. This method of operation also enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed versus what we could accomplish on a stand-alone basis. Many of these businesses perform supporting or complementary roles to our other business operations.

For additional information regarding our business segments, please read Note 13 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

Selected Price and Volumetric Data

The following table illustrates selected average quarterly industry index prices for natural gas, crude oil, selected NGL and petrochemical products since the beginning of 2004:

								Polymer	Refinery
	Natural				Normal		Natural	Grade	Grade
	Gas,	Crude Oil,	Ethane,	Propane,	Butane,	Isobutane,	Gasoline,	Propylene,	Propylene,
	$/MMBtu	$/barrel	$/gallon	$/gallon	$/gallon	$/gallon	$/gallon	$/pound	$/pound
	(1)	(2)	(1)	(1)	(1)	(1)	(1)	(1)	(1)
2004
1st Quarter	$5.69	$35.25	$0.43	$0.66	$0.76	$0.76	$0.87	$0.29	$0.26
2nd Quarter	$6.00	$38.34	$0.45	$0.65	$0.79	$0.79	$0.92	$0.32	$0.26
3rd Quarter	$5.75	$43.90	$0.52	$0.79	$0.92	$0.92	$1.05	$0.32	$0.27
4th Quarter	$7.07	$48.31	$0.60	$0.85	$1.03	$1.04	$1.15	$0.40	$0.35
Average for Year	$6.13	$41.45	$0.50	$0.74	$0.88	$0.88	$1.00	$0.33	$0.29
2005
1st Quarter	$6.27	$49.68	$0.52	$0.79	$0.98	$1.00	$1.14	$0.45	$0.39
2nd Quarter	$6.74	$53.09	$0.52	$0.82	$0.98	$1.01	$1.16	$0.37	$0.30
3rd Quarter	$8.53	$63.08	$0.69	$0.97	$1.14	$1.26	$1.36	$0.37	$0.33
Average for Year	$7.18	$55.28	$0.58	$0.86	$1.03	$1.09	$1.22	$0.40	$0.34

(1) Natural gas, NGL, polymer grade propylene and refinery grade propylene prices represent an average of various commercial index prices including OPIS and CMAI. Natural gas price is representative of Henry-Hub I-FERC. NGL prices are representative of Mont Belvieu Non-TET pricing. Refinery grade propylene represents an average of CMAI spot prices. Polymer-grade propylene represents average CMAI contract pricing. (2) Crude oil price is representative of an index price for West Texas Intermediate.

The following table presents our significant average throughput, production and processing volumetric data for the periods indicated (on a net basis, taking into account our ownership interests). In general, the increase in volumes period-to-period is primarily due to the assets we acquired in connection with the GulfTerra Merger, including the South Texas midstream assets. The GulfTerra Merger was completed on September 30, 2004.

	For the Three Months		For the Nine Months
	Ended September 30,		Ended September 30,
	2005 (1)	2004 (1)	2005 (1)	2004 (1)
Offshore Pipelines & Services, net:
Natural gas transportation volumes (BBtus/d)	1,623	393	1,876	423
Crude oil transportation volumes (MBPD)	124		134
Platform gas treating (Mdth/d)	221		285
Platform oil treating (MBPD)	8		8
Onshore Natural Gas Pipelines & Services, net:
Natural gas transportation volumes (BBtus/d)	6,035	685	5,933	650
NGL Pipelines & Services, net:
NGL transportation volumes (MBPD)	1,468	1,450	1,463	1,358
NGL fractionation volumes (MBPD)	270	239	311	235
Equity NGL production (MBPD)	82	84	94	84
Fee-based natural gas processing (MMcf/d)	1,471	1,822	1,828	1,544
Petrochemical Services, net:
Butane isomerization volumes (MBPD)	96	82	82	73
Propylene fractionation volumes (MBPD)	55	58	55	58
Octane additive production volumes (MBPD)	8	12	5	9
Petrochemical transportation volumes (MBPD)	50	77	65	72
Total, net:
NGL, crude oil and petrochemical transportation volumes (MBPD)	1,642	1,527	1,662	1,430
Natural gas transportation volumes (BBtus/d)	7,658	1,079	7,809	1,074
Equivalent transportation volumes (MBPD) (2)	3,657	1,811	3,717	1,713
(1) Volumetric data shown above reflects net operating rates of the underlying assets for the periods in which we owned them. (2) Reflects equivalent energy volumes where 3.8 MMBtus of natural gas are equivalent to one barrel of NGLs.

Comparisons of Our Consolidated Results of Operations

The following table summarizes the key components of our consolidated results of operations for the periods indicated:

	For the Three Months		For the Nine Months
	Ended September 30,		Ended September 30,
	2005	2004	2005	2004
Revenues	$3,249,291	$2,040,271	$8,476,581	$5,458,507
Operating costs and expenses	3,045,345	1,951,567	7,959,122	5,226,392
General and administrative costs	13,654	10,300	47,689	27,069
Equity in income of unconsolidated affiliates	3,703	14,289	14,563	42,224
Operating income	193,995	92,693	484,333	247,270
Interest expense	61,348	32,471	171,507	96,956
Minority interest	111,553	56,499	261,549	127,085
Net income	15,301	3,660	35,603	21,671

gas using onshore assets accounted for 13% and 12% of total consolidated revenues for the three and nine months ended September 30, 2005, respectively.

In general, an increase in our revenues and costs and expenses period-to-period is attributable to the results of businesses acquired or consolidated since the second quarter of 2004 and an increase in NGL and petrochemical sales volumes including the effects of higher energy commodity prices. Higher energy commodity prices result in increased revenues from our NGL and petrochemical marketing activities; however, these same higher prices also increase the cost of sales within these activities as feedstock and other related purchase prices rise. For selected general energy commodity price information and detailed segment-level volumetric information, please review the tables under “—Selected Price and Volumetric Data.”

Minority interest expense represents third-party and related party ownership interests in the earnings of Enterprise Products Partners and certain other subsidiaries. For financial reporting purposes, the assets and liabilities of our majority-owned subsidiaries are consolidated with those of our own, with any third-party investor's ownership in our consolidated balance sheet amounts shown as minority interest. For additional information regarding our minority interest amounts, please see Note 2 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

Our consolidated gross operating margin by segment and in total is as follows for the periods indicated:

		For the Three Months		For the Nine Months
		Ended September 30,		Ended September 30,
		2005	2004	2005	2004
Gross operating margin by segment:
	Offshore Pipelines & Services	$ 16,922	$ 721	$ 62,180	$ 2,577
	Onshore Natural Gas Pipelines & Services	93,513	7,186	257,774	18,928
	NGL Pipelines & Services	153,760	83,560	427,392	231,730
	Petrochemical Services	47,621	35,522	85,559	90,731
Other, non-segment			10,759		32,025
Total segment gross operating margin		$ 311,816	$ 137,748	$ 832,905	$ 375,991

For a reconciliation of our consolidated non-GAAP gross operating margin to our consolidated GAAP operating income and further to our consolidated GAAP income before provision for taxes, minority interest and the cumulative effect of changes in accounting principles, please read “Other Items” included within this Item 2.

Three Months Ended September 30, 2005 Compared with the

Three Months Ended September 30, 2004

Revenues for the third quarter of 2005 increased $1.2 billion over those recorded during the same period in 2004. The trend in consolidated revenues can be attributed to (i) a $583 million increase in revenues from our NGL and petrochemical marketing activities primarily resulting from an increase in sales volumes and energy commodity prices and (ii) the addition of $495 million in revenues from businesses acquired or consolidated during or after the third quarter of 2004 (primarily revenues generated by the GulfTerra and South Texas midstream assets).

Consolidated costs and expenses increased $1.1 billion quarter-to-quarter primarily due to (i) an increase in volumes purchased including the effects of higher energy commodity prices, which resulted in a $572 million increase in the cost of sales of our NGL and petrochemical marketing activities and (ii) the addition of $381 million in costs and expenses attributable to businesses acquired or consolidated during or after the third quarter of 2004. General and administrative costs also increased $3.2 million quarter-to-quarter primarily due to businesses acquired since September 30, 2004.

Changes in our revenues and costs and expenses quarter-to-quarter are explained in part by changes in energy commodity prices. The indicative weighted-average market price for NGLs was 98

cents per gallon for the three months ended September 30, 2005 versus 77 cents per gallon during the same period in 2004—a quarter-to-quarter increase of 27%. Our determination of the weighted-average market price for NGLs is based on selected U.S. Gulf Coast prices for such products at Mont Belvieu, which is the primary industry hub for domestic NGL production. The market price of natural gas (as measured at Henry Hub) averaged $8.53 per MMBtu for the third quarter of 2005 versus $5.75 per MMBtu during the 2004 period. Polymer grade propylene index prices increased 16% quarter-to-quarter and refinery grade propylene index prices increased 22% quarter-to-quarter.

Equity earnings from unconsolidated affiliates decreased $10.6 million quarter-to-quarter. Equity earnings for the third quarter of 2005 include our share of earnings from investments we acquired in connection with the GulfTerra Merger. The third quarter of 2004 includes $10.8 million of equity earnings from GulfTerra GP, which we began consolidating on September 30, 2004 as a result of completing the GulfTerra Merger. Collectively, the aforementioned changes in revenues, costs and expenses and equity earnings contributed to a $101.3 million increase in operating income quarter-to-quarter.

The $28.8 million increase in interest expense is primarily due to additional debt we incurred in October 2004 as a result of the GulfTerra Merger (Senior Notes E, F, G and H), Senior Notes I and J in February 2005 and Senior Notes K in June 2005. Our weighted-average debt principal outstanding was $5 billion during the third quarter of 2005 compared to $2.8 billion during the third quarter of 2004.

As a result of the items noted in previous paragraphs, our net income increased $11.7 million to $15.4 million for the third quarter of 2005 from $3.7 million for the third quarter of 2004.

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

In general, due to our geographic and business diversification, Hurricanes Katrina and Rita had varying effects across our business segments. The hurricanes impacted supply and demand for natural gas, NGLs, crude oil and motor gasoline. In general, this resulted in an increase in energy commodity prices, which was exacerbated in certain regions due to local supply and demand imbalances. The disruptions in natural gas, NGL and crude oil production along the U.S. Gulf Coast resulted in decreased volumes for some of our pipeline systems, natural gas processing plants and NGL fractionators, which in turn caused a decrease in gross operating margin for certain operations. In addition, operating costs at certain of our plants and pipelines were negatively impacted due to the increase in natural gas prices. These effects were offset by an increase in gross operating margin from certain of our businesses, which benefited from increased demand for NGLs and octane additives used in the production of motor gasoline, regional demand for natural gas and the general increase in commodity prices.

We estimate that gross operating margin for the third quarter of 2005 decreased by approximately $27 million due to the direct effects of Hurricanes Katrina and Rita as a result of loss of volumes, expected costs to repair facilities limited to the deductibles under our insurance program and the cost of increased insurance premiums. We currently expect a decrease in gross operating margin for the fourth quarter of 2005 directly related to the storms to be approximately $34 million prior to any future recoveries under business interruption insurance.

Offshore Pipelines & Services. Gross operating margin from this business segment increased $16.2 million quarter-to-quarter primarily due to offshore Gulf of Mexico assets acquired in connection with the GulfTerra Merger. These assets accounted for $17.3 million of gross operating margin recorded for this segment during the third quarter of 2005.

Onshore Natural Gas Pipelines & Services. Gross operating margin from this business segment increased $86.3 million quarter-to-quarter primarily due to onshore natural gas pipeline and storage assets we acquired in connection with the GulfTerra Merger. These assets accounted for $82.4 million of gross operating margin recorded for this segment during the third quarter of 2005.

Our Texas Intrastate System generated gross operating margin of $21.9 million during the third quarter of 2005 on average transportation volumes of 3,577 BBtus/d. The Texas Intrastate System is an 8,222-mile natural gas pipeline system that gathers and transports natural gas from supply basins in Texas and offshore in the Gulf of Mexico to local gas distribution companies and electric generation and industrial customers. Our San Juan Gathering System contributed $36.3 million of gross operating margin during the third quarter of 2005 on average transportation volumes of 1,181 BBtus/d. The San Juan Gathering System is a 5,404-mile natural gas pipeline system that serves natural gas producers in the San Juan Basin of New Mexico and Colorado. We own 100% of the Texas Intrastate System and the San Juan Gathering System, both of which were acquired in connection with the GulfTerra Merger.

NGL Pipelines & Services. Gross operating margin from this business segment increased $70.2 million quarter-to-quarter. This increase is primarily due to an $82.7 million increase in gross operating margin from our natural gas processing and related businesses, which includes $45.3 million from assets acquired during or after the third quarter of 2004 and a $41.1 million increase from our NGL marketing activities. NGL marketing benefited from an increase in demand for NGLs used as feedstocks in the production of motor gasoline, an increase in NGL import activity, and improved sales margins.

Gross operating margin from NGL pipelines and related storage services decreased $6.4 million quarter-to-quarter. An increase in gross operating margin attributable to assets acquired or consolidated since September 30, 2004 was more than offset by lower gross operating margin from our Mid-America and Seminole pipelines and NGL storage facilities. A reduction in gross operating margin quarter-to-quarter on our Mid-America and Seminole pipelines is attributable to the net impact of tariffs that became effective in the second and third quarters of 2005 (see discussion below) and a 54 MBPD decrease in transportation volumes, caused in part by planned maintenance outages during the third quarter of 2005 at several third party-owned gas processing facilities located in the Rockies that are connected to our pipeline system.

Gross operating margin from NGL fractionation increased $0.8 million quarter-to-quarter primarily due to NGL fractionation assets we acquired in connection with the GulfTerra Merger. Expenses related to support services classified within this segment (e.g., product distribution and related direct costs) increased $7 million quarter-to-quarter primarily due to an increase in business activity related to acquired assets.

One of our objectives for 2005 was to seek relief through filings with the FERC to increase tariffs on our Mid-America and Seminole pipeline systems to recover increased costs of operating the pipelines, principally those costs attributable to fuel and pipeline integrity expenses. In March 2005, the joint tariff rate for Mid-America and Seminole increased, which should result in additional revenues of approximately $10 million per year on a combined basis for these assets based on expected transportation rates. In May 2005, the FERC allowed a cost of service increase in Mid-America’s local tariffs (subject to refund and further review) that is expected to provide our Mid-America pipeline additional revenues of approximately $12 million per year based on expected transportation rates. This cost of service adjustment has been protested by shippers, so although the increased rates are being collected from customers, revenue related to this cost of service adjustment is being deferred. If these protests are settled in favor of Mid-America during 2005, the deferred revenues will be recognized in earnings at that time. If these protests are settled in favor of the shippers, the deferred revenue amount will be refunded. As of September 30, 2005, $3.4 million in revenue associated with this cost of service adjustment has been deferred.

In addition to the above rate changes, in July 2005, Mid-America voluntarily filed a new tariff with the FERC to reduce certain transportation rates for mixed NGL product movements from the northern Rockies to Mont Belvieu, Texas. We filed this new tariff, which is a discount to our general commodity rate, to promote higher NGL recoveries at existing processing facilities connected to the system and to encourage the construction of new cryogenic natural gas processing plants in the region that could be connected to the system. Additionally, we believe that, subject to negotiations with our shippers, the new tariff could result in longer term dedications of NGL supplies to the system and higher fuel reimbursement from our shippers than we have under our existing contracts. Based on current transportation volumes, if the new lower rates are fully implemented, system revenues on Mid-America may decrease by as much as

$12 million per year depending upon actual product recoveries and movements. However, it is expected that the lower revenues would be offset by the benefit of longer term dedications, higher fuel recovery and increased volumes. We will periodically review the effectiveness of the new rates to determine if we will elect to keep them in place.

Petrochemical Services. Gross operating margin from this business segment increased $12.1 million quarter-to-quarter primarily due to a $12 million increase in gross operating margin from our octane enhancement business and isomerization facilities. Improved results from these businesses are attributable to increased demand for motor gasoline and motor gasoline additives in the third quarter of 2005. Our octane-additive production facility is capable of producing either MTBE or isooctane as economic conditions warrant. The facility may be further modified in the future to produce alkylate.

Other. Gross operating margin from this segment pertains to equity earnings we recorded from GulfTerra GP prior to its consolidation with our financial results upon completion of the GulfTerra merger on September 30, 2004.

Nine Months Ended September 30, 2005 Compared with the

Nine Months Ended September 30, 2004

Revenues for the nine months ended September 30, 2005 increased $3 billion over those recorded during the same period in 2004. The trend in consolidated revenues can be attributed to (i) a $1.5 billion increase in revenues from our NGL and petrochemical marketing activities primarily resulting from an increase in sales volumes and energy commodity prices and (ii) the addition of $1.4 billion in revenues from acquired or consolidated businesses, primarily those generated by the GulfTerra and South Texas midstream assets.

Consolidated costs and expenses increased $2.7 billion period-to-period primarily due to (i) an increase in volumes purchased including the effects of higher product prices, which resulted in a $1.3 billion increase in the cost of sales of our NGL and petrochemical marketing activities and (ii) the addition of $1.1 billion in costs and expenses attributable to acquired or consolidated businesses. General and administrative costs increased $20 million period-to-period primarily due to businesses acquired since September 30, 2004.

Changes in our revenues and costs and expenses period-to-period are explained in part by changes in commodity prices. The indicative weighted-average market price for NGLs was 86 cents per gallon for the nine months ended September 30, 2005 versus 69 cents per gallon during the same period in 2004—a period-to-period increase of 25%. The Henry Hub market price for natural gas averaged $7.18 per MMBtu for the nine months ended September 30, 2005 versus $5.81 per MMBtu during the 2004 period. Polymer grade propylene index prices increased 29% period-to-period and refinery grade propylene index prices increased 31% period-to-period.

Equity earnings from unconsolidated affiliates decreased $27.7 million period-to-period, which includes an $11.5 million one-time charge recorded in the second quarter of 2005 related to the refinancing of Cameron Highway’s project debt. Our share of earnings from investments we acquired in connection with the GulfTerra Merger is included in equity earnings for the first nine months of 2005. The first nine months of 2004 includes $32 million of equity earnings from GulfTerra GP, which we began consolidating on September 30, 2004 as a result of completing the GulfTerra Merger. Collectively, the aforementioned changes in revenues, costs and expenses and equity earnings contributed to a $237.1 million increase in operating income period-to-period.

The $74.6 million increase in interest expense is attributable to the senior notes we issued during October 2004 in connection with the GulfTerra Merger and the issuance of additional senior notes during the first nine months of 2005. Our weighted-average debt principal outstanding was $4.8 billion during the first nine months of 2005 compared to $2.3 billion during the same period in 2004.

As a result of the items noted in previous paragraphs, our net income increased $14 million to $35.6 million for the nine months ended September 30, 2005 from $21.7 million for the 2004 period. The first nine months of 2004 includes a $0.2 million benefit related to the cumulative effect of changes in accounting principles adopted during 2004. For additional information regarding the cumulative effect of changes in accounting principles we recorded during 2004, please read “Other Items” included within this Item 2.

The following information highlights the significant period-to-period variances in gross operating margin by business segment.

Offshore Pipelines & Services. Gross operating margin from this business segment increased $59.6 million period-to-period primarily due to offshore Gulf of Mexico assets acquired in connection with the GulfTerra Merger. These assets accounted for $57.4 million of gross operating margin recorded for this segment during the nine months ended September 30, 2005. Gross operating margin for the 2005 period also includes $11.5 million in one-time charges related to the refinancing of Cameron Highway’s project debt and a $5.1 million one-time benefit related to the resolution of a transportation contract dispute involving Neptune. For additional information regarding Cameron Highway's debt restructuring, please read Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

Onshore Natural Gas Pipelines & Services. Gross operating margin from this business segment increased $238.8 million period-to-period primarily due to onshore natural gas pipeline and storage assets we acquired in connection with the GulfTerra Merger. These assets accounted for $235.9 million of gross operating margin recorded for this segment during the first nine months of 2005. Our Texas Intrastate System generated gross operating margin of $75.2 million during the 2005 period on average transportation volumes of 3,463 BBtus/d. Our San Juan Gathering System contributed $108.2 million of gross operating margin during the 2005 period on average transportation volumes of 1,188 BBtus/d. We acquired the Texas Intrastate System and the San Juan Gathering System in connection with the GulfTerra Merger. Natural gas storage assets acquired in the GulfTerra Merger contributed $31.1 million to gross operating margin during 2005.

NGL Pipelines & Services. Gross operating margin from this business segment increased $195.7 million period-to-period primarily due to contributions from assets we acquired in connection with the GulfTerra Merger and improved processing economics and NGL sales margins. Gross operating margin from natural gas processing assets we acquired in connection with the GulfTerra Merger accounted for $131.2 million of the increase in gross operating margin for this segment. Gross operating margin from our NGL marketing activities and Louisiana natural gas processing facilities increased $60.5 million period-to-period primarily due to higher NGL sales volumes and energy commodity prices.

Gross operating margin from our NGL pipelines and related storage assets decreased $3.3 million period-to-period due to a $4.3 million charge recorded by Dixie in May 2005 related to off specification propane injected into its pipeline system and lower earnings from our Mid-America pipeline, NGL storage facilities and South Louisiana pipelines. These decreases were partially offset by improved results from our NGL import facility and related pipeline system and the addition of gross operating margin from assets acquired or consolidated since September 30, 2004.

Gross operating margin from NGL fractionation increased $19.4 million period-to-period primarily due to NGL fractionation assets we acquired in connection with the GulfTerra Merger. Expenses related to support services classified within this segment increased $14.7 million period-to-period primarily due to increased business activities associated with acquired assets.

Petrochemical Services. Gross operating margin from this business segment decreased $5.2 million period-to-period due to a decrease in earnings from our octane enhancement and propylene fractionation businesses partially offset by an $8.5 million increase from our isomerization business. Our octane additive production facility encountered isooctane production difficulties during the second quarter of 2005, which resulted in a prolonged period of start-up activities. Gross operating margin from propylene

fractionation decreased period-to-period primarily due to lower product sales margins and propylene transportation volumes caused by a sharp decline in propylene prices during the second quarter of 2005.

LIQUIDITY AND CAPITAL RESOURCES

Parent Company Only – Enterprise GP Holdings

The parent company has no separate operating activities apart from those conducted by the Operating Partnership. The primary sources of cash flow for the parent company are its investments in the limited and general partner ownership interests of Enterprise Products Partners. The amount of cash that Enterprise Products Partners can distribute to its partners, including us, each quarter is based on earnings from Enterprise Products Partners' business activities, which are exposed to certain risks. For a summary of these risks, please read “Cautionary Statement Regarding Forward-Looking Information and Risk Factors” included within this Item 2.

The parent company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. We expect to fund our short-term needs for such items as general and administrative expenses with operating cash flows. Debt service requirements are expected to be funded by operating cash flows and/or refinancing arrangements. We expect to fund cash distributions to our partners primarily with operating cash flows.

We did not receive any cash distributions from Enterprise Products Partners or Enterprise Products GP during the period August 29, 2005 through September 30, 2005. Conversely, we did not make any parent company distributions to its partners during this period. On November 10, 2005, we will pay a prorated quarterly distribution of $0.092 per unit (based on our initial declared quarterly distribution of $0.265 per unit) for the 32-day period after the closing of our initial public offering beginning on August 30, 2005 and ending September 30, 2005. For additional information regarding our cash distribution policy, please read Note 9 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

Parent company debt obligation – $525 Million Credit Facility. On August 29, 2005, the parent company entered into a $525 million credit facility consisting of a $475 million term loan and a $50 million revolving credit facility, both maturing in February 2006. Additionally, on August 29, 2005, we borrowed $525 million under the new facility to repay (i) $160 million of indebtedness owed by Enterprise Products GP to an affiliate of EPCO that was originally incurred to finance Enterprise Products GP's purchase of a 50% interest in GulfTerra's general partner and (ii) the $160 million of debt we assumed from EPCO as part of the contribution of net assets to us by affiliates of EPCO. The parent company used proceeds from its August 2005 initial public offering to repay some of the borrowings under the new credit facility. At September 30, 2005, the parent company had approximately $124.5 million of borrowings outstanding under the $475 million term loan portion of the new credit facility and approximately $25.5 million of liquidity under the $50 million revolving portion of the new credit facility.

Consolidated Liquidity and Capital Resources

As previously discussed, we own the general partner of Enterprise Products Partners. As a result, our financial results reflect the consolidated financial results of Enterprise Products Partners and its general partner. The following is a discussion of our consolidated liquidity and capital resources, which includes Enterprise Products Partners and its general partner.

Our primary consolidated cash requirements, in addition to normal operating expenses and debt service, are for capital expenditures, business acquisitions and distributions to our partners. We expect to fund our short-term needs for such items as operating expenses and sustaining capital expenditures with operating cash flows. Capital expenditures for long-term needs resulting from internal growth projects and business acquisitions are expected to be funded by a variety of sources (either separately or in combination) including cash flows from operating activities, borrowings under commercial bank credit facilities, the issuance of additional partnership equity in Enterprise Products Partners and public or private placement debt. We expect to fund cash distributions to partners primarily with operating cash flows. Our debt service requirements are expected to be funded by operating cash flows and/or refinancing arrangements.

As noted above, certain of our liquidity and capital resource requirements are fulfilled by borrowings made under debt agreements and/or proceeds from the issuance of additional partnership equity of Enterprise Products Partners. At September 30, 2005, we had $33.2 million of unrestricted cash, approximately $25.5 million of available credit under the revolving portion of our $525 million Credit Facility and approximately $388.9 million of available credit under the Operating Partnership's Multi-Year Revolving Credit Facility . In total, we had approximately $5 billion in principal outstanding under various debt agreements at September 30, 2005. In October 2005, we increased the borrowing capacity under our Operating Partnership’s Multi-Year Revolving Credit Facility from $750 million to $1.25 billion. On a pro forma basis at September 30, 2005, total availability under the Operating Partnership’s Multi-Year Revolving Credit Facility increased to $788.9 million, after taking into account the aforementioned amendment which increased borrowing capacity by $500 million and the contemporaneous repayment of $100 million under a short-term promissory note.

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

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

Registration Statements and Equity and Debt Offerings

In March 2005, Enterprise Products Partners filed a universal shelf registration statement with the SEC registering the issuance of $4 billion of partnership equity and public debt obligations. In connection with this registration statement, Enterprise Products Partners also registered for resale 35,368,522 common units owned by Shell and 5,631,478 common units owned by a third party, Kayne Anderson MLP Investment Company ("Kayne Anderson"). Kayne Anderson purchased its unregistered common units from Shell in December 2004 and March 2005. We were obligated to register the resale of these common units under a registration rights agreement we executed with Shell in connection with our acquisition of certain of Shell's Gulf Coast midstream energy businesses in September 1999.

In February 2005, Enterprise Products Partners sold 17,250,000 common units (including the over-allotment amount of 2,250,000 common units which closed on March 11, 2005) under a preexisting registration statement from which it received net proceeds of approximately $456.7 million, including Enterprise Products GP’s proportionate net capital contribution of $9.1 million. The proceeds from this public offering were used to repay our 364-Day Acquisition Credit Facility, to temporarily reduce

indebtedness outstanding under our Multi-Year Revolving Credit Facility and for general partnership purposes.

In February 2005, the Operating Partnership sold $500 million in principal amount of senior notes in a private offering, comprised of $250 million in principal amount of 10-year senior unsecured notes and $250 million in principal amount of 30-year senior unsecured notes. The 10-year notes ("Senior Notes I") were issued at 99.379% of their principal amount and have annual fixed-rate interest of 5.00% and mature in March 2015. The 30-year notes ("Senior Note J") were issued at 98.691% of their principal amount and have annual fixed-rate interest of 5.75% and a mature in March 2035. The Operating Partnership used the net proceeds from the issuance of Senior Notes I and J to repay $350 million of indebtedness outstanding under Senior Notes A, which was due in March 2005, and the remaining proceeds for general partnership purposes, including the temporary repayment of indebtedness outstanding under the Multi-Year Revolving Credit Facility. In July 2005, we filed a registration statement for an offer to exchange these notes for registered debt securities with identical terms. The exchange of notes was completed in August 2005.

In June 2005, the Operating Partnership sold $500 million in principal amount of five-year senior unsecured notes. The five-year notes ("Senior Notes K") were issued at 99.834% of their principal amount and have a fixed-rate interest of 4.95% and mature in June 2010. The Operating Partnership used the net proceeds from the issuance of Senior Notes K to temporarily reduce borrowings outstanding under the Multi-Year Revolving Credit Facility and for general partnership purposes, including capital expenditures and business combinations. These notes were registered under the $4 billion universal shelf registration statement we filed with the SEC in March.

In August 2005, we sold 14,216,784 common units (including the over-allotment amount of 1,616,784 common units) in our initial public offering. For additional information regarding the parent company’s standalone activities, please read “Liquidity and Capital Resources – Parent Company – Enterprise GP Holdings.”

Consolidated Debt Obligations

The following table summarizes our consolidated debt obligations at the dates indicated.

			September 30,	December 31,
			2005	2004
Parent company debt obligation:
	$525 Million Credit Facility, variable rate, due February 2006		$ 149,000
Enterprise Products GP related party obligation:
	$370 Million Note, 6.25% fixed-rate, repaid August 2005 (1)			$ 366,433
Operating Partnership debt obligations:
	364-Day Acquisition Credit Facility, variable rate, repaid in February 2005 (2)			242,229
	Multi-Year Revolving Credit Facility, variable rate, due October 2010 (3)		335,000	321,000
	30-Day Promissory Note, variable rate, repaid October 2005 (4)		100,000
	Seminole Notes, 6.67% fixed-rate, due December 2005		15,000	15,000
	Pascagoula MBFC Loan, 8.70% fixed-rate, due March 2010		54,000	54,000
	Senior Notes A, 8.25% fixed-rate, repaid March 2005			350,000
	Senior Notes B, 7.50% fixed-rate, due February 2011		450,000	450,000
	Senior Notes C, 6.375% fixed-rate, due February 2013		350,000	350,000
	Senior Notes D, 6.875% fixed-rate, due March 2033		500,000	500,000
	Senior Notes E, 4.00% fixed-rate, due October 2007		500,000	500,000
	Senior Notes F, 4.625% fixed-rate, due October 2009		500,000	500,000
	Senior Notes G, 5.60% fixed-rate, due October 2014		650,000	650,000
	Senior Notes H, 6.65% fixed-rate, due October 2034		350,000	350,000
	Senior Notes I, 5.00% fixed-rate, due March 2015		250,000
	Senior Notes J, 5.75% fixed-rate, due March 2035		250,000
	Senior Notes K, 4.95% fixed-rate, due June 2010		500,000
	Dixie revolving credit facility, due June 2007		17,000
	GulfTerra Senior Notes and Senior Subordinated Notes (5)		5,673	6,469
		Total principal amount	4,975,673	4,655,131
Other, including unamortized discounts and premiums and changes in fair value (6)			(22,833)	(7,462)
		Subtotal long-term debt	4,952,840	4,647,669
Less current maturities of debt (7)			(164,000)	(18,450)
		Long-term debt	$ 4,788,840	$ 4,629,219

Standby letters of credit outstanding			$ 66,411	$ 139,052

(1) This amount was repaid in August 2005 using borrowings under our $525 Million Credit Facility. (2) Enterprise Products Partners used the proceeds from its February 2005 common unit offering to fully repay and terminate the 364-Day Acquisition Credit Facility. (3) At September 30, 2005 and December 31, 2004, the Multi-Year Revolving Credit Facility had a $750 million borrowing capacity, which was reduced by the amount of standby letters of credit outstanding. In October 2005, the Operating Partnership executed an amended Multi-Year Revolving Credit Facility, which among other things, (i) increased the borrowing capacity to $1.25 billion, which is reduced by the amount of standby letters of credit outstanding, (ii) extended the maturity date from September 2009 to October 2010 and (iii) removed the $100 million limit on the total amount of standby letters of credit that can be outstanding under the facility. For additional information regarding the amended Multi-Year Revolving Credit Facility, please see Note 18 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.. (4) The Operating Partnership used borrowings under the Multi-Year Revolving Credit Facility to repay the 30-Day Promissory Note in October 2005. (5) GulfTerra’s remaining $0.8 million of 6.25% Senior Notes due June 2010 were called and retired in February 2005. Additionally, in October 2005, we called and retired $0.6 million of GulfTerra' Senior Subordinated Notes. (6) The September 30, 2005 amount includes $8.5 million related to fair value hedges and $14.3 million in net unamortized discounts. (7) In accordance with SFAS No. 6, "Classification of Short-Term Obligations Expected to Be Refinanced," long-term and current maturities of debt at September 30, 2005, reflected our repayment of the 30-Day Promissory Note in October 2005 using borrowings under our Multi-Year Revolving Credit Facility, which is due in October 2010. Additionally, in accordance with SFAS No. 6, long-term and current maturities of debt at December 31, 2004 reflected (i) our refinancing of Senior Notes A with proceeds from our Senior Notes I and J in March 2005 and (ii) the repayment of our 364-Day Acquisition Credit Facility using proceeds from an equity offering completed in February 2005.

We have three unconsolidated affiliates with long-term debt obligations. The following table shows our ownership interest in each entity at September 30, 2005 and total long-term debt obligations (including current maturities) of each unconsolidated affiliate at September 30, 2005, on a 100% basis to the joint venture.

	Our
	Ownership
	Interest	Total
Cameron Highway	50.0%	$ 415,000
Poseidon	36.0%	96,000
Evangeline	49.5%	35,650
Total		$ 546,650

For additional information regarding our consolidated debt obligations and those of our unconsolidated affiliates, please read Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

Credit Ratings

Currently, the credit ratings of our Operating Partnership’s debt obligations are Baa3 with a stable outlook as rated by Moody’s Investor Services; BB+ with a stable outlook as rated by Standard and Poor’s; and BBB- with a stable outlook by Fitch ratings.

Comparison of Consolidated Cash Flows for the Nine Months Ended September 30, 2005

with Consolidated Cash Flows for the Nine Months Ended September 30, 2004

Cash flows from our consolidated operating activities primarily reflect net income adjusted for depreciation, amortization and similar non-cash amounts; equity earnings and cash distributions from unconsolidated affiliates; and changes in operating accounts. For additional information regarding changes in operating accounts, please read Note 11 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

Cash flow from operations is primarily based on earnings from our consolidated business activities. As a result, these cash flows are exposed to certain risks. We operate predominantly in the midstream energy industry, which includes gathering, transporting, processing, fractionating and storing natural gas, NGLs and crude oil. In general, we provide services for producers and consumers of natural gas, NGLs and crude oil from the wellhead to the end user. The products that we process, sell or transport are principally used as fuel for residential, agricultural and commercial heating, feedstocks in petrochemical manufacturing and in the production of motor gasoline. Reduced demand for our services or products by industrial customers, whether because of general economic conditions, reduced demand for the end products made with our products or increased competition from other service providers or producers due to pricing differences or other reasons, could have a negative impact on our earnings and thus the availability of cash from operating activities. Other risks include fluctuations in oil, natural gas and NGL prices, competitive practices in the midstream energy industry and the impact of operational and systems risks. For a summary of the risk factors pertinent to our business, please read "Cautionary Statement Regarding Forward-Looking Information and Risk Factors" included within this Item 2.

Operating activities. For the nine months ended September 30, 2005 and 2004, cash provided by operating activities was $329.2 million and $36 million, respectively. The period-to-period increase in cash provided by operating activities is partially attributable to increased earnings as discussed under "Results of Operations - Consolidated Results of Operations," included within this Item 2. A description of the other significant period-to-period fluctuations of the remaining line items within this section of our Unaudited Condensed Statements of Consolidated Cash Flows follows:

•

As measured by the net effect of changes in our operating accounts, we used an additional $72.4 million of cash for working capital purposes when compared to the nine months ended September

30, 2004. In general, the net effect of changes in operating accounts is the result of timing of cash receipts from sales and cash payments for purchases and other expenses near the end of each period, including the effects of increased transactions resulting from the GulfTerra Merger. Increases or decreases in inventory are influenced by changes in commodity prices and our marketing activities.

•

Cash distributions from unconsolidated affiliates decreased $7.2 million period-to-period primarily due to distributions of $32.3 million from GulfTerra GP, which we began consolidating on September 30, 2004, offset by $25.6 million in distributions received from investments we acquired in the GulfTerra Merger.

Investing activities. For the nine months ended September 30, 2005 and 2004, we used $881.9 million and $1.1 billion, respectively, for investing activities. During the nine months ended September 30, 2005, we used $144 million to purchase NGL underground storage and terminaling assets from Ferrellgas, $74.9 million to purchase from El Paso two entities which owned interests in the Indian Springs natural gas gathering and processing assets, $73 million to purchase additional ownership interests in Dixie and Belle Rose and $25 million to purchase an additional 2% indirect interest in the Mid-America Pipeline System and an additional 1.6% indirect interest in the Seminole pipeline. During the 2004 period we used $1 billion to complete the GulfTerra Merger, and we used $57.9 million to purchase additional ownership interests in Tri-States, Seminole and BEF. Capital expenditures were $627.9 million during the nine months ended September 30, 2005 period compared to $39.4 million for the same period in 2004, and contributions in aid of construction costs were $40.4 million during the nine months ended September 30, 2005 period compared to $0.5 million for the same period in 2004. For additional information regarding our capital expenditures and contributions in aid of construction costs, please read "Capital Spending" included within this Item 2.

Our investments in unconsolidated affiliates were $80.8 million during the nine months ended September 30, 2005 compared to $1.1 million during the same period in 2004. In March 2005, we contributed $72 million to Deepwater Gateway to fund our share of the repayment of its $144 million term loan. In addition, our cash flows from investing activities for the nine months ended September 30, 2005, include (i) $42.1 million in proceeds from the sale of our 50% equity interest in Starfish in March 2005, which was required to gain regulatory approval for the GulfTerra Merger and (ii) $47.5 million related to a return of our investment in Cameron Highway associated with the refinancing of its project debt in June 2005, which we will use to fund capital expenditures associated with our growth capital projects. For additional information regarding the refinancing of Cameron Highway's debt, please read Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report. The period-to-period fluctuation in the restricted cash balance is primarily due to timing of physical purchases of natural gas on the NYMEX exchange.

Financing activities. For the nine months ended September 30, 2005 and 2004, cash provided by financing activities was $560.8 million and $1.2 billion, respectively. During the nine months ended September 30, 2005, we had net borrowings on our debt obligations of $144.9 million compared to net borrowings of $1.8 billion during the same period in 2004.

During the nine months ended September 30, 2005, the Operating Partnership issued an aggregate of $1 billion in senior notes, the proceeds of which were used to repay $350 million due under Senior Notes A, to temporarily reduce amounts outstanding under the Operating Partnership's bank credit facilities and for general partnership purposes, including capital expenditures and business combinations. Additionally, the Operating Partnership repaid the remaining $242.2 million that was due under our 364-Day Acquisition Credit Facility using proceeds from Enterprise Products Partners' February 2005 equity offering. In August 2005, we borrowed $525 million under our new credit facility to repay (i) the indebtedness owed by Enterprise Products GP to an affiliate of EPCO that was originally incurred to finance Enterprise Products GP's purchase of a 50% interest in GulfTerra's general partner and (ii) the $160 million of debt we assumed from EPCO as part of the contribution of net assets to us by affiliates of EPCO in August 2005. We used the proceeds from our initial public offering in August 2005 to repay some of the borrowings under our new credit facility.

The 2004 period reflects the Operating Partnership's borrowings of approximately $2.8 billion under bank credit facilities on September 30, 2004 to (i) fund $655.3 million in cash payment obligations to El Paso associated with the GulfTerra Merger, (ii) escrow $1.1 billion to finance our tender offers for GulfTerra's senior and senior subordinated notes and (iii) extinguish $962 million outstanding under GulfTerra's revolving credit facility and secured term loans. Additionally, on September 30, 2004, Enterprise Products GP borrowed $370 million from an affiliate of EPCO to fund additional cash payment obligations to El Paso associated with the GulfTerra Merger. Our repayments of debt during the 2004 period reflect the use of proceeds from Enterprise Products Partners' May 2004 and August 2004 equity offerings to repay the Operating Partnership's $225 million Interim Term Loan and to temporarily reduce amounts outstanding under the Operating Partnership's bank credit facilities.

Distributions paid to minority interests increased from $259.3 million during the nine months ended September 30, 2004 to $478.9 million during the same period in 2005. Distributions paid to minority interests primarily represents the distributions paid to the limited partners of Enterprise Products Partners excluding the limited partner interests owned by Enterprise GP Holdings, in accordance with Enterprise Products Partners' partnership agreement. The increase in quarterly cash distributions paid by Enterprise Products Partners is primarily due to an increase in the number of Enterprise Products Partners' common units eligible for distributions and an increase in Enterprise Products Partners' declared quarterly cash distribution rate. We expect that future distributions paid to minority interests will increase as a result of Enterprise Products Partners' periodic issuance of common units under the DRIP and other equity offerings.

Contributions from minority interests was $555 million for the nine months ended September 30, 2005, compared to $747.3 million for the same period in 2004. Contributions from minority interests primarily represent (i) net proceeds Enterprise Products Partners' limited partners received from common unit offerings, (ii) proceeds Enterprise Products Partners' limited partners received from the exercise of unit options under EPCO's 1998 Long-Term Incentive Plan and (iii) contributions from Enterprise Products Partners' joint venture partners.

During the nine months ended September 30, 2005, the limited partners of Enterprise Products Partners received net proceeds of approximately $506 million from common unit offerings, and proceeds of $20.5 million from the exercise of unit options. In February 2005, Enterprise Products Partners sold 17,250,000 common units (including the over-allotment amount of 2,250,000 common units) in a public offering. Additionally, during the nine months ended September 30, 2005, Enterprise Products Partners sold 2,326,622 common units in connection with the DRIP. During the nine months ended September 30, 2004, the limited partners of Enterprise Products Partners received net proceeds of approximately $740.8 million from common unit offerings. In each of May 2004 and August 2004, Enterprise Products Partners sold 17,250,000 common units (including the over-allotment amounts of 2,250,000 common units) in two separate public offerings. Additionally, during the nine months ended September 2004, Enterprise Products Partners sold 2,912,864 common units in connection with the DRIP.

CONTRACTUAL OBLIGATIONS

With regards to our material contractual obligations, there have been no significant changes outside of the ordinary course of business since those reported in our registration statement on Form S-1 for the year ended December 31, 2004 with the exception of debt. For additional information regarding changes in our consolidated debt obligations since December 31, 2004, please read Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

RECENT ACCOUNTING DEVELOPMENTS

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

•

SFAS No. 123(R), “Share-Based Payment” issued by the FASB and the related SAB 107 issued by the SEC;

•

FIN 46(R)-5, "Implicit Variable Interests Under FASB Interpretation No. 46(R), Consolidation of Variable Interest Entities";

•

FIN 47, “Accounting for Conditional Asset Retirement Obligations”,

•

SFAS No. 154, “Accounting Changes and Error Corrections;” and

•

EITF 04-13, "Accounting for Purchases and Sale of Inventory with Same Counterparty."

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

CRITICAL ACCOUNTING POLICIES

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

The following describes the estimation risk underlying our most significant financial statement items:

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

At September 30, 2005 and December 31, 2004, the net book value of our property, plant and equipment was $8.4 billion and $7.8 billion, respectively. For additional information regarding our property, plant and equipment, please read Note 5 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

Measuring recoverability of long-lived assets and equity method investments. In general, long-lived assets (including intangible assets with finite useful lives and property, plant and equipment) are reviewed for impairment whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. Equity method investments are evaluated for impairment whenever events or changes in circumstances indicate that there is a loss in value of the investment that is an other than temporary decline. Measuring the potential impairment of such assets and investments involves the estimation of future cash flows to be derived from the asset being tested. Our estimates of such cash flows are based on a number of assumptions including anticipated margins and volumes; estimated useful life of the asset or asset group; and salvage values. A significant change in these underlying assumptions could result in our recording an impairment charge.

In connection with obtaining regulatory approval for the GulfTerra Merger, we were required to sell our undivided 50% interest in a Mississippi propane storage facility by December 31, 2004. As a result

of our determination of this long-lived asset's current market value, we recorded a non-cash asset impairment charge of $4 million during the third quarter of 2004, which is reflected as a component of operating costs and expenses on our Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income. We did not record any impairment charges during the nine months ended September 30, 2005.

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

At September 30, 2005 and December 31, 2004, the carrying value of our intangible asset portfolio was $941.5 million and $980.6 million. For additional information regarding our intangible assets, please read Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

Methods we employ to measure the fair value of goodwill. In general, goodwill is attributable to the excess of the purchase price over the fair value of assets acquired. Goodwill is not amortized. Instead, goodwill is tested for impairment at a reporting unit level during the second quarter of each fiscal year, and more frequently, if circumstances indicate it is more likely than not that the fair value of goodwill is below its carrying amount. Testing goodwill for impairment involves calculating the fair value of a reporting unit, which in turn is based on our assumptions regarding the future economic prospects of the reporting unit. Our estimates of such prospects (i.e., cash flows) are based on a number of assumptions including anticipated margins and volumes of the underlying assets or asset group. A significant change in these underlying assumptions could result in our recording an impairment charge.

At September 30, 2005 and December 31, 2004, the carrying value of our goodwill was $489.4 million and $459.2 million. For additional information regarding our goodwill, please read Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

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

Reserves for environmental matters. Each of our business segments is subject to extensive federal, state and local laws and regulations governing environmental quality and pollution control. We accrue reserves for environmental matters when our assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. Our assessments are based on studies, as well as site surveys, to determine the extent of any environmental damage and the necessary requirements to remediate this damage. Our actual results may differ from our estimates, and our estimates can be, and often are, revised in the future, either negatively or positively, depending upon the outcome or expectations based on the facts surrounding each exposure.

At September 30, 2005 and December 31, 2004, we had a liability for environmental remediation of $21 million, which was derived from a range of reasonable estimates based upon studies and site surveys. In accordance with SFAS No. 5 "Accounting for Contingencies" and FASB Interpretation No. 14,

"Reasonable Estimation of the Amount of a Loss," we recorded our best estimate of the costs for these remediation activities.

Natural gas imbalances. Natural gas imbalances result when customers physically deliver a larger or smaller quantity of gas into our pipelines than they take out. We generally value our imbalances using a twelve-month moving average of natural gas prices, which we believe is an appropriate assumption to estimate the value of the imbalances at the time of settlement given that the actual settlement dates are generally not known. Changes in natural gas prices may impact our estimates.

At September 30, 2005 and December 31, 2004, our imbalance receivables were $70 million and $56.7 million, respectively, and are reflected as a component of accounts receivable. At September 30, 2005 and December 31, 2004, our imbalance payables were $52 million and $59 million, respectively, and are reflected as a component of accrued gas payables.

SUMMARY OF RELATED PARTY TRANSACTIONS

The following is a summary of our related party relationships and transactions. For additional information regarding our current and historical related party relationships, please read Note 10 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

Relationship with EPCO. We have an extensive and ongoing relationship with EPCO. Collectively, EPCO and its affiliates owned a 86.5% equity interest in us at September 30, 2005. EPCO is controlled by Dan L. Duncan, who is also a director and Chairman of our general partner and Enterprise Products GP. Additionally, all of the executive officers and non-independent directors of our general partner also serve as executive officers or directors of Enterprise Products GP.

On August 29, 2005, affiliates of EPCO contributed certain partnership interests in Enterprise Products Partners to us (on a standalone basis) consisting of (i) a 100% ownership of Enterprise Products GP and (ii) 13,454,498 common units of Enterprise Products Partners acquired from an affiliate of El Paso in January 2005, representing an approximate 3.4% limited partner interest in Enterprise Products Partners.

We also assumed $160 million in debt and $0.5 million of accrued interest from EPCO in connection with the transfer of these assets, which was subsequently repaid using borrowings under our new credit facility (see Note 1 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report). The assumed debt amount represents a portion of the $425 million borrowed by EPCO in January 2005 to purchase 13,454,498 common units of Enterprise Products Partners and a 9.9% ownership interest in Enterprise Products GP from an affiliate of El Paso. Upon completion of EPCO's purchase of El Paso's 9.9% ownership interest in Enterprise Products GP, EPCO and its affiliates owned 100% of the equity interests in Enterprise Products GP. Additionally, EPCO affiliates received 74,667,332 of our common units in connection with the contribution of net assets by affiliates of EPCO to us.

We have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to the Administrative Services Agreement. We reimburse EPCO for the costs of its employees who perform operating functions for us and for costs related to its other management and administrative employees. Additionally, we reimburse EPCO for the costs associated with the office space we occupy related to our partnership's headquarters. In August 2005, a Third Amended and Restated Administrative Services Agreement was executed, which was effective as of February 24, 2005. For additional information regarding the Amended and Restated Administrative Services Agreement, see Note 10 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of the quarterly report. Our other transactions with EPCO and its affiliates include:

•

We have entered into an agreement with an affiliate of EPCO to provide trucking services to us for the transportation of NGLs and other products.

•

In the normal course of business, we buy from and sell certain NGL products to an affiliate of EPCO.

In September 2004, our subsidiary, Enterprise Products GP, borrowed $370 million from an affiliate of EPCO to finance the purchase of a 50% membership interest in GulfTerra GP. This promissory note bore fixed-rate interest of 6.25% and was repaid in August 2005 using borrowings under the Enterprise GP Holdings Credit Facility. We recorded $3.7 million and $15.2 million in interest related to this promissory note for the three and nine months ended September 30, 2005.

Our related party revenues from EPCO and affiliates were nominal for the three months ended September 30, 2005 and 2004, and $0.3 million and $2.3 million for the nine months ended September 30, 2005 and 2004, respectively. Our related party expenses paid to EPCO and affiliates were $71 million and $55.5 million for the three months ended September 30, 2005 and 2004, and $205 million and $146.8 million for the nine months ended September 30, 2005 and 2004, respectively.

Relationship with TEPPCO. On February 24, 2005, an affiliate of EPCO acquired Texas Eastern Products Pipeline Company, LLC ("TEPPCO GP"), the general partner of TEPPCO Partners, L.P. (“TEPPCO”) from Duke Energy Field Services, LLC, and 2,500,000 common units of TEPPCO from Duke Energy Corporation for approximately $1.2 billion in cash. TEPPCO GP owns a 2% general partner interest in TEPPCO and is the managing partner of TEPPCO and its subsidiaries. Subsequently, EPCO reconstituted the board of directors of TEPPCO GP and Dr. Ralph Cunningham (a former independent director of Enterprise Products GP) was named Chairman of TEPPCO GP. Due to EPCO's ownership of TEPPCO GP and TEPPCO GP's ability to direct the management of TEPPCO, TEPPCO GP and TEPPCO became related parties to EPCO and the Company during the first quarter of 2005. The employees of TEPPCO became EPCO employees on June 1, 2005. Our related party transactions with TEPPCO consist of the purchase of NGL pipeline transportation and storage services.

On March 11, 2005, the Bureau of Competition of the U.S. Federal Trade Commission (“FTC”) delivered written notice to EPCO’s legal advisor that it was conducting a non-public investigation to determine whether EPCO’s acquisition of TEPPCO GP may tend substantially to lessen competition. No filings were required under the Hart-Scott-Rodino Act in connection with EPCO’s purchase of TEPPCO GP. EPCO and its affiliates, including us, may receive similar inquiries from other regulatory authorities and intend to cooperate fully with any such investigations and inquiries. In response to such FTC investigation or any inquiries EPCO and its affiliates may receive from other regulatory authorities, we may be required to divest certain assets. In the event we are required to divest significant assets, our financial condition could be affected.

We did not have any related party revenues from TEPPCO and affiliates for the three and nine months ended September 30, 2005. Our related party expenses paid to TEPPCO and affiliates were $4 million and $12.6 million for the three and nine months ended September 30, 2005, respectively.

Relationship with unconsolidated affiliates. Our significant related party transactions with unconsolidated affiliates consist of the sale of natural gas to Evangeline, purchase of pipeline transportation services from Dixie (prior to its consolidation with our results beginning in February 2005, see Note 2) and the purchase of NGL storage, transportation and fractionation services from Promix. In addition, we sell

natural gas to Promix and process natural gas at VESCO. Our related party revenues from unconsolidated affiliates were $119 million and $89.4 million for the three months ended September 30, 2005 and 2004, and $257.8 million and $196.3 million for the nine months ended September 30, 2005 and 2004, respectively. Our related party expenses paid to unconsolidated affiliates were $11.5 million and $7.4 million for the three months ended September 30, 2005 and 2004, and $21.9 million and $23.9 million for the nine months ended September 30, 2005 and 2004, respectively.

Historical relationship with Shell. Historically, Shell Oil Company, its subsidiaries and affiliates (“Shell”) were collectively considered a related party because Shell owned more than 10% of Enterprise Products Partners' limited partner interests and, prior to September 2003, owned a 30% ownership interest in Enterprise Products GP. As a result of Shell selling a portion of its limited partner interests in Enterprise Products Partners to third parties in December 2004 and during the first seven months of 2005, Shell now owns less than 10% of Enterprise Products Partners common units. Shell sold its 30% interest in Enterprise Products GP to an affiliate of EPCO in September 2003. As a result of Shell's reduced equity interest in Enterprise Products Partners and its lack of control of Enterprise Products GP, Shell ceased to be considered a related party beginning in the first quarter of 2005. For the three months ended September 30, 2004, our related party revenues from Shell and expenses paid to Shell were $148.8 million and $189.4 million, respectively. Our related party revenues from Shell and expenses paid to Shell for the nine months ended September 30, 2004, were $397.8 million and $536.3 million, respectively.

OTHER ITEMS

Recent regulatory developments. On May 4, 2005, the FERC issued a policy statement providing that all entities owning public utility assets – oil and gas pipelines and electric utilities – would be permitted to include an income tax allowance in their rates to reflect the actual or potential income tax liability attributable to their public utility income, regardless of the form of ownership. Any tax pass-through entity seeking an income tax allowance would have to establish that its partners or members have an actual or potential income tax obligation on the entity's public utility income. The FERC has stated that it will determine on a case-by-case basis whether there is an actual or potential income tax liability. The policy appears to provide an opportunity for partnership-owned pipelines to seek allowances based upon their entire income paid to partners, rather than the partial allowance which was limited to partner interests owned by corporate partners. The policy statement is subject to rehearing and clarification by the FERC. We have not yet been able to determine the effect, if any, that this new FERC policy statement will have on the rates for transportation services on our interstate pipelines we charge or on the rates we will be allowed to charge in the future. We expect the implementation of the policy in individual cases will be subject to review by the United States Court of Appeals.

In December 2002, High Island Offshore System (“HIOS’), an interstate natural gas pipeline owned by us, filed a rate case pursuant to Section 4 of the Natural Gas Act before the FERC to increase its transportation fees. The FERC accepted HIOS’ tariff sheets implementing the new rates, subject to refund, and set certain issues for hearing before an Administrative Law Judge (“ALJ”). The ALJ issued an initial decision on the issues, proposing rates lower than the rate initially proposed by HIOS. In August 2004, in response to the ALJ’s initial decision, HIOS filed a settlement agreement whereby HIOS proposed to implement its rates in effect prior to this proceeding for a prospective three-year period. In January 2005, the FERC issued an order rejecting HIOS’ settlement offer and generally affirming the ALJ’s initial decision, resulting in rates significantly lower than the rate proposed in HIOS’ settlement offer. In February 2005, HIOS filed a request for rehearing with the FERC. In July 2005, the FERC issued an order denying all requests for rehearing, and the FERC required HIOS to implement the approved rate and to make refunds to its customers. The refunds to HIOS' customers were due in August 2005, and HIOS is fully reserved for the refund obligations.

Pipeline integrity costs. Our NGL, petrochemical and natural gas pipelines are subject to pipeline integrity management programs administered by the U.S. Department of Transportation, through its Office of Pipeline Safety. During the three months ended September 30, 2005, we spent approximately $10 million to comply with these programs, of which $6.1 million was recorded as an operating expense with

the remaining $3.9 million being capitalized. We spent approximately $20.5 million to comply with these programs during the nine months ended September 30, 2005, of which $13.3 million was recorded as an operating expense with the remaining $7.2 million being capitalized. Our net cash outlay for the pipeline integrity program is estimated to be approximately $53 million over the next six months (fourth quarter of 2005 and first quarter of 2006), of which $24 million is estimated to be recorded as an operating expense with the remaining $29 million being capitalized. The forecasted cost for the next six months is net of the value of an indemnification for such expenses that we expect to receive from El Paso related to pipelines acquired from GulfTerra.

Non-GAAP reconciliation. A reconciliation of our measurement of total non-GAAP gross operating margin to GAAP operating income and income before provision for income taxes, minority interest and the cumulative effect of changes in accounting principles (as shown on our Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income included under Item 1 of this quarterly report on Form 10-Q) follows:

		For the Three Months		For the Nine Months
		Ended September 30,		Ended September 30,
		2005	2004	2005	2004
Total non-GAAP gross operating margin		$ 311,816	$ 137,748	$ 832,905	$ 375,991
Adjustments to reconcile total non-GAAP gross operating margin
	to GAAP operating income:
	Depreciation and amortization in operating costs and expenses	(103,028)	(32,439)	(304,041)	(94,674)
	Retained lease expense, net in operating costs and expenses	(528)	(2,273)	(1,584)	(6,820)
	Gain (loss) on sale of assets in operating costs and expenses	(611)	(43)	4,742	(158)
	General and administrative costs	(13,654)	(10,300)	(47,689)	(27,069)
GAAP consolidated operating income		193,995	92,693	484,333	247,270
	Other expense	(63,918)	(31,872)	(183,223)	(96,024)
GAAP income before provision for income taxes, minority interest
	and cumulative effect of changes in accounting principles	$ 130,077	$ 60,821	$ 301,110	$ 151,246

EPCO subleases to us certain equipment located at our Mont Belvieu facility and 100 railcars for $1 per year. These subleases (the “retained lease expense” in the previous table) are part of the Administrative Services Agreement that we executed with EPCO in connection with Enterprise Products Partners formation in 1998. EPCO holds these items pursuant to operating leases for which it has retained the corresponding cash lease payment obligation.

Operating costs and expenses (as shown on the Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income included under Item 1 of this quarterly report on Form 10-Q) classify the lease payments being made by EPCO as a non-cash related party operating expense, with the offset to minority interest and partners’ equity on the Unaudited Condensed Consolidated Balance Sheets recorded as a general contribution to Enterprise Products Partners. Apart from the partnership interests we granted to EPCO at its formation, EPCO does not receive any additional ownership rights as a result of its contribution to us of the retained leases.

Cumulative effect of accounting changes recorded during 2004. The cumulative effect of changes in accounting principles represents the combined impact of changing (i) the method Enterprise Products Partners' BEF subsidiary uses to account for its planned major maintenance activities from the accrue-in-advance method to the expense-as-incurred method and (ii) the method Enterprise Products Partners used to account for our investment in VESCO. The cumulative effect of these changes in accounting principles resulted in a benefit of $10.8 million ($10.6 million recorded as a reduction to minority interest expense).

Financial statement classifications. Certain reclassifications have been made to the prior year’s financial statements to conform to the current year presentation. In accordance with SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements,” we have reclassified amounts related to our adoption of EITF 03-16, “Accounting for Investments in Limited Liability Companies,” on July 1, 2004.

Our adoption of EITF 03-16 on that date required us to change our method of accounting for our 13.1% investment in VESCO to the equity method from the cost method.

Since this change in accounting principle was made during the third quarter of 2004, our statement of consolidated operations and statement of consolidated cash flows for the three and nine months ended September 30, 2004 has been recast for comparability purposes.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

AND RISK FACTORS

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

Risk Factors. An investment in our common units involves risks. If any of these risks were to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, the trading price of our common units could decline, and you could lose all or part of your investment. Among the key risk factors that may have a direct impact on our results of operations and financial condition are:

•

Currently, our operating cash flow is derived primarily from cash distributions from Enterprise Products Partners, of which the risks of Enterprise Products Partners' business are:

•

Changes in the prices of hydrocarbons may materially adversely affect Enterprise Products Partners' results of operations, cash flow and financial condition;

•

A decline in the volumes of natural gas, NGLS and crude oil delivered to Enterprise Products Partners' facilities could materially adversely affect its results of operations, cash flows and financial condition;

•

A reduction in the demand for NGL products by the petrochemical, refining or heating industries could materially adversely affect Enterprise Products Partners' results of operations, cash flows and financial condition.

We have no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. For additional information regarding our risk factors, please refer to the section titled “Risk Factors” included within our registration statement on Form S-1. Other risks involved in our business are discussed under “Quantitative and Qualitative Disclosures about Market Risk” included under Item 3 of this quarterly report on Form 10-Q.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Interest rate risk hedging program. Our interest rate exposure results from variable and fixed rate borrowings under debt agreements. We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar arrangements, which allow us to convert a portion of fixed rate debt into variable rate debt or a portion of variable rate debt into fixed rate debt.

In August 2005, the Operating Partnership entered into two additional interest rate swap agreements with an aggregate notional amount of $200 million in which we exchanged the payment of fixed rate interest on a portion of the principal outstanding under Senior Notes K for variable rate interest. We have designated these two interest rate swaps as fair value hedges under SFAS No. 133 since they mitigate changes in the fair value of the underlying fixed rate debt. Under each swap agreement, we will pay the counterparty a variable interest rate based on six-month LIBOR rates (plus an applicable margin as defined in each swap agreement) and receive back from the counterparty a fixed interest rate payment of 4.95%, which is the stated interest rate of Senior Notes K. We will settle amounts receivable from or payable to the counterparty every six months (the "settlement period"), with the first settlement occurring on December 1, 2005. The settlement amount will be amortized ratably to earnings as either an increase or a decrease in interest expense over the settlement period.

As summarized in the following table, we had eleven interest rate swap agreements outstanding at September 30, 2005 that were accounted for as fair value hedges.

		Number	Period Covered	Termination	Fixed to	Notional
Hedged Fixed Rate Debt		Of Swaps	by Swap	Date of Swap	Variable Rate (1)	Amount
Senior Notes B, 7.50% fixed rate, due Feb. 2011		1	Jan. 2004 to Feb. 2011	Feb. 2011	7.50% to 7.26%	$50 million
Senior Notes C, 6.375% fixed rate, due Feb. 2013		2	Jan. 2004 to Feb. 2013	Feb. 2013	6.375% to 5.81%	$200 million
Senior Notes G, 5.6% fixed rate, due Oct. 2014		6	4th Qtr. 2004 to Oct. 2014	Oct. 2014	5.6% to 4.36%	$600 million
Senior Notes K, 4.95% fixed rate, due June 2010		2	Aug. 2005 to June 2010	June 2010	4.95% to 4.34%	$200 million
	(1) The variable rate indicated is the all-in variable rate for the current settlement period.

The following table shows the effect of hypothetical changes in interest rates on the estimated fair value (“FV”) of our interest rate swap portfolio and the related change in fair value of the underlying debt at October 12, 2005 (dollars in thousands). Income is not affected by changes in the fair value of these swaps; however, these swaps effectively convert the hedged portion of fixed-rate debt to variable-rate debt. As a result, interest expense (and related cash outlays for debt service) will increase or decrease with the change in the periodic “reset” rate associated with the respective swap. Typically, the reset rate is an agreed upon index rate published for the first day of the six-month interest calculation period.

	Resulting	Swap FV at	Change in FV of Debt
Scenario	Classification	October 12, 2005	Increase (Decrease)
FV assuming no change in underlying interest rates	Asset (Liability)	$ (16,792)
FV assuming 10% increase in underlying interest rates	Asset (Liability)	(49,742)	$ (32,950)
FV assuming 10% decrease in underlying interest rates	Asset (Liability)	16,157	32,950

Commodity risk hedging program. The prices of natural gas, NGLs and petrochemical products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control. In order to manage the risks associated with natural gas and NGLs, we may enter into commodity financial instruments. The primary purpose of our commodity risk management activities is to hedge our exposure to price risks associated with (i) natural gas purchases, (ii) NGL production and inventories, (iii) related firm commitments, (iv) fluctuations in transportation revenues where the underlying fees are based on natural gas index prices and (v) certain anticipated transactions involving either natural gas or NGLs.

At September 30, 2005 and December 31, 2004, we had a limited number of commodity financial instruments in our portfolio, which primarily consisted of natural gas cash flow and fair value hedges. The fair value of our commodity financial instrument portfolio at September 30, 2005 and December 31, 2004 was an asset of $0.1 million and $0.2 million, respectively. Excluding the reclassification of a $1.4 million gain from accumulated other comprehensive income during the first quarter of 2005 (see discussion below regarding the effect of financial instruments on accumulated other comprehensive income), we recorded nominal amounts of earnings from our commodity financial instruments during the three and nine months ended September 30, 2005 and 2004.

We assess the risk of our commodity financial instrument portfolio using a sensitivity analysis model. The sensitivity analysis applied to this portfolio measures the potential income or loss (i.e., the change in fair value of the portfolio) based upon a hypothetical 10% movement in the underlying quoted market prices of the commodity financial instruments outstanding at the date indicated within the following table. The following table shows the effect of hypothetical price movements on the estimated fair value (“FV”) of this portfolio at October 12, 2005 (dollars in thousands):

		Commodity
	Resulting	Financial Instr.
Scenario	Classification	Portfolio FV
FV assuming no change in underlying commodity prices	Asset (Liability)	$ (277)
FV assuming 10% increase in underlying commodity prices	Asset (Liability)	(1,127)
FV assuming 10% decrease in underlying commodity prices	Asset (Liability)	572

Effect of financial instruments on Accumulated Other Comprehensive Income. The following table summarizes the effect of our cash flow hedging financial instruments on accumulated other comprehensive income since December 31, 2004.

		Interest Rate Fin. Instrs.		Accumulated
			Forward-	Other
	Commodity		Starting	Comprehensive
	Financial	Treasury	Interest	Income
	Instruments	Locks	Rate Swaps	Balance
Balance, December 31, 2004	$ 1,434	$ 4,572	$ 18,548	$ 24,554
Change in fair value of commodity financial instruments	(1,350)			(1,350)
Reclassification of gain on settlement of treasury locks to interest expense		(331)		(331)
Reclassification of gain on settlement of forward-starting swaps to interest expense			(2,687)	(2,687)
Balance, September 30, 2005	$ 84	$ 4,241	$ 15,861	$ 20,186

ITEM 4. CONTROLS AND PROCEDURES.

Our management, with the participation of the CEO and CFO of our general partner, have evaluated the effectiveness of our disclosure controls and procedures, including internal controls over financial reporting. Collectively, these disclosure controls and procedures are designed to provide us with a reasonable assurance that the information required to be disclosed in periodic reports filed with the SEC is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also designed to provide reasonable assurance that such information is accumulated and communicated to our management, including our general partner’s CEO and CFO, as appropriate to allow such persons to make timely decisions regarding required disclosures.

Our management does not expect that our disclosure controls and procedures will prevent all errors and all fraud. The design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Based on the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple errors or mistakes. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events. Therefore, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Our disclosure controls and procedures are designed to provide such reasonable assurances of achieving our desired control objectives, and our CEO and CFO have concluded that our disclosure controls and procedures are effective in achieving that level of reasonable assurance.

Based on their evaluation, the CEO and CFO of our general partner have concluded that our disclosure controls and procedures are effective to ensure that material information relating to our partnership is made known to management on a timely basis. The CEO and CFO noted no material weaknesses in the design or operation of our internal controls over financial reporting that are likely to adversely affect our ability to record, process, summarize and report financial information. Also, they detected no fraud involving management or employees who have a significant role in our internal controls over financial reporting. There have been no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) or in other factors that occurred since the time we

became a public company on August 24, 2005, that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting. As a result of becoming a public company during August 2005, our report regarding the effectiveness of our "internal control over financial reporting" that is required under the SEC's rules under Section 404 of the Sarbanes-Oxley Act of 2002 is not applicable to us in 2005.

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

PART II. OTHER INFORMATION.

ITEM 1. LEGAL PROCEEDINGS.

See Note 16 of the Notes to Unaudited Consolidated Financial Statements for Commitments and Contingencies regarding litigation, which is incorporated herein by reference.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

On April 26, 2005, we filed a registration statement (Registration No. 333-124320) relating to the initial public offering of Enterprise GP Holdings. This registration statement was declared effective by the Securities and Exchange Commission on August 23, 2005. The offering closed on August 29, 2004. Citigroup Global Markets Inc and Lehman Brothers Inc. acted as co-managers for the offering.

On August 29 2005, we sold 14,216,784 common units under this registration statement (including an over-allotment amount of 1,616,784 common units) at an offering price of $28.00 per common unit. Total net proceeds from the sale of these common units was approximately $373 million after deducting applicable underwriting discounts, commissions, structuring fees and other offering expenses of $25.6 million. The net proceeds from this initial public offering were used to reduce debt outstanding under Enterprise GP Holdings' $525 Million Credit Facility.

We sold 2,357,142 common units to affiliates of EPCO that are included in the 14,216,784 common units issued. Our related party sales include:

•

1,821,428 common units sold to a partnership affiliated with, and established for the benefit of certain employees of, EPCO;

•

357,143 common units to other affiliates of EPCO and Dan L. Duncan; and

•

178,571 common units sold to O.S. Andras, a director of Enterprise Products GP.

The underwriters did not receive any discount or commission on the 2,178,571 units sold to entities controlled by Dan L. Duncan or on the 178,571 units offered to O.S. Andras, a director of Enterprise Products GP.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

None.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

None.

ITEM 5. OTHER INFORMATION.

None.

ITEM 6. EXHIBITS.

Exhibit No.	Exhibit*
1.1	Underwriting Agreement, dated August 23, 2005, by and among Enterprise GP Holdings L.P., EPE Holdings, LLC, and the underwriters named therein (incorporated by reference to Exhibit 1.1 of the Current Report on Form 8-K filed September 1, 2005).
1.2	Unit Purchase Agreement dated August 23, 2005, by and between Enterprise GP Holdings L.P. and EPE Unit L.P. (incorporated by reference to Exhibit 1.2 of the Current Report on Form 8-K filed September 1, 2005).
2.1	Purchase and Sale Agreement between Coral Energy, LLC and Enterprise Products Operating L.P. dated September 22, 2000 (incorporated by reference to Exhibit 10.1 to Enterprise Products Partners' Form 8-K filed September 26, 2000).
2.2	Purchase and Sale Agreement dated January 16, 2002 by and between Diamond-Koch, L.P. and Diamond-Koch III, L.P. and Enterprise Products Texas Operating L.P. (incorporated by reference to Exhibit 10.1 to Enterprise Products Partners' Form 8-K filed February 8, 2002.)
2.3	Purchase and Sale Agreement dated January 31, 2002 by and between D-K Diamond-Koch, L.L.C., Diamond-Koch, L.P. and Diamond-Koch III, L.P. as Sellers and Enterprise Products Operating L.P. as Buyer (incorporated by reference to Exhibit 10.2 to Enterprise Products Partners' Form 8-K filed February 8, 2002).
2.4	Purchase Agreement by and between E-Birchtree, LLC and Enterprise Products Operating L.P. dated July 31, 2002 (incorporated by reference to Exhibit 2.2 to Enterprise Products Partners' Form 8-K filed August 12, 2002).
2.5	Purchase Agreement by and between E-Birchtree, LLC and E-Cypress, LLC dated July 31, 2002 (incorporated by reference to Exhibit 2.1 to Enterprise Products Partners' Form 8-K filed August 12, 2002).
2.6	Merger Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Enterprise Products Partners' Form 8-K filed December 15, 2003).
2.7	Amendment No. 1 to Merger Agreement, dated as of August 31, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Enterprise Products Partners' Form 8-K filed September 7, 2004).
2.8	Parent Company Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.2 to Enterprise Products Partners' Form 8-K filed December 15, 2003).
2.9	Amendment No. 1 to Parent Company Agreement, dated as of April 19, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.1 to Enterprise Products Partners' Form 8-K filed April 21, 2004).
2.10	Second Amended and Restated Limited Liability Company Agreement of GulfTerra Energy Company, L.L.C., adopted by GulfTerra GP Holding Company, a Delaware corporation, and Enterprise Products GTM, LLC, a Delaware limited liability company, as of December 15, 2003, (incorporated by reference to Exhibit 2.3 to Enterprise Products Partners' Form 8-K filed December 15, 2003).
2.11	Amendment No. 1 to Second Amended and Restated Limited Liability Company Agreement of GulfTerra Energy Company, L.L.C. adopted by Enterprise Products GTM, LLC as of September 30, 2004 (incorporated by reference to Exhibit 2.11 to Enterprise Products Partners' Registration Statement on Form S-4 filed December 27, 2004).
2.12	Purchase and Sale Agreement (Gas Plants), dated as of December 15, 2003, by and between El Paso Corporation, El Paso Field Services Management, Inc., El Paso Transmission, L.L.C., El Paso Field Services Holding Company and Enterprise Products Operating L.P. (incorporated by

	reference to Exhibit 2.4 to Enterprise Products Partners' Form 8-K filed December 15, 2003).
3.1#	Amended and Restated Agreement of Limited Partnership of Enterprise GP Holdings L.P., dated as of August 29, 2005.
3.2	Amended and Restated Limited Liability Company Agreement of EPE Holdings, LLC, dated as of August 29, 2005 (incorporated by reference to Exhibit 3.2 of the Current Report on Form 8-K filed September 1, 2005).
3.3	Fifth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated effective as of August 8, 2005 (incorporated by reference to Exhibit 3.1 to Enterprise Products Partners' Form 8-K filed August 10, 2005).
3.4	Third Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC, dated as of August 29, 2005 (incorporated by reference to Exhibit 3.1 to Enterprise Products Partners' Form 8-K filed September 1, 2005).
3.5	Amended and Restated Agreement of Limited Partnership of Enterprise Products Operating L.P. dated as of July 31, 1998 (restated to include all agreements through December 10, 2003)(incorporated by reference to Exhibit 3.1 to Enterprise Products Partners' Form 8-K filed July 1, 2005).
3.6	Certificate of Incorporation of Enterprise Products OLPGP, Inc., dated December 3, 2003 (incorporated by reference to Exhibit 3.5 to Enterprise Products Partners' Form S-4 filed December 27, 2004).
3.7	Bylaws of Enterprise Products OLPGP, Inc., dated December 8, 2003 (incorporated by reference to Exhibit 3.6 to Enterprise Products Partners' Form S-4 filed December 27, 2004).
3.8	Certificate of Limited Partnership of Enterprise GP Holdings L.P., dated April 18, 2005 (incorporated by reference to Exhibit 3.1 to Amendment No. 2 to Form S-1 Registration Statement, Reg. No. 333-124320, filed July 21, 2005).
3.9	Certificate of Formation of EPE Holdings LLC, dated April 18, 2005 (incorporated by reference to Exhibit 3.3 to Amendment No. 2 to Form S-1 Registration Statement, Reg. No. 333-124320, filed July 21, 2005).
4.1	Indenture dated as of March 15, 2000, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and First Union National Bank, as Trustee (incorporated by reference to Exhibit 4.1 to Enterprise Products Partners' Form 8-K filed March 10, 2000).
4.2	First Supplemental Indenture dated as of January 22, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Enterprise Products Partners' Registration Statement on Form S-4, Reg. No. 333-102776, filed January 28, 2003).
4.3	Global Note representing $350 million principal amount of 6.375% Series B Senior Notes due 2013 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Enterprise Products Partners' Registration Statement on Form S-4, Reg. No. 333-102776, filed January 28, 2003).
4.4	Second Supplemental Indenture dated as of February 14, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Enterprise Products Partners' Form 10-K filed March 31, 2003).
4.5	Global Note representing $500 million principal amount of 6.875% Series B Senior Notes due 2033 with attached Guarantee (incorporated by reference to Exhibit 4.8 to Enterprise Products Partners' Form 10-K filed March 31, 2003).
4.6	Global Notes representing $450 million principal amount of 7.50% Senior Notes due 2011 (incorporated by reference to Exhibit 4.1 to Enterprise Products Partners' Form 8-K filed January 25, 2001).
4.7	Form of Unit certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 3 to Form S-1 Registration Statement, Reg. No. 333-124320, filed August 11, 2005).
4.8	Contribution Agreement dated September 17, 1999 (incorporated by reference to Exhibit "B" to Schedule 13D filed September 27, 1999 by Tejas Energy, LLC).
4.9	Registration Rights Agreement dated September 17, 1999 (incorporated by reference to Exhibit "E" to Schedule 13D filed September 27, 1999 by Tejas Energy, LLC).
4.10	Unitholder Rights Agreement dated September 17, 1999 (incorporated by reference to Exhibit "C" to Schedule 13D filed September 27, 1999 by Tejas Energy, LLC).

4.11	Amendment No. 1, dated September 12, 2003, to Unitholder Rights Agreement dated September 17, 1999 (incorporated by reference to Exhibit 4.1 to Enterprise Products Partners' Form 8-K filed September 15, 2003).
4.12	Agreement dated as of March 4, 2004 among Enterprise Products Partners L.P., Shell US Gas & Power LLC and Kayne Anderson MLP Investment Company (incorporated by reference to Exhibit 4.31 to Enterprise Products Partners' Form S-3 Registration Statement, Reg. No. 333-123150, filed March 4, 2004).
4.13	$750 Million Multi-Year Revolving Credit Agreement dated as of August 25, 2004, among Enterprise Products Operating L.P., the Lenders party thereto, Wachovia Bank, National Association, as Administrative Agent, Citibank, N.A. and JPMorgan Chase Bank, as Co-Syndication Agents and Mizuho Corporate Bank, Ltd., SunTrust Bank and The Bank of Nova Scotia, as Co-Documentation Agents (incorporated by reference to Exhibit 4.1 to Enterprise Products Partners' Form 8-K filed on August 30, 2004).
4.14	Guaranty Agreement dated as of August 25, 2004, by Enterprise Products Partners L.P. in favor of Wachovia Bank, National Association, as Administrative Agent for the several lenders that are or become parties to the Credit Agreement included as Exhibit 4.1, above (incorporated by reference to Exhibit 4.2 to Enterprise Products Partners' Form 8-K filed on August 30, 2004).
4.15	First Amendment dated October 5, 2005, to Multi-Year Revolving Credit Agreement dated as of August 25, 2004, among Enterprise Products Operating L.P., the Lenders party thereto, Wachovia Bank, National Association, as Administrative Agent, CitiBank, N.A. and JPMorgan Chase Bank, as CO-Syndication Agents, and Mizuho Corporate Bank, Ltd., SunTrust Bank and The Bank of Nova Scotia, as Co-Documentation Agents (incorporated by reference to Exhibit 4.3 to Enterprise Products Partners' Form 8-K filed on October 7, 2005).
4.16	$2.25 Billion 364-Day Revolving Credit Agreement dated as of August 25, 2004, among Enterprise Products Operating L.P., the Lenders party thereto, Wachovia Bank, National Association, as Administrative Agent, Citicorp North America, Inc. and Lehman Commercial Paper Inc., as Co-Syndication Agents, JPMorgan Chase Bank, UBS Loan Finance LLC and Morgan Stanley Senior Funding, Inc., as Co-Documentation Agents, Wachovia Capital Markets, LLC, Citigroup Global Markets Inc. and Lehman Brothers Inc., as Joint Lead Arrangers and Joint Book Runners (incorporated by reference to Exhibit 4.3 to Enterprise Products Partners' Form 8-K filed on August 30, 2004).
4.17	Guaranty Agreement dated as of August 25, 2004, by Enterprise Products Partners L.P. in favor of Wachovia Bank, National Association, as Administrative Agent for the several lenders that are or become parties to the Credit Agreement included as Exhibit 4.3, above (incorporated by reference to Exhibit 4.4 to Enterprise Products Partners' Form 8-K filed on August 30, 2004).
4.18	Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Enterprise Products Partners' Form 8-K filed on October 6, 2004).
4.19	First Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Enterprise Products Partners' Form 8-K filed on October 6, 2004).
4.20	Second Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Enterprise Products Partners' Form 8-K filed on October 6, 2004).
4.21	Third Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.4 to Enterprise Products Partners' Form 8-K filed on October 6, 2004).
4.22	Fourth Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.5 to Enterprise Products Partners' Form 8-K filed on October 6, 2004).
4.23	Global Note representing $500 million principal amount of 4.000% Series B Senior Notes due

	2007 with attached Guarantee (incorporated by reference to Exhibit 4.14 to Enterprise Products Partners' Form S-3 Registration Statement Reg. No. 333-123150 filed on March 4, 2004).
4.24	Global Note representing $500 million principal amount of 5.600% Series B Senior Notes due 2014 with attached Guarantee (incorporated by reference to Exhibit 4.17 to Enterprise Products Partners' Form S-3 Registration Statement Reg. No. 333-123150 filed on March 4, 2004).
4.25	Global Note representing $150 million principal amount of 5.600% Series B Senior Notes due 2014 with attached Guarantee (incorporated by reference to Exhibit 4.18 to Enterprise Products Partners' Form S-3 Registration Statement Reg. No. 333-123150 filed on March 4, 2004).
4.26	Global Note representing $350 million principal amount of 6.650% Series B Senior Notes due 2034 with attached Guarantee (incorporated by reference to Exhibit 4.19 to Enterprise Products Partners' Form S-3 Registration Statement Reg. No. 333-123150 filed on March 4, 2004).
4.27	Global Note representing $500 million principal amount of 4.625% Series B Senior Notes due 2009 with attached Guarantee (incorporated by reference to Exhibit 4.27 to Enterprise Products Partners' Form 10-K for the year ended December 31, 2004 filed on March 15, 2005).
4.28	Registration Rights Agreement dated as of October 4, 2004, among Enterprise Products Operating L.P., Enterprise Products Partners L.P. and the Initial Purchasers named therein (incorporated by reference to Exhibit 4.17 to Enterprise Products Partners' Form 8-K filed on October 6, 2004).
4.29	Fifth Supplemental Indenture dated as of March 2, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Enterprise Products Partners' Form 8-K filed on March 3, 2005).
4.30	Sixth Supplemental Indenture dated as of March 2, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Enterprise Products Partners' Form 8-K filed on March 3, 2005).
4.31	Global Note representing $250,000,000 principal amount of 5.00% Series B Senior Notes due 2015 with attached Guarantee (incorporated by reference to Exhibit 4.31 to Enterprise Products Partners' Form 10-Q for the quarter ended September 30, 2005 filed on November 4, 2005).
4.32	Global Note representing $250,000,000 principal amount of 5.75% Series B Senior Notes due 2035 with attached Guarantee (incorporated by reference to Exhibit 4.32 to Enterprise Products Partners' Form 10-Q for the quarter ended September 30, 2005 filed on November 4, 2005).
4.33	Registration Rights Agreement dated as of March 2, 2005, among Enterprise Products Partners, L.P., Enterprise Products Operating L.P. and the Initial Purchasers named therein (incorporated by reference to Exhibit 4.6 to Enterprise Products Partners' Form 8-K filed on March 3, 2005).
4.34	Assumption Agreement dated as of September 30, 2004 between Enterprise Products Partners L.P. and GulfTerra Energy Partners, L.P. relating to the assumption by Enterprise of GulfTerra's obligations under the GulfTerra Series F2 Convertible Units (incorporated by reference to Exhibit 4.4 to Enterprise Products Partners' Form 8-K/A-1 filed on October 5, 2004).
4.35	Statement of Rights, Privileges and Limitations of Series F Convertible Units, included as Annex A to Third Amendment to the Second Amended and Restated Agreement of Limited Partnership of GulfTerra Energy Partners, L.P., dated May 16, 2003 (incorporated by reference to Exhibit 3.B.3 to Current Report on Form 8-K of GulfTerra Energy Partners, L.P., file no. 001-11680, filed with the Commission on May 19, 2003).
4.36	Unitholder Agreement between GulfTerra Energy Partners, L.P. and Fletcher International, Inc. dated May 16, 2003 (incorporated by reference to Exhibit 4.L to Current Report on Form 8-K of GulfTerra Energy Partners, L.P., file no. 001-11680, filed with the Commission on May 19, 2003).
4.37	Indenture dated as of May 17, 2001 among GulfTerra Energy Partners, L.P., GulfTerra Energy Finance Corporation, the Subsidiary Guarantors named therein and the Chase Manhattan Bank, as Trustee (filed as Exhibit 4.1 to GulfTerra’s Registration Statement on Form S-4 filed June 25, 2001, Registration Nos. 333-63800 through 333-63800-20); First Supplemental Indenture dated as of April 18, 2002 (filed as Exhibit 4.E.1 to GulfTerra’s 2002 First Quarter Form 10-Q); Second Supplemental Indenture dated as of April 18, 2002 (filed as Exhibit 4.E.2

	to GulfTerra’s 2002 First Quarter Form 10-Q); Third Supplemental Indenture dated as of October 10, 2002 (filed as Exhibit 4.E.3 to GulfTerra’s 2002 Third Quarter Form 10-Q); Fourth Supplemental Indenture dated as of November 27, 2002 (filed as Exhibit 4.E.1 to GulfTerra’s Current Report on Form 8-K dated March 19, 2003); Fifth Supplemental Indenture dated as of January 1, 2003 (filed as Exhibit 4.E.2 to GulfTerra’s Current Report on Form 8-K dated March 19, 2003); Sixth Supplemental Indenture dated as of June 20, 2003 (filed as Exhibit 4.E.1 to GulfTerra’s 2003 Second Quarter Form 10-Q, file no. 001-11680).
4.38	Indenture dated as of May 17, 2001 among GulfTerra Energy Partners, L.P., GulfTerra Energy Finance Corporation, the Subsidiary Guarantors named therein and the Chase Manhattan Bank, as Trustee (filed as Exhibit 4.1 to GulfTerra’s Registration Statement on Form S-4 filed June 25, 2001, Registration Nos. 333-63800 through 333-63800-20); First Supplemental Indenture dated as of April 18, 2002 (filed as Exhibit 4.E.1 to GulfTerra’s 2002 First Quarter Form 10-Q); Second Supplemental Indenture dated as of April 18, 2002 (filed as Exhibit 4.E.2 to GulfTerra’s 2002 First Quarter Form 10-Q); Third Supplemental Indenture dated as of October 10, 2002 (filed as Exhibit 4.E.3 to GulfTerra’s 2002 Third Quarter Form 10-Q); Fourth Supplemental Indenture dated as of November 27, 2002 (filed as Exhibit 4.E.1 to GulfTerra’s Current Report on Form 8-K dated March 19, 2003); Fifth Supplemental Indenture dated as of January 1, 2003 (filed as Exhibit 4.E.2 to GulfTerra’s Current Report on Form 8-K dated March 19, 2003); Sixth Supplemental Indenture dated as of June 20, 2003 (filed as Exhibit 4.E.1 to GulfTerra’s 2003 Second Quarter Form 10-Q, file no. 001-11680).
4.38	Seventh Supplemental Indenture dated as of August 17, 2004 (filed as Exhibit 4.E.1 to GulfTerra’s Current Report on Form 8-K filed on August 19, 2004, file no. 001-11680).
4.39	Indenture dated as of November 27, 2002 by and among GulfTerra Energy Partners, L.P., GulfTerra Energy Finance Corporation, the Subsidiary Guarantors named therein and JPMorgan Chase Bank, as Trustee (filed as Exhibit 4.1 to GulfTerra’s Current Report of Form 8-K dated December 11, 2002); First Supplemental Indenture dated as of January 1, 2003 (filed as Exhibit 4.1.1 to GulfTerra’s Current Report on Form 8-K dated March 19, 2003); Second Supplemental Indenture dated as of June 20, 2003 (filed as Exhibit 4.1.1 to GulfTerra’s 2003 Second Quarter Form 10-Q, file no. 001-11680).
4.40	Third Supplemental Indenture dated as of August 17, 2004 (filed as Exhibit 4.1.1 to GulfTerra’s Current Report on Form 8-K filed on August 19, 2004, file no. 001-11680).
4.41	Indenture dated as of March 24, 2003 by and among GulfTerra Energy Partners, L.P., GulfTerra Energy Finance Corporation, the Subsidiary Guarantors named therein and JPMorgan Chase Bank, as Trustee dated as of March 24, 2003 (filed as Exhibit 4.K to GulfTerra’s Quarterly Report on Form 10-Q dated May 15, 2003); First Supplemental Indenture dated as of June 30, 2003 (filed as Exhibit 4.K.1 to GulfTerra’s 2003 Second Quarter Form 10-Q, file no. 001-11680).
4.42	Second Supplemental Indenture dated as of August 17, 2004 (filed as Exhibit 4.K.1 to GulfTerra’s Current Report on Form 8-K filed on August 19, 2004, file no. 001-11680).
4.43	Indenture dated as of July 3, 2003, by and among GulfTerra Energy Partners, L.P., GulfTerra Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as Trustee (Filed as Exhibit 4.L to GulfTerra’s 2003 Second Quarter Form 10-Q, file no. 001-11680).
4.44	First Supplemental Indenture dated as of August 17, 2004 (filed as Exhibit 4.K.1 to GulfTerra’s Current Report on Form 8-K filed on August 19, 2004, file no. 001-11680).
4.45	Amended and Restated Credit Agreement dated as of June 29, 2005, among Cameron Highway Oil Pipeline Company, the Lenders party thereto, and SunTrust Bank, as Administrative Agent and Collateral Agent (incorporated by reference to Exhibit 4.1 to Enterprise Products Partners' Form 8-K filed on July 1, 2005).
4.46	Credit Agreement, dated as of August 29, 2005, by and among Enterprise GP Holdings L.P., the lenders party thereto, Lehman Commercial Paper Inc., as Co-Administrative Agent, Citicorp North America, Inc., as Co-Administrative Agent and Paying Agent, The Bank of Nova Scotia, as Syndication Agent, and SunTrust Bank, as Documentation Agent (incorporated by reference to Exhibit 4.1 of the Current Report on Form 8-K filed September 1, 2005).
4.47	Seventh Supplemental Indenture dated as of June 1, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.46 to Enterprise Products Partners' Form 10-Q for the quarter ended September 30, 2005, filed November 4, 2005).
4.48	Global Note representing $500,000,000 principal amount of 4.95% Senior Notes due 2010 with attached Guarantee (incorporated by reference to Exhibit 4.47 to Enterprise Products Partners' Form 10-Q for the quarter ended September 30, 2005 filed November 4, 2005).
10.1	Transportation Contract between Enterprise Products Operating L.P. and Enterprise Transportation Company dated June 1, 1998 (incorporated by reference to Exhibit 10.3 to Enterprise Products Partners' Registration Statement Form S-1/A filed July 8, 1998).
10.2	Partnership Agreement among Sun BEF, Inc., Liquid Energy Fuels Corporation and Enterprise Products Company dated May 1, 1992 (incorporated by reference to Exhibit 10.5 to Enterprise Products Partners' Registration Statement on Form S-1 filed May 13, 1998).
10.3	Propylene Facility and Pipeline Agreement between Enterprise Petrochemical Company and Hercules Incorporated dated December 13, 1978 (incorporated by reference to Exhibit 10.9 to Enterprise Products Partners' Registration Statement on Form S-l filed May 13, 1998).
10.4	Restated Operating Agreement for the Mont Belvieu Fractionation Facilities Chambers County, Texas among Enterprise Products Company, Texaco Producing Inc., El Paso Hydrocarbons Company and Champlin Petroleum Company dated July 17, 1985 (incorporated by reference to Exhibit 10.10 to Enterprise Products Partners' Registration Statement on Form S-l/A filed July 8,

	1998).
10.5	Amendment to Propylene Facility and Pipeline Agreement and Propylene Sales Agreement between HIMONT U.S.A., Inc. and Enterprise Products Company dated January 1, 1993 (incorporated by reference to Exhibit 10.12 to Enterprise Products Partners' Registration Statement on Form S-l/A filed July 8, 1998).
10.6	Amendment to Propylene Facility and Pipeline Agreement and Propylene Sales Agreement between HIMONT U.S.A., Inc. and Enterprise Products Company dated January 1, 1995 (incorporated by reference to Exhibit 10.13 to Enterprise Products Partners' Registration Statement on Form S-l/A filed July 8, 1998).
10.7	Seventh Amendment to Conveyance of Gas Processing Rights, dated as of April 1, 2004 among Enterprise Gas Processing, LLC, Shell Oil Company, Shell Exploration & Production Company, Shell Offshore Inc., Shell Consolidated Energy Resources Inc., Shell Land & Energy Company, Shell Frontier Oil & Gas Inc. and Shell Gulf of Mexico Inc. (incorporated by reference to Exhibit 10.1 to Enterprise Products Partners' Form 8-K filed April 26, 2004).
10.8 ***	Enterprise Products 1998 Long-Term Incentive Plan, amended and restated as of April 8, 2004 (incorporated by reference to Appendix B to Enterprise Products Partners' Notice of Written Consent dated April 22, 2004, filed April 22, 2004).
10.9 ***	Form of Option Grant Award under 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.3 to Enterprise Products Partners' Form S-8 Registration Statement, Reg. No. 333-115633, filed May 19, 2004).
10.10***	Form of Restricted Unit Grant under the Enterprise Products 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.3 to Enterprise Products Partners' Form S-8 Registration Statement, Reg. No. 333-115633, filed May 19, 2004).
10.11***	1998 Omnibus Compensation Plan of GulfTerra Energy Partners, L.P., Amended and Restated as of January 1, 1999 (incorporated by reference to Exhibit 10.9 to Form 10-K for the year ended December 31, 1998 of GulfTerra Energy Partners, L.P., file no. 001-11680); Amendment No. 1, dated as of December 1, 1999 (incorporated by reference to Exhibit 10.8.1 to Form 10-Q for the quarter ended June 30, 2000 of GulfTerra Energy Partners, L.P., file no. 001-116800); Amendment No. 2 dated as of May 15, 2003 (incorporated by reference to Exhibit 10.M.1 to Form 10-Q for the quarter ended June 30, 2003 of GulfTerra Energy Partners, L.P., file no. 001-11680).
10.12	Third Amended and Restated Administrative Services Agreement by and among EPCO, Inc., Enterprise Products Partners L.P., Enterprise Products Operating L.P., Enterprise Products GP, LLC, Enterprise Products OLPGP, Inc., Enterprise GP Holdings L.P., EPE Holdings, LLC, TEPPCO Partners, L.P., Texas Eastern Products Pipeline Company, LLC, TE Products Pipeline Company, Limited Partnership, TEPPCO Midstream Companies, L.P., TCTM, L.P. and TEPPCO GP, Inc. dated August 15, 2005, but effective as of February 24, 2005 (incorporated by reference to Exhibit 10.1 to Enterprise Products Partners' Form 8-K filed August 22, 2005).
10.13	Contribution, /conveyance and Assumption Agreement, dated as of August 29, 2005, by and among Enterprise GP Holdings L.P., EPE Holdings, LLC, Dan Duncan, LLC, Duncan Family Interests, Inc., DFI GP Holdings L.P. and DFI Holdings, LLC (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K filed September 1, 2005).
10.14***	EPE Unit L.P. Agreement of Limited Partnership (incorporated by reference to Exhibit 10.2 of the Current Report on Form 8-K filed September 1, 2005).
10.15***	Enterprise Products Company 2005 EPE Long Term Incentive Plan (incorporated by reference to Exhibit 10.28 to Amendment No. 3 to Form S-1 Registration Statement, Reg. No. 333-124320, filed August 11, 2005).
10.16***	Form of Restricted Unit Grant under the Enterprise Products Company 2005 EPE Long Term Incentive Plan (incorporated by reference to Exhibit 10.29 to Amendment No. 3 to Form S-1 Registration Statement, Reg. No. 333-124320, filed August 11, 2005).
10.17***	Form of Phantom Unit Grant under the Enterprise Products company 2005 EPE Long Term Incentive Plan (incorporated by reference to Exhibit 10.30 to Amendment No. 3 to Form S-1 Registration Statement, Reg. No. 333-124320, filed August 11, 2005).
10.18	$370,000,000 Note of Enterprise Products GP, LLC, payable to Dan Duncan LLC (incorporated by reference to Exhibit 10.33 to Amendment No. 3 to Form S-1 Registration Statement, Reg. No. 333-124320 filed August 11, 2005).
10.19#	Promissory Note assumed by Enterprise GP Holdings L.P. in the amount of $160,023,385.34,

	payable to EPCO, Inc.
18.1	Letter regarding Change in Accounting Principles dated May 4, 2004 (incorporated by reference to Exhibit 18.1 to Enterprise Products Partners' Form 10-Q filed May 10, 2004).
31.1#	Sarbanes-Oxley Section 302 certification of Michael A. Creel for Enterprise GP Holdings L.P. for the September 30, 2005 quarterly report on Form 10-Q.
31.2#	Sarbanes-Oxley Section 302 certification of W. Randall Fowler for Enterprise GP Holdings L.P. for the September 30, 2005 quarterly report on Form 10-Q.
32.1#	Section 1350 certification of Michael A. Creel for the September 30, 2005 quarterly report on Form 10-Q.
32.2#	Section 1350 certification of W. Randall Fowler for the September 30, 2005 quarterly report on Form 10-Q.

*	With respect to any exhibits incorporated by reference to any Exchange Act filings, the Commission file number for Enterprise GP Holdings L.P. is 1-32610 and the Commission file number for Enterprise Products Partners L.P. is 1-14323.

***	Identifies management contract and compensatory plan arrangements.
#	Filed with this report.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this quarterly report on Form 10-Q to be signed on its behalf by the undersigned thereunto duly authorized, in the City of Houston, State of Texas on November 8, 2005.

	ENTERPRISE GP HOLDINGS L.P.
	(A Delaware Limited Partnership)

	By:	EPE Holdings, LLC,
		as General Partner

By:	___/s/ Michael J. Knesek_____________________
		Name:	Michael J. Knesek
		Title:	Senior Vice President, Controller
			and Principal Accounting Officer
			of the General Partner

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Enterprise GP Inactive 10-Q2005 Q3 Quarterly report

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