UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 8-K

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

UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549

FORM 8-K

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

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

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

Delaware	1-14323	76-0568219
(State or Other Jurisdiction of Incorporation or Organization)	(Commission File Number)	(I.R.S. Employer Identification No.)

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

EXHIBIT 99.1

Enterprise Products GP, LLC

Unaudited Condensed Consolidated Balance Sheet at June 30, 2005

ENTERPRISE PRODUCTS GP, LLC

TABLE OF CONTENTS

Unaudited Condensed Consolidated Balance Sheet at June 30, 2005

Notes to Unaudited Condensed Consolidated Balance Sheet

General

Recently issued accounting standards

Business combinations

Inventories

Property, plant and equipment

Investments in and advances to unconsolidated affiliates

Intangible assets and goodwill

Related party transactions

Minority interest

Capital structure

Debt obligations

Financial instruments

Segment information

Condensed financial information of Operating Partnership

Commitments and contingencies

Subsequent events

ENTERPRISE PRODUCTS GP, LLC

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET

AT JUNE 30, 2005

(Dollars in thousands)

ASSETS
Current assets
	Cash and cash equivalents			$ 33,131
	Restricted cash			13,027
	Accounts and notes receivable - trade, net of allowance for doubtful
		accounts of $24,083		1,022,179
	Accounts receivable - related parties			202
	Inventories			365,803
	Prepaid and other current assets			109,583
			Total current assets	1,543,925
Property, plant and equipment, net				8,182,589
Investments in and advances to unconsolidated affiliates				479,146
Intangible assets, net of accumulated amortization of $119,682				956,956
Goodwill				483,377
Deferred tax asset				7,737
Long-term receivables				14,815
Other assets				61,510
			Total assets	$ 11,730,055

LIABILITIES AND MEMBERS’ EQUITY
Current liabilities
	Current maturities of debt			$ 18,686
	Accounts payable - trade			113,541
	Accounts payable - related parties			15,941
	Accrued gas payables			971,675
	Accrued expenses			31,295
	Accrued interest			72,446
	Other current liabilities			114,162
			Total current liabilities	1,337,746
Long-term debt				4,929,452
Other long-term liabilities				58,935
Minority interest				5,234,203
Commitments and contingencies
Members’ equity				169,719
			Total liabilities and members’ equity	$ 11,730,055

See Notes to Unaudited Condensed Consolidated Balance Sheet.

ENTERPRISE PRODUCTS GP, LLC

NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET

1. GENERAL

ENTERPRISE PRODUCTS GP, LLC (“EPGP”) is a Delaware limited liability company formed in May 1998 that is the general partner of Enterprise Products Partners L.P. EPGP’s primary business purpose is to manage the affairs and operations of Enterprise Products Partners L.P. and its subsidiaries (collectively referred to as “EPD”). EPD is a publicly traded Delaware limited partnership listed on the New York Stock Exchange (“NYSE”) under symbol “EPD.” EPD conducts substantially all of its business through its wholly owned subsidiary, Enterprise Products Operating L.P. (the “Operating Partnership”). EPD and the Operating Partnership were formed to acquire, own and operate the natural gas liquids (“NGL”) business of EPCO, Inc. (“EPCO”).

Unless the context requires otherwise, references to “we”, “us”, “our”, “EPGP” or “the Company” within these notes shall mean EPGP and its consolidated subsidiaries, which include EPD and its subsidiaries. References to “Shell” shall mean Shell Oil Company, its subsidiaries and affiliates. References to “El Paso” shall mean El Paso Corporation and its affiliates.

At June 30, 2005, Duncan Family Interests, Inc. (“DFI”) owned 85.6%, Dan Duncan, LLC (“DDC”) owned 4.5% and DFI GP Holdings LP (“DFI GP”) owned 9.9% of the membership interests of EPGP. DFI, DDC and DFI GP are collectively referred to as the “Members.” EPCO is the ultimate parent of DFI and an affiliate of DDC and DFI GP. In January 2005, DFI GP purchased El Paso’s 9.9% membership interest in us. See Note10 for additional information regarding this event.

In the opinion of the EPGP, the accompanying unaudited condensed consolidated balance sheet includes all adjustments consisting of normal recurring accruals necessary for a fair presentation. Although we believe the disclosures are adequate to make the information presented in the unaudited balance sheet 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"). EPGP’s unaudited June 30, 2005 balance sheet should be read in conjunction with its audited December 31, 2004 balance sheet filed on EPD’s Form 8-K (Commission File No. 1-14323) on March 31, 2005. In addition, this financial information should be read in conjunction with EPD’s Form 10-K for the year ended December 31, 2004 and its Form 10-Q for the three and six months ended June 30, 2005 (Commission File No. 1-14323).

Dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars, unless otherwise indicated.

We own a 2% general partner interest in EPD, which conducts substantially all of our business. We have no independent operations and no material assets outside those of EPD. The number of reconciling items between our consolidated balance sheet and that of EPD are few. The most significant is that relating to minority interest in our net assets by the limited partners of EPD and the elimination of our investment in EPD with our underlying partner’s capital account in EPD. See Note 9 for additional details of minority interest in our consolidated subsidiaries.

As a result of DFI acquiring Shell’s 30% membership interest in EPGP on September 12, 2003, the financial statements of EPD were consolidated with those of EPGP beginning in September 2003. This accounting consolidation is required because Shell’s minority interest rights in EPGP (which gave them significant participating rights) were terminated as a result of the purchase. This fact, along with DFI’s indirect control of EPD through its common unit holdings, gives EPGP the ability to exercise control over EPD. All significant intercompany accounts and transactions have been eliminated in consolidation.

Dixie Pipeline Company ("Dixie") employee benefit plans

During the first quarter of 2005, we acquired additional ownership interests in 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 June 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 estimate could change due to this recent transaction and the 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.

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.

2. RECENTLY ISSUED 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 APB 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 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 did not have any 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 studying the effects of FIN 47 on our accounting policy for 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") 04-5, "Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights." In June 2005, the EITF reached consensus in EITF 04-5 to provide guidance on how general partners in a limited partnership should determine whether they control a limited partnership and therefore should consolidate it. The EITF agreed that the presumption of general partner control would be overcome only when the limited partners have either of two types of rights. The first type, referred to as kick-out rights, is the right to dissolve or liquidate the partnership or otherwise remove the general partner without cause. The second type, referred to as participating rights, is the right to effectively participate in significant decisions made in the ordinary course of the partnership’s business. The kick-out rights and the participating rights must be substantive in order to overcome the presumption of general partner control. The consensus is effective for general partners of all new limited partnerships formed and for existing limited partnerships for which the partnership agreements are modified subsequent to the date of FASB ratification (June 29, 2005). The guidance in this EITF is effective for existing partnerships no later than the beginning of the first reporting period in fiscal years beginning after December 15, 2005. We are currently evaluating what impact this EITF will have on our financial statements; however, we do not currently believe that the adoption of this EITF will have a material effect on our financial position, results of operations or cash flows.

3. BUSINESS COMBINATIONS

As summarized below, we recorded purchase accounting adjustments related to the GulfTerra Merger and completed several smaller acquisitions during the first six months of 2005. All such purchase price allocations are preliminary.

GulfTerra Merger purchase price and purchase price allocation adjustments. During the first six months of 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.

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 purchase price allocations related to the GulfTerra Merger remain preliminary and could change due to the refinement of our estimates, including the estimated recovery of

expenditures resulting from damages to certain offshore operations due to the effects of Hurricane Ivan, a Category 3 hurricane which struck the U.S. Gulf Coast in September 2004 prior 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 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 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 natural gas liquid ("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 additional interest in Belle Rose NGL Pipeline LLC (“Belle Rose”) in June 2005. We purchased an approximate 41.7% interest in Belle Rose in June 2005 for approximately $4.5 million in cash. As a result of this acquisition, our 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 preliminary purchase price for 2005 business combinations and

other purchase accounting adjustments

The acquisitions and post-closing 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 &
				Springs	Dixie	Seminole	GulfTerra	Belle Rose	Other	Total
Purchase price allocation:
	Assets acquired in business combination:
		Current assets		$ 354	$ (476)		$ 6,005	$ 562	$ (3,095)	$ 3,350
		Property, plant and equipment, net		41,572	91,402	$ 9,390		17,878	3,090	163,332
		Investments in and advances to
		unconsolidated affiliates (1)			(36,253)			(10,017)		(46,270)
		Intangible assets		19,095					1,009	20,104
		Other assets			32,023		(3,694)			28,329
			Total assets acquired	61,021	86,696	9,390	2,311	8,423	1,004	168,845
	Liabilities assumed in business combination:
		Current liabilities			(2,758)		338	(52)		(2,472)
		Long-term debt			(9,982)					(9,982)
		Other long-term liabilities			(6,535)					(6,535)
		Minority interest			(4,563)	15,610		(4,007)		7,040
			Total liabilities assumed		(23,838)	15,610	338	(4,059)		(11,949)
			Total assets acquired less liabilities assumed	61,021	62,858	25,000	2,649	4,364	1,004	156,896
			Total consideration given	74,854	68,608	25,000	7,028	4,364	1,225	181,079
	Goodwill			$ 13,833	$ 5,750	$ -	$ 4,379	$ -	$ 221	$ 24,183

(1) Represents carrying value of our investment prior to consolidation.

The purchase price allocations shown in the preceding table are preliminary. Enterprise has engaged an independent third-party business valuation expert to assess the fair values of the tangible and intangible assets of Dixie, Belle Rose, and those acquired in the Indian Springs acquisition. 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 June 30, 2005:

Working inventory		$ 254,012
Forward-sales inventory		111,791
Inventory		$ 365,803

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.

5. PROPERTY, PLANT AND EQUIPMENT

Our property, plant and equipment and accumulated depreciation were as follows at June 30, 2005:

	Estimated
	Useful Life
	in Years
Plants and pipelines (1)	5-35 (5)	$ 7,971,609
Underground and other storage facilities (2)	5-35 (6)	537,839
Platforms and facilities (3)	23-31	162,694
Transportation equipment (4)	3-10	8,434
Land		30,534
Construction in progress		455,032
Total		9,166,142
Less accumulated depreciation		983,553
Property, plant and equipment, net		$ 8,182,589

(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).

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 at June 30, 2005 are grouped in the following table according to the business segment to which they relate. For a general discussion of our business segments, see Note 13.

		Ownership
		Percentage
Offshore Pipelines & Services:
	Poseidon Oil Pipeline, L.L.C. (“Poseidon”)	36%	$ 63,531
	Cameron Highway Oil Pipeline Company (“Cameron Highway”) (1)	50%	64,167
	Deepwater Gateway, L.L.C. (“Deepwater Gateway”)	50%	119,328
	Neptune Pipeline Company, L.L.C. (“Neptune”)	25.67%	69,866
	Nemo Gathering Company, LLC (“Nemo”)	33.92%	11,274
Onshore Natural Gas Pipelines & Services:
	Evangeline (2)	49.5%	3,116
	Coyote Gas Treating, LLC (“Coyote”)	50%	2,006
NGL Pipelines & Services:
	Dixie Pipeline Company (“Dixie”) (3)
	Venice Energy Services Company, LLC (“VESCO”)	13.1%	38,214
	Belle Rose NGL Pipeline LLC (“Belle Rose”) (4)
	K/D/S Promix LLC (“Promix”)	50%	60,464
	Baton Rouge Fractionators LLC (“BRF”)	32.3%	26,870
Petrochemical Services:
	Baton Rouge Propylene Concentrator, LLC (“BRPC”)	30%	15,269
	La Porte (5)	50%	5,041
Total			$ 479,146

(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 11. (2) Refers to our ownership interests in Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp., collectively. (3) 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. (4) 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. (5) 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 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 June 30, 2005, our investments in Promix, La Porte, Neptune, Poseidon, Cameron Highway and Nemo included excess cost. At June 30, 2005, excess cost amounts included in our investments in and advances to unconsolidated affiliates totaled $49.2 million, which was attributed to tangible assets.

7. INTANGIBLE ASSETS AND GOODWILL

Intangible assets

The following table summarizes our intangible assets (which primarily consist of contracts and customer relationships) at June 30, 2005 by segment:

		Gross	Accum.	Carrying
		Value	Amort.	Value
Offshore Pipelines & Services		$ 207,012	$ (20,175)	$ 186,837
Onshore Natural Gas Pipelines & Services		457,798	(26,695)	431,103
NGL Pipelines & Services		355,154	(66,607)	288,547
Petrochemical Services		56,674	(6,205)	50,469
	Total	$ 1,076,638	$ (119,682)	$ 956,956

During the six months ended June 30, 2005, we recorded an additional $21.9 million of intangible assets primarily due to acquisitions and changes in our fair market value estimates.

Goodwill

The following table summarizes our goodwill amounts by segment at June 30, 2005. Of the $483.4 million of goodwill we have recorded as of June 30, 2005, $381.1 million relates to goodwill we recorded in connection with the GulfTerra Merger. The amount of goodwill we recorded as a result of the GulfTerra Merger is subject to change since our purchase price allocation remains preliminary (see Note 3).

8. RELATED PARTY TRANSACTIONS

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 EPD's limited partner interests and, prior to September 2003, Shell owned a 30% ownership interest in us. As a result of Shell selling a portion of its limited partner interests in EPD to third parties in December 2004 and during the first seven months of 2005, Shell now owns less than 10% of EPD's common units. Shell sold its 30% interest in us to an affiliate of EPCO in September 2003. As a result of Shell's reduced equity interest in EPD and its lack of control of Enterprise, 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. EPCO is controlled by Dan L. Duncan, who is one of our non-voting directors (non-voting) and Chairman. In addition, our executive and other officers are employees of EPCO, including Robert G. Phillips who is Chief Executive Officer (“CEO”) and one our directors.

At December 31, 2004, EPCO and DDC, together, owned 90.1% of our membership interests. In January 2005, an affiliate of EPCO acquired El Paso's 9.9% membership interest in us. As a result of this transaction, EPCO and its affiliates own 100% of our membership interests.

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. 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.

We and EPD are both separate legal entities from EPCO and its other affiliates, with assets and liabilities that are separate from EPCO and its other affiliates. EPCO depends on cash distributions it receives as an equity owner in EPD to fund most of its other operations and to meet its debt obligations. The ownership interests in us and EPD 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 credit facility. In the event of a default under such credit facility, a change in control of us or EPD 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”), and 2,500,000 common units of TEPPCO from Duke Energy Field Services, LLC ("Duke Energy") 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 GP) was named Chairman of TEPPCO GP. Due to EPCO's actions to reconstitute the board of directors 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 significant 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.

9. MINORITY INTEREST

Minority interest represents third-party and related party ownership interests in the net assets of certain of our subsidiaries. The following table shows the components of minority interest at June 30, 2005:

EPD’s limited partners
	Non-affiliates of EPGP Members	$ 4,381,292
	Affiliates of EPGP Members	767,176
Joint venture partners		85,735
		$ 5,234,203

The minority interest attributable to EPD's limited partners consists of EPD common units held by the public, Shell and affiliates of the Company, which primarily includes EPCO, and is net of unamortized deferred compensation of $9.5 million at June 30, 2005, which represents the value of EPD restricted common units issued to key employees of EPCO. The minority interest attributable to joint venture partners at June 30, 2005, is primarily

attributable to our partners in Tri-States, Seminole, Wilprise, Independence Hub, Dixie and Belle Rose. 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.

10. CAPITAL STRUCTURE

At June 30, 2005, our members’ equity account balances and ownership interests were as follows:

		Membership
		Percentage
DFI		85.60%	$ 53,836
DDC		4.51%	3,788
DFI GP		9.90%	90,976
	Subtotal		148,600
Accumulated other comprehensive income			21,119
	Total		$ 169,719

Earnings and cash distributions are allocated to Member capital accounts in accordance with their respective membership percentages. On September 30, 2004, El Paso was granted a 9.9% membership interest in the Company in connection with our acquisition of El Paso’s 50% membership interest in GulfTerra GP. In January 2005, DFI GP, an affiliate of EPCO, purchased El Paso’s 9.9% membership interest in us. As a result of these transactions, EPCO and affiliates own 100% of the membership interest in EPGP and, at June 30, 2005, approximately 38.6% of EPD’s total common units outstanding. El Paso no longer owns any interest in EPD or EPGP.

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 instrument	(1,434)			(1,434)
Reclassification of gain on settlement of treasury locks to interest expense		(219)		(219)
Reclassification of gain on settlement of forward-starting swaps to interest expense			(1,782)	(1,782)
Balance, June 30, 2005	$ -	$ 4,353	$ 16,766	$ 21,119

During the remainder of 2005, we will reclassify a combined $2 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.

11. DEBT OBLIGATIONS

Our debt consisted of the following at June 30, 2005:

Operating Partnership debt obligations:
	Multi-Year Revolving Credit Facility, variable rate, due September 2009 (1)		$ 180,000
	Seminole Notes, 6.67% fixed-rate, due December 2005 (2)		15,000
	Pascagoula MBFC Loan, 8.70% fixed-rate, due March 2010		54,000
	Senior Notes A, 8.25% fixed-rate, repaid March 2005
	Senior Notes B, 7.50% fixed-rate, due February 2011		450,000
	Senior Notes C, 6.375% fixed-rate, due February 2013		350,000
	Senior Notes D, 6.875% fixed-rate, due March 2033		500,000
	Senior Notes E, 4.00% fixed-rate, due October 2007		500,000
	Senior Notes F, 4.625% fixed-rate, due October 2009		500,000
	Senior Notes G, 5.60% fixed-rate, due October 2014		650,000
	Senior Notes H, 6.65% fixed-rate, due October 2034		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 (2)		21,000
GulfTerra Senior Notes and Senior Subordinated Notes (2,3)			5,673
EPGP related party obligation:
	$370 Million Note, 6.25% fixed rate, due November 2019		364,691
		Total principal amount	4,940,364
Other, including unamortized discounts and premiums and changes in fair value (4)			7,774
		Subtotal long-term debt	4,948,138
Less current maturities of debt			(18,686)
		Long-term debt	$ 4,929,452

Standby letters of credit outstanding (5)			$ 97,139

(1) The Multi-Year Revolving Credit Facility has a $750 million borrowing capacity, which is reduced by the amount of standby letters of credit outstanding. (2) Solely as it relates to the assets of our GulfTerra, Dixie and Seminole subsidiaries, our senior indebtedness is structurally subordinated and ranks junior in right of payment to the indebtedness of such subsidiaries. (3) GulfTerra’s remaining $0.8 million of 6.25% Senior Notes due June 2010 were called and retired in February 2005. (4) The June 30, 2005 amount includes $21.2 million related to fair value hedges and $14.6 million in net unamortized discounts. (5) Of the $97 million in standby letters of credit outstanding at June 30, 2005, $67 million is associated with a letter of credit facility we entered into in November 2004 in connection with our Independence Hub capital project, and the remaining amounts were issued under our Multi-Year Revolving Credit Facility.

Parent-Subsidiary guarantor relationships. Through guarantor agreements which are nonrecourse to us, EPD acts as guarantor of the debt obligations of its Operating Partnership, with the exception of the Seminole Notes, Dixie revolving credit facility and the senior subordinated notes of GulfTerra. If the Operating Partnership were to default on any debt EPD guarantees, EPD would be responsible for full repayment of that obligation. The Seminole Notes are unsecured obligations of Seminole Pipeline Company (of which we own a 90% 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).

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. On January 24, 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. An offer to exchange these notes for registered debt securities began in July 2005 and is currently scheduled to expire in August 2005, unless we decide to extend it.

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 us. EPD has guaranteed repayment of amounts due under these notes through an unsecured and unsubordinated guarantee. 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.

Covenants. The Operating Partnership is in compliance with the various covenants of our consolidated debt agreements at June 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 six months ended June 30, 2005.

		Weighted-
	Range of	average
	interest rates	interest rate
	paid	paid
364-Day Acquisition Credit Facility	3.25% to 3.40%	3.30%
Multi-Year Revolving Credit Facility	3.22% to 6.00%	3.64%

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	$ 16,784
2006	3,802
2007	525,045
2008	4,242
2009	684,576
Thereafter	3,705,915
Total scheduled principal payments	$ 4,940,364

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 June 30, 2005, (ii) total long-term debt obligations (including current maturities) of each unconsolidated affiliate at June 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%	102,000				$ 102,000
Evangeline	49.5%	35,650	$ 5,000	5,000	$ 5,000	5,000	$ 5,000	$ 10,650
Total		$ 552,650	$ 5,000	$ 420,000	$ 5,000	$ 107,000	$ 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 such covenants at June 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 that serves as the operator of the Cameron Highway Oil Pipeline, (iii) pledges by Enterprise 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 our 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 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.

As defined in the amended credit agreement, variable interest rates charged 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.

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. As summarized in the following table, we had nine interest rate swap agreements outstanding at June 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 6.3%	$50 million
Senior Notes C, 6.375% fixed rate, due Feb. 2013		2	Jan. 2004 to Feb. 2013	Feb. 2013	6.375% to 4.85%	$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

	(1) The variable rate indicated is the all-in variable rate for the current settlement period.

The total fair value of these nine interest rate swaps at June 30, 2005, was an asset of $21.2 million with an offsetting increase in the fair value of the underlying debt.

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 June 30, 2005, 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 June 30, 2005 was a liability of $14 thousand.

13. SEGMENT INFORMATION

Business segments are components of a business about which separate financial information is available. The components are regularly evaluated by our CEO 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 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 800 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.

The NGL Pipelines & Services business segment includes our (i) natural gas processing business and related NGL marketing activities, (ii) NGL pipelines aggregating approximately 12,775 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 Petrochemical Services business segment includes four propylene fractionation facilities, an isomerization complex and an octane additive production facility. This segment also includes various petrochemical pipeline systems.

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.

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 represent 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.

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

			Operating Segments
			Offshore	Onshore	NGL		Adjustments
			Pipeline	Pipelines	Pipelines	Petrochem.	and	Consolidated
			& Services	& Services	& Services	Services	Eliminations	Totals
Segment assets:
		At June 30, 2005	$ 636,904	$ 3,656,480	$ 2,933,987	$ 500,186	$ 455,032	$ 8,182,589
Investments in and advances
	to unconsolidated affiliates:
		At June 30, 2005	328,166	5,122	125,548	20,310		479,146
Intangible Assets:
		At June 30, 2005	186,837	431,103	288,547	50,469		956,956
Goodwill:
		At June 30, 2005	81,114	278,503	50,070	73,690		483,377

14. CONDENSED FINANCIAL INFORMATION OF OPERATING PARTNERSHIP

The Operating Partnership and its subsidiaries conduct substantially all of our business. Currently, neither we nor EPD have any independent operations or material assets outside of those of the Operating Partnership. EPD acts as guarantor of all the Operating Partnership’s consolidated debt obligations, with the exception of the Seminole Notes, 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 EPD guarantees, EPD would be responsible for full repayment of that obligation. EPD’s guarantee of these debt obligations is full and unconditional. These debt obligations are non-recourse to us. For additional information regarding our consolidated debt obligations, see Note 11.

The number and dollar amounts of reconciling items between EPD’s consolidated financial statements and those of its Operating Partnership are insignificant. Historically, the primary reconciling items between the consolidated balance sheet of the Operating Partnership and EPD’s consolidated balance sheet were treasury units EPD owns directly and minority interest.

The following table shows condensed consolidated balance sheet data for the Operating Partnership at June 30, 2005:

ASSETS
Current assets		$ 1,530,883
Property, plant and equipment, net		8,182,589
Investments in and advances to unconsolidated affiliates, net		479,146
Intangible assets, net		956,956
Goodwill		483,377
Deferred tax asset		7,737
Long-term receivables		14,815
Other assets		48,062
	Total	$ 11,703,565

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities		$ 1,330,039
Long-term debt		4,568,447
Other long-term liabilities		58,708
Minority interest		88,503
Partners’ equity		5,657,868
	Total	$ 11,703,565

Total Operating Partnership debt obligations guaranteed by EPD		$ 4,534,000

15. 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.

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 current proposed federal legislation has been drafted to eliminate 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 which 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, our 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 our Operating Partnership's potential obligation to the six producers for our share of the cost of constructing the platform in the very 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 our 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, we recorded the fair value of the performance guaranty using an expected present value approach. Given the remote probability that our 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 June 30, 2005.

16. SUBSEQUENT EVENTS

Purchase of NGL underground storage and terminaling assets

In July 2005, we purchased three NGL underground storage facilities and four terminals from Ferrellgas L.P. 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.

August 2005 interest rate swaps

In August 2005, we entered into two 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.

Offshore Pipelines & Services

Onshore Natural Gas Pipelines & Services

NGL Pipelines & Services

Petrochemical Services