EXHIBIT 99.1

Enterprise Products GP, LLC

Unaudited Condensed Consolidated Balance Sheet at June 30, 2006

ENTERPRISE PRODUCTS GP, LLC

TABLE OF CONTENTS

		Page No.

Unaudited Condensed Consolidated Balance Sheet at June 30, 2006		2

Notes to Unaudited Condensed Consolidated Balance Sheet
	Note 1 – Company Organization and Basis of Financial Statement Presentation	3
	Note 2 – General Accounting Policies and Related Matters	4
	Note 3 – Accounting for Equity Awards	6
	Note 4 – Financial Instruments	8
	Note 5 – Inventories	9
	Note 6 – Property, Plant and Equipment	10
	Note 7 – Investments in and Advances to Unconsolidated Affiliates	11
	Note 8 – Business Combinations and Other Acquisitions	11
	Note 9 – Intangible Assets and Goodwill	12
	Note 10 – Debt Obligations	13
	Note 11 – Member’s Equity	15
	Note 12 – Business Segments	15
	Note 13 – Related Party Transactions	16
	Note 14 – Commitments and Contingencies	18
	Note 15 – Significant Risks and Uncertainties – Weather-Related Risks	19
	Note 16 – Condensed Financial Information of Operating Partnership	20
	Note 17 – Subsequent Events	21

ENTERPRISE PRODUCTS GP, LLC

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET

AT JUNE 30, 2006

(Dollars in thousands)

ASSETS
Current assets
	Cash and cash equivalents			$ 24,525
	Restricted cash			21,655
	Accounts and notes receivable – trade, net of allowance
		for doubtful accounts of $20,121		1,324,611
	Accounts receivable – related parties			12,228
	Inventories			451,237
	Prepaid and other current assets			169,276
			Total current assets	2,003,532
Property, plant and equipment, net				9,018,275
Investments in and advances to unconsolidated affiliates				464,605
Intangible assets, net of accumulated amortization of $205,055				909,323
Goodwill				493,995
Deferred tax asset				3,445
Other assets				150,104
			Total assets	$ 13,043,279

LIABILITIES AND MEMBER'S EQUITY
Current liabilities
	Accounts payable - trade			$ 264,368
	Accounts payable - related parties			38,544
	Accrued gas payables			1,392,239
	Accrued expenses			30,160
	Accrued interest			69,945
	Other current liabilities			188,339
			Total current liabilities	1,983,595
Long-term debt				4,821,401
Other long-term liabilities				131,316
Minority interest				5,575,235
Commitments and contingencies
Member's equity				531,732
			Total liabilities and member's equity	$ 13,043,279

See Notes to Unaudited Condensed Consolidated Balance Sheet

ENTERPRISE PRODUCTS GP, LLC

NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET

AT JUNE 30, 2006

1. Company Organization and Basis of Financial Statement Presentation

Company organization and formation

Enterprise Products GP, LLC is a Delaware limited liability company formed in May 1998 that is the general partner of Enterprise Products Partners L.P. (“Enterprise Products Partners”). Enterprise Products GP’s primary business purpose is to manage the affairs and operations of Enterprise Products Partners and its subsidiaries. Enterprise Products Partners is a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.” Enterprise Products Partners conducts substantially all of its business through a wholly owned subsidiary, Enterprise Products Operating L.P. (the “Operating Partnership”).

Enterprise Products GP is owned 100% by Enterprise GP Holdings L.P. (“Enterprise GP Holdings”). Enterprise GP Holdings is a publicly traded partnership, the common units of which are listed on the NYSE under the ticker symbol “EPE.” Enterprise GP Holdings’ assets consist of its ownership of Enterprise Products GP and certain limited partner interests in Enterprise Products Partners. Enterprise Products GP, Enterprise Products Partners and Enterprise GP Holdings are affiliates and under common control of Dan L. Duncan, the Chairman and controlling shareholder of EPCO, Inc.

Significant relationships referenced in Notes to Unaudited Condensed Consolidated Balance Sheet

Unless the context requires otherwise, references to “we,” “us,” “our” or “Enterprise Products GP, LLC” are intended to mean and include the business and operations of Enterprise Products GP, LLC, as well as its consolidated subsidiaries, which include Enterprise Products Partners L.P. and its consolidated subsidiaries.

References to “Enterprise Products GP” are intended to mean and include Enterprise Products GP, LLC, individually as the general partner of Enterprise Products Partners L.P., and not on a consolidated basis.

References to “Enterprise Products Partners” mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries.

References to “Enterprise GP Holdings” are intended to mean Enterprise GP Holdings L.P., individually as our parent company, and not on a consolidated basis.

References to “EPE Holdings” mean EPE Holdings, LLC, the general partner of Enterprise GP Holdings.

References to “EPCO” mean EPCO, Inc., which is a related party affiliate to all of the foregoing named entities.

References to “TEPPCO” mean TEPPCO Partners L.P., a publicly traded Delaware limited partnership, which is an affiliate of us. References to “TEPPCO GP” refer to the general partner of TEPPCO, which is wholly owned by a private company subsidiary of EPCO.

Basis of presentation of consolidated financial statements

We own a 2% general partner interest in Enterprise Products Partners, which conducts substantially all of our business. We have no independent operations and no material assets outside those of Enterprise Products Partners. The number of reconciling items between our consolidated balance sheet and that of Enterprise Products Partners are few. The most significant difference is that relating to minority

interest ownership in our net assets by the limited partners of Enterprise Products Partners, and the elimination of our investment in Enterprise Products Partners with our underlying partner’s capital account in Enterprise Products Partners. See Note 2 for additional information regarding minority interest ownership in our consolidated subsidiaries.

In our opinion, the accompanying unaudited condensed consolidated balance sheet includes all adjustments consisting of normal recurring accruals necessary for a fair presentation. Although we believe our disclosures are adequate to make the information presented in our 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” or “Commission”). Enterprise Products GP’s unaudited June 30, 2006 balance sheet should be read in conjunction with its audited December 31, 2005 balance sheet filed on Enterprise Products Partners' Form 8-K on February 27, 2006. In addition, this financial information should be read in conjunction with Enterprise Products Partners' Form 10-K for the year ended December 31, 2005 and its Form 10-Q for the three and six months ended June 30, 2006. The Commission file number for Enterprise Products Partners’ public filings is 1-14323.

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

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. Our actual results could differ from these estimates.

New accounting pronouncements

Emerging Issues Task Force (“EITF”) 04-13, “Accounting for Purchases and Sale of Inventory With the Same Counterparty.” This accounting guidance requires that two or more inventory transactions with the same counterparty should be viewed as a single nonmonetary transaction, if the transactions were entered into in contemplation of one another. Exchanges of inventory between entities in the same line of business should be accounted for at fair value or recorded at carrying amounts, depending on the classification of such inventory. This guidance was effective April 1, 2006, and our adoption of this guidance had no impact on our financial position, results of operations or cash flows.

EITF 06-3, “How Taxes Collected From Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation).” This accounting guidance requires companies to disclose their policy regarding the presentation of tax receipts on the face of their income statements. This guidance specifically applies to taxes imposed by governmental authorities on revenue-producing transactions between sellers and customers (gross receipts taxes are excluded). This guidance is effective January 1, 2007. As a matter of policy, we report such taxes on a net basis.

Statement of Financial Accounting Standards (“SFAS”) 155, “Accounting for Certain Hybrid Financial Instruments.” This accounting standard amends SFAS 133, Accounting for Derivative Instruments and Hedging Activities, amends SFAS 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, and resolves issues addressed in Statement 133 Implementation Issue D1, Application of Statement 133 to Beneficial Interests to Securitized Financial Assets. A hybrid financial instrument is one that embodies both an embedded derivative and a host contract. For certain hybrid financial instruments, SFAS 133 requires an embedded derivative instrument be separated from the host contract and accounted for as a separate derivative instrument. SFAS 155

amends SFAS 133 to provide a fair value measurement alternative for certain hybrid financial instruments that contain an embedded derivative that would otherwise be recognized as a derivative separately from the host contract. For hybrid financial instruments within its scope, SFAS 155 allows the holder of the instrument to make a one-time, irrevocable election to initially and subsequently measure the instrument in its entirety at fair value instead of separately accounting for the embedded derivative and host contract. We are evaluating the effect of this recent guidance, which is effective January 1, 2007 for our partnership.

Accounting for employee benefit plans

Dixie Pipeline Company (“Dixie”), a consolidated subsidiary of Enterprise Products Partners, directly employs the personnel operating its pipeline system. Certain of these employees are eligible to participate in Dixie’s defined contribution plan and pension and postretirement benefit plans. Dixie's employee benefit plans are immaterial to our consolidated financial position, results of operations and cash flows. During the remainder of 2006, Dixie expects to contribute approximately $0.2 million to its postretirement benefit plan and between $2 million and $4.4 million to its pension plan.

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 presents the components of minority interest at June 30, 2006:

Limited partners of Enterprise Products Partners:
	Non-affiliates of Enterprise Products GP	$ 4,760,571
	Affiliates of Enterprise Products GP	693,920
Joint venture partners		120,744
	Total minority interest on consolidated balance sheet	$ 5,575,235

Minority interest attributable to the limited partners of Enterprise Products Partners consist of common units held by the public and affiliates of EPCO. Minority interest attributable to joint venture partners at June 30, 2006, primarily represents our partners in Tri-States, Seminole, Wilprise, Independence Hub, Dixie and Belle Rose.

Provision for income taxes

Prior to the second quarter of 2006, our provision for income taxes related to federal income tax and state franchise and income tax obligations of Seminole and Dixie, which are both corporations and represented our only consolidated subsidiaries that were historically subject to such income taxes. In May 2006, the State of Texas enacted a new business tax (the “Texas Margin Tax”) that replaced the existing state franchise tax. In general, legal entities that do business in Texas are subject to the Texas Margin Tax. Limited partnerships, limited liability companies, corporations, limited liability partnerships and joint ventures are examples of the types of entities that are subject to the Texas Margin Tax. As a result of the change in tax law, our tax status in the State of Texas changed from non-taxable to taxable. The tax is considered an income tax for purposes of adjustments to deferred tax liability as the tax is determined by applying a tax rate to a base that considers both revenues and expenses. The Texas Margin Tax becomes effective for margin tax reports due on or after January 1, 2008. The Texas Margin Tax due in 2008 will be based on revenues earned during the 2007 fiscal year.

The Texas Margin Tax is assessed at 1% of Texas-sourced taxable margin. The taxable margin is the lesser of (1) 70% of total revenue or (2) total revenue less (a) cost of goods sold or (b) compensation and benefits. Our deferred tax liability, which is a component of other long-term liabilities on our consolidated balance sheets, reflects the net tax effects of temporary differences related to items such as property, plant and equipment. Therefore, the deferred tax liability is noncurrent. We have calculated and recorded an estimated deferred tax liability of approximately $6.1 million for the Texas Margin Tax.

3. Accounting for Equity Awards

Effective January 1, 2006, we adopted SFAS 123(R) to account for equity awards. Prior to our adoption of SFAS 123(R), we accounted for equity awards using the intrinsic value method described in Accounting Principles Board Opinion (“APB”) 25, “Accounting for Stock Issued to Employees.” SFAS 123(R) requires us to recognize compensation expense related to equity awards based on the fair value of the award at the grant date. The fair value of an equity award is estimated using the Black-Scholes option pricing model. Under SFAS 123(R), the fair value of an award is amortized to earnings on a straight-line basis over the requisite service or vesting period.

Upon our adoption of SFAS 123(R), we recognized a cumulative effect of change in accounting principle of $1.5 million (a benefit), which is included as a component of minority interest since the limited partners of Enterprise Products Partners were allocated their share of this benefit. The cumulative effect adjustment is based on SFAS 123(R)’s requirement to recognize compensation expense based upon the grant date fair value of an equity award and the application of an estimated forfeiture rate to unvested awards. In addition, previously recognized deferred compensation expense of $14.6 million related to Enterprise Products Partners’ nonvested (or “restricted”) common units was reversed on January 1, 2006.

Unit options

Under EPCO’s 1998 Long-Term Incentive Plan (the “1998 Plan”), non-qualified incentive options to purchase a fixed number of Enterprise Products Partners’ common units may be granted to EPCO’s key employees who perform management, administrative or operational functions for us. When issued, the exercise price of each option grant is equivalent to the market price of the underlying equity on the date of grant. In general, options granted under the 1998 Plan have a vesting period of four years and remain exercisable for ten years from the date of grant.

In order to fund its obligations under the 1998 Plan, EPCO purchases common units at fair value either in the open market or directly from Enterprise Products Partners. When employees exercise unit options, we reimburse EPCO for our allocable share of the cash difference between the strike price paid by the employee and the actual purchase price paid by EPCO for the units issued to the employee.

The fair value of each option to purchase Enterprise Products Partners’ common units is estimated on the date of grant using the Black-Scholes option pricing model, which incorporates various assumptions including (i) an expected life of the options of seven years, (ii) risk-free interest rates ranging from 3.1% to 6.4%, (iii) an expected distribution yield on common units of Enterprise Products Partners ranging from 5.3% to 10%, and (iv) expected unit price volatility on Enterprise Products Partners’ common units ranging from 20% to 30%. In general, our assumption of expected life represents the period of time that options are expected to be outstanding based on an analysis of historical option activity. Our selection of the risk-free interest rate is based on published yields for U.S. government securities with comparable terms. The expected distribution yield and unit price volatility for Enterprise Products Partners’ units is estimated based on several factors, which include an analysis of our historical unit price volatility and distribution yield over a period equal to the expected life of the option.

The information in the following table shows unit option activity under the 1998 Plan.

				Weighted-
				average
			Weighted-	remaining	Aggregate
		Number of	average strike	contractual	Intrinsic
		Units	price	term (in years)	Value ⁽¹⁾
Outstanding at December 31, 2005		2,082,000	$ 22.16
	Granted	590,000	$ 24.85
	Exercised	(63,000)	$ 14.75
	Forfeited	(45,000)	$ 24.28
Outstanding at June 30, 2006		2,564,000	$ 22.92	7.91	$ 3,594

Exercisable at June 30, 2006		714,000	$ 19.87	5.35	$ 3,594

(1) Aggregate intrinsic value reflects fully vested unit options of Enterprise Products Partners at June 30, 2006.

The total intrinsic value of Enterprise Products Partners’ unit options exercised during the three and six months ended June 30, 2006 was $0.3 million and $0.6 million, respectively. During the six months ended June 30, 2006, we received cash of $1.6 million from the exercise of unit options, and our option-related reimbursements to EPCO were $0.7 million.

Nonvested units

Under the 1998 Plan, Enterprise Products Partners may issue nonvested (or,“restricted”) common units to key employees of EPCO and directors of Enterprise Products GP. The 1998 Plan provides for the issuance of 3,000,000 restricted common units of Enterprise Products Partners, of which 1,933,088 remain authorized for issuance at June 30, 2006.

In general, Enterprise Products Partners’ restricted unit awards allow recipients to acquire the underlying common units (at no cost to the recipient) once a defined vesting period expires, subject to certain forfeiture provisions. The restrictions on such nonvested units generally lapse four years from the date of grant. The fair value of such restricted units is based on (i) the market price of the underlying common units on the date of grant and (ii) an allowance for forfeitures.

The following table summarizes information regarding Enterprise Products Partners’ restricted units for the six months ended June 30, 2006.

			Weighted-
		Number of	average grant
		Units	date fair value
Restricted units at December 31, 2005		751,604	$ 24.49
	Granted	400,400	$ 24.85
	Vested	(39,711)	$ 23.91
	Forfeited	(37,276)	$ 24.14
Restricted units at June 30, 2006		1,075,017	$ 24.66

The total fair value of Enterprise Products Partners’ restricted units that vested during the three and six months ended June 30, 2006 was $0.9 million and $1.0 million, respectively.

Employee Partnership

In connection with the initial public offering of the parent company in August 2005, the Employee Partnership was formed to serve as an incentive arrangement for certain employees of EPCO through a “profits interest” in the Employee Partnership. At inception, the Employee Partnership used $51 million in contributions it received from an affiliate of EPCO (which was admitted as the Class A limited partner of

the Employee Partnership as a result of such contribution) to purchase 1,821,428 units of the parent company in August 2005. Certain EPCO employees, including all of EPE Holdings’ and Enterprise Products GP’s executive officers other than Dan L. Duncan, have been issued Class B limited partner interests without any capital contribution and admitted as Class B limited partners of the Employee Partnership.

As described in its partnership agreement, the Employee Partnership will be liquidated upon the earlier of (i) August 2010 or (ii) a change in control of Enterprise GP Holdings L.P. or its general partner, EPE Holdings. Upon liquidation of the Employee Partnership, units having a fair market value equal to the Class A limited partner’s capital base will be distributed to the Class A limited partner, plus any Class A preferred return for the quarter in which liquidation occurs. Any remaining units will be distributed to the Class B limited partners as a residual profits interest in the Employee Partnership as an award.

Prior to our adoption of SFAS 123(R), the estimated value of the profits interest was accounted for in a manner similar to a stock appreciation right. Upon our adoption of SFAS 123(R), we began recognizing compensation expense based upon the estimated grant date fair value of the Class B partnership equity awards.

The fair value of the Class B partnership equity awards was estimated on the date of grant using a Black-Scholes option pricing model, which incorporates various assumptions including (i) an expected life of the awards of five years; (ii) a risk-free interest rate of 4.1%; (iii) an expected dividend yield on units of Enterprise GP Holdings of 3%; and (iv) an expected Enterprise GP Holdings unit price volatility of 30%. In general, the methodology we followed to estimate the fair value of the Class B partnership equity awards is similar to that used to estimate the fair value of Enterprise Products Partners’ unit options.

4. 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 (i) the variability of future earnings, (ii) fair values of certain debt instruments and (iii) cash flows resulting from changes in certain 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 interest rate borrowings under various 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.

Fair value hedges – Interest rate swaps. As summarized in the following table, we had eleven interest rate swap agreements outstanding at June 30, 2006 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 8.15%	$50 million
Senior Notes C, 6.375% fixed rate, due Feb. 2013		2	Jan. 2004 to Feb. 2013	Feb. 2013	6.375% to 6.69%	$200 million
Senior Notes G, 5.6% fixed rate, due Oct. 2014		6	4^th Qtr. 2004 to Oct. 2014	Oct. 2014	5.6% to 6.14%	$600 million
Senior Notes K, 4.95% fixed rate, due June 2010		2	Aug. 2005 to June 2010	June 2010	4.95% to 5.73%	$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 June 30, 2006 and December 31, 2005, was a liability of $64.9 million and $19.2 million, respectively, with an offsetting decrease in the fair value of the underlying debt.

Cash flow hedges – Treasury Locks. During the second quarter of 2006, the Operating Partnership entered into a treasury lock transaction having a notional amount of $250 million. In addition, in July 2006, the Operating Partnership entered into an additional treasury lock transaction having a notional amount of $50 million. A treasury lock is a specialized agreement that fixes the price (or yield) on a specific treasury security for an established period of time. A treasury lock purchaser is protected from a rise in the yield of the underlying treasury security during the lock period. The Operating Partnership’s purpose of entering into these transactions was to hedge the underlying U.S. treasury rate related to its anticipated issuance of subordinated debt. In July 2006, the Operating Partnership issued $300 million in principal amount of its Junior Notes A (see Note 17). Each of the treasury lock transactions was designated as a cash flow hedge under SFAS 133. In July 2006, the Operating Partnership elected to terminate these treasury lock transactions and recognized a minimal gain.

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 such products, 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, NGLs or certain petrochemical products.

The fair value of our commodity financial instrument portfolio at June 30, 2006 and December 31, 2005 was a liability of $7.8 million and $0.1 million, respectively.

5. Inventories

At June 30, 2006, our inventory amounts were as follows:

Working inventory	$ 406,169
Forward-sales inventory	45,068
Inventory	$ 451,237

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

6. Property, Plant and Equipment

At June 30, 2006, our property, plant and equipment and accumulated depreciation were as follows:

	Estimated
	Useful Life	June 30,
	in Years	2006
Plants and pipelines ⁽¹⁾	5-35 ⁽⁵⁾	$ 8,489,508
Underground and other storage facilities ⁽²⁾	5-35 ⁽⁶⁾	552,458
Platforms and facilities ⁽³⁾	23-31	161,880
Transportation equipment ⁽⁴⁾	3-10	22,245
Land		38,589
Construction in progress		1,074,165
Total		10,338,845
Less accumulated depreciation		1,320,570
Property, plant and equipment, net		$ 9,018,275

(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).

7. Investments in and Advances to Unconsolidated Affiliates

We own interests in a number of related businesses that are accounted for using the equity method. 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 12. The following table shows our investments in and advances to unconsolidated affiliates at June 30, 2006.

		Ownership
		Percentage
NGL Pipelines & Services:
	Venice Energy Services Company, LLC (“VESCO”)	13.1%	$ 38,609
	K/D/S Promix LLC (“Promix”)	50%	55,330
	Baton Rouge Fractionators LLC (“BRF”)	32.3%	26,096
Onshore Natural Gas Pipelines & Services:
	Evangeline ⁽¹⁾	49.5%	4,547
	Coyote Gas Treating, LLC (“Coyote”)	50%	1,510
Offshore Pipelines & Services:
	Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”)	36%	62,296
	Cameron Highway Oil Pipeline Company (“Cameron Highway”)	50%	62,789
	Deepwater Gateway, L.L.C. (“Deepwater Gateway”)	50%	115,628
	Neptune Pipeline Company, L.L.C. (“Neptune”)	25.67%	67,405
	Nemo Gathering Company, LLC (“Nemo”)	33.92%	10,527
Petrochemical Services:
	Baton Rouge Propylene Concentrator, LLC (“BRPC”)	30%	14,870
	La Porte ⁽²⁾	50%	4,998
Total			$ 464,605

(1) Refers to our ownership interests in Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp., collectively. (2) Refers to our ownership interests in La Porte Pipeline Company, L.P. and La Porte GP, LLC, collectively.

On occasion, the price we pay to purchase an equity interest in a company exceeds the underlying book capital account we acquire. Such excess cost amounts are included within our investments in and advances to unconsolidated affiliates. At June 30, 2006, our investments in Promix, La Porte, Neptune, Poseidon, Cameron Highway and Nemo included excess cost amounts totaling $47 million, all of which was attributed to values in excess of the underlying tangible asset values.

8. Business Acquisitions

In March 2006, we paid $38.1 million to TEPPCO for its Pioneer natural gas processing plant located in Opal, Wyoming and certain natural gas processing rights related to production from the Jonah and Pinedale fields located in the Greater Green River Basin in Wyoming. This acquisition was accounted for under the purchase method of accounting and, accordingly, the cost has been allocated based on estimated preliminary fair values as follows:

Property, plant and equipment, net		$ 469
Intangible assets		37,631
	Total assets acquired	$ 38,100
	Total consideration given	$ 38,100

Management developed the fair value estimates underlying this preliminary purchase price allocation using recognized business valuation techniques.

After completing this acquisition, we commenced construction to increase the capacity of the Pioneer natural gas processing plant, and started work on a related cryogenic natural gas processing facility. Upon completion of the cryogenic natural gas processing facility, we will have the required capacity to process natural gas production from the Jonah and Pinedale fields that is expected to be transported to our

Wyoming facilities as a result of the contract rights we acquired from TEPPCO. See Note 9 for information regarding the intangible assets recorded in connection with this acquisition.

See Note 17 for subsequent events involving (i) our acquisition of natural gas pipeline assets located in South Texas in July 2006 and (ii) our acquisition of an NGL pipeline from ExxonMobil in August 2006.

9. Intangible Assets and Goodwill

Identifiable Intangible assets

The following table summarizes our intangible assets by segment at June 30, 2006. Our intangible assets primarily consist of contracts and customer relationships.

	Gross	Accum.	Carrying
Business Segment	Value	Amort.	Value
NGL Pipelines & Services ⁽¹⁾	$ 392,894	$ (92,150)	$ 300,744
Onshore Natural Gas Pipelines & Services	457,798	(60,761)	397,037
Offshore Pipelines & Services	207,012	(43,947)	163,065
Petrochemical Services	56,674	(8,197)	48,477
Total	$ 1,114,378	$ (205,055)	$ 909,323

(1) During the first six months of 2006, we recorded an additional $37.6 million of intangible assets in connection with our acquisition of the Pioneer natural gas processing plant and associated natural gas processing rights. The value we assigned to these processing rights will be amortized to earnings using methods that closely resemble the pattern in which the economic benefits of the underlying natural gas resource bases from which the customers produce are estimated to be consumed or otherwise used. Our estimate of the useful life of each resource base is based on a number of factors, including third-party reserve estimates, the economic viability of production and exploration activities and other industry factors.

Goodwill

The following table summarizes our goodwill amounts by segment at June 30, 2006. Of the $494 million of goodwill we have recorded, $387.1 million was recorded in connection with the merger of GulfTerra Energy Partners, L.P. (“GulfTerra”) with a wholly owned subsidiary of Enterprise Products Partners in September 2004.

NGL Pipelines & Services		$ 54,942
Onshore Natural Gas Pipelines & Services		282,977
Offshore Pipelines & Services		82,386
Petrochemical Services		73,690
	Totals	$ 493,995

10. Debt Obligations

Our consolidated debt consisted of the following at June 30, 2006:

Operating Partnership debt obligations:
	Multi-Year Revolving Credit Facility, variable rate, due October 2011 ⁽¹⁾		$ 530,000
	Pascagoula MBFC Loan, 8.70% fixed-rate, due March 2010		54,000
	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, 4.950% fixed-rate, due June 2010		500,000
Dixie Revolving Credit Facility, variable rate, due June 2007			10,000
Debt obligations assumed from GulfTerra			5,068
		Total principal amount	4,899,068
Other, including unamortized discounts and premiums and changes in fair value ⁽²⁾			(77,667)
		Long-term debt	$ 4,821,401

Standby letters of credit outstanding			$ 46,558

(1) In June 2006, the Operating Partnership executed a second amendment (the “Second Amendment”) to the credit agreement governing its Multi-Year Revolving Credit Facility. The Second Amendment, among other things, extends the maturity date of amounts borrowed under the Multi-Year Revolving Credit Facility from October 2010 to October 2011 with respect to $1.2 billion of the commitments. Borrowings with respect to the remaining $48 million in commitments mature in October 2010. (2) The June 30, 2006 amount includes $64 million related to fair value hedges and $13.7 million in net unamortized discounts.

Parent-Subsidiary guarantor relationships

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

Operating Partnership debt obligations

Apart from that discussed below, there have been no significant changes in the terms of the Operating Partnership’s debt obligations since those reported in our Enterprise Products Partners’ annual report on Form 10-K for the year ended December 31, 2005.

In March 2006, Enterprise Products Partners generated net proceeds of $430 million in connection with the sale of 18,400,000 of its common units in an underwritten equity offering. Subsequently, this amount was contributed to the Operating Partnership, which, in turn, used this amount to temporarily reduce debt outstanding under its Multi-Year Revolving Credit Facility.

In June 2006, the Operating Partnership executed a second amendment (the “Second Amendment”) to the credit agreement governing its Multi-Year Revolving Credit Facility. The Second Amendment, among other things, extends the maturity date of the Multi-Year Revolving Credit Facility from October 2010 to October 2011 with respect to $1.2 billion of the commitments. Borrowings with respect to $48 million in commitments mature in October 2010. The Second Amendment also modifies the Operating Partnership’s financial covenants to, among other things, allow the Operating Partnership to include in the calculation of its Consolidated EBITDA (as defined in the credit agreement) pro forma adjustments for material capital projects. In addition, the Second Amendment allows for the issuance of

hybrid debt, such as the $300 million in principal amount of fixed/floating unsecured junior subordinated notes issued by the Operating Partnership in July 2006 (see Note 17).

Covenants

We were in compliance with the covenants of our consolidated debt agreements at June 30, 2006.

Information regarding variable interest rates paid

The following table shows the range of interest rates paid and weighted-average interest rate paid on our consolidated variable-rate debt obligations during the six months ended June 30, 2006.

	Range of	Weighted-average
	interest rates	interest rate
	paid	paid
Operating Partnership’s Multi-Year Revolving Credit Facility	4.87% to 8.00%	5.35%
Dixie Revolving Credit Facility	4.67% to 5.55%	5.00%

Consolidated debt maturity table

Our scheduled maturities of debt principal amounts over the next five years and in total thereafter are presented in the following table. No amounts are currently due in 2006 or 2008.

2007	$ 510,000
2009	500,000
2010	607,068
Thereafter	3,282,000
Total scheduled principal payments	$ 4,899,068

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, 2006, (ii) total debt of each unconsolidated affiliate at June 30, 2006 (on a 100% basis to the joint venture) and (iii) the corresponding scheduled maturities of such debt.

	Our		Scheduled Maturities of Debt
	Ownership							After
	Interest	Total	2006	2007	2008	2009	2010	2010
Cameron Highway	50.0%	$ 415,000			$ 25,000	$ 25,000	$ 50,000	$ 315,000
Poseidon	36.0%	92,000						92,000
Evangeline	49.5%	30,650	$ 5,000	$ 5,000	5,000	5,000	10,650
Total		$ 537,650	$ 5,000	$ 5,000	$ 30,000	$ 30,000	$ 60,650	$ 407,000

The credit agreements of our joint ventures contain various affirmative and negative covenants, including financial covenants. Our joint ventures were in compliance with all such covenants at June 30, 2006.

Amendment of Cameron Highway debt. In March 2006, Cameron Highway amended the note purchase agreement governing its senior secured notes to primarily address the effect of reduced deliveries of crude oil to Cameron Highway resulting from production delays. In general, this amendment modified certain financial covenants in light of production forecasts made by management. In addition, the amendment increased the face amount of the letters of credit required to be issued by the Operating Partnership and an affiliate of our joint venture partner from $18.4 million each to $36.8 million each.

Also, the amendment specifies that Cameron Highway cannot make distributions to its partners during the period beginning March 30, 2006 and ending on the earlier of (i) December 31, 2007 or (ii) the date on which Cameron Highway’s debt service coverage ratios are not less than 1.5 to 1 for three consecutive fiscal quarters. In order for Cameron Highway to resume paying distributions to its partners, no default or event of default can be present or continuing at the date Cameron Highway desires to start paying such distributions.

Amendment of Poseidon debt. In May 2006, Poseidon amended its revolving credit facility to, among other things, reduce commitments from $170 million to $150 million, extend the maturity date from January 2008 to May 2011 and lower the borrowing rate.

11. Member’s Equity

At June 30, 2006, member’s equity consisted of the capital account of Enterprise GP Holdings and accumulated other comprehensive income. Enterprise GP Holdings is a publicly traded limited partnership that completed an initial public offering of its common units in August 2005 and trades on the NYSE under the ticker symbol “EPE.”

Accumulated other comprehensive income

The following table summarizes transactions affecting our accumulated other comprehensive income since December 31, 2005.

			Accumulated
		Interest	Other
	Commodity	Rate	Comprehensive
	Financial	Financial	Income
	Instruments	Instruments	Balance
Balance, December 31, 2005		$ 19,072	$ 19,072
Change in fair value of commodity financial instruments	$ (7,700)		(7,700)
Reclassification of gain on settlement of interest rate financial instruments		(2,093)	(2,093)
Reclassification of change in fair value of interest rate financial instruments		1,638	1,638
Balance, June 30, 2006	$ (7,700)	$ 18,617	$ 10,917

During the remainder of 2006, we will reclassify $2.1 million from accumulated other comprehensive income to earnings as a reduction in consolidated interest expense.

12. Business Segments

We have four reportable business segments: NGL Pipelines & Services, Onshore Natural Gas Pipelines & Services, Offshore 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.

Our integrated midstream energy asset system (including the midstream energy assets of our equity method investees) provides services to producers and consumers of natural gas, NGLs and petrochemicals. Our asset system has multiple entry points. In general, hydrocarbons can enter our asset system through a number of ways, such as an offshore natural gas or crude oil pipeline, an offshore platform, a natural gas processing plant, an NGL gathering pipeline, an NGL fractionator, an NGL storage facility, an NGL transportation or distribution pipeline or an onshore natural gas pipeline.

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 the total value of segment assets is construction-in-progress. Segment assets represent the net book carrying value of

facilities and other assets that contribute to gross operating margin of a particular segment. Since assets under construction generally do not contribute to segment gross operating margin, such assets are excluded from segment asset 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 our consolidated totals, is presented in the following table:

			Operating Segments
			NGL	Onshore	Offshore		Adjustments
			Pipelines	Pipelines	Pipelines	Petrochemical	and	Consolidated
			& Services	& Services	& Services	Services	Eliminations	Totals
Segment assets:
		At June 30, 2006	$ 3,143,499	$ 3,557,642	$ 733,047	$ 509,922	$ 1,074,165	$ 9,018,275
Investments in and advances to
	unconsolidated affiliates (see Note 7):
		At June 30, 2006	120,035	6,057	318,645	19,868		464,605
Intangible Assets (see Note 9):
		At June 30, 2006	300,744	397,037	163,065	48,477		909,323
Goodwill (see Note 9):
		At June 30, 2006	54,942	282,977	82,386	73,690		493,995

13. Related Party Transactions

Relationship with EPCO and affiliates

General. We have an extensive and ongoing relationship with EPCO and its affiliates, which include the following significant entities:

•

EPCO and its private company subsidiaries;

•

Enterprise GP Holdings, which owns 100% of the membership interest and controls Enterprise Products GP;

•

the Employee Partnership; and

•

TEPPCO and TEPPCO GP, which are controlled by affiliates of EPCO.

Unless noted otherwise, our agreements with EPCO are not the result of arm’s length transactions. As a result, we cannot provide assurance that the terms and provisions of such agreements are at least as favorable to us as we could have obtained from unaffiliated third parties.

EPCO is a private company controlled by Dan L. Duncan, who is also a director and Chairman of Enterprise Products GP and EPE Holdings, the general partner of Enterprise GP Holdings. At June 30, 2006, EPCO and its affiliates beneficially owned 144,384,693 (or 34.5%) of the outstanding common units of Enterprise Products Partners. In addition, at June 30, 2006, EPCO and its affiliates owned 86.7% of Enterprise GP Holdings, including 100% of EPE Holdings.

Enterprise Products Partners, Enterprise Products GP, Enterprise GP Holdings and EPE Holdings are separate legal entities apart from each other and apart from EPCO and its other affiliates, with assets and liabilities that are separate from those of EPCO and its other affiliates. EPCO depends on the cash distributions it receives from Enterprise Products Partners, Enterprise GP Holdings and other investments to fund its other operations and to meet its debt obligations. EPCO and its affiliates received $148.3 million and $117.8 million in cash distributions from us during the six months ended June 30, 2006 and 2005, respectively, in connection with its member interests in Enterprise Products GP and EPE Holdings and its limited partner interests in Enterprise Products Partners and Enterprise GP Holdings.

The ownership interests in Enterprise Products Partners and Enterprise GP Holdings that are owned or controlled by EPCO and its affiliates, other than those interests owned by Enterprise GP

Holdings, Dan Duncan LLC and certain trusts affiliated with Dan L. Duncan, are pledged as security under the credit facility of an affiliate of EPCO. This credit facility contains customary and other events of default relating to EPCO and certain affiliates, including Enterprise Products Partners, Enterprise GP Holdings and TEPPCO.

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. We also lease office space in various buildings from affiliates of EPCO. The rental rates in these lease agreements approximate market rates. In addition, we buy and sell NGL products to and from a foreign affiliate of EPCO at market-related prices in the normal course of business.

Relationship with TEPPCO. In March 2006, we paid $38.1 million to TEPPCO for its Pioneer natural gas processing plant located in Opal, Wyoming and certain natural gas processing rights related to production from the Jonah and Pinedale fields located in the Greater Green River Basin in Wyoming. This transaction was reviewed and approved by the Audit and Conflicts Committee of the board of directors of our general partner and the general partner of TEPPCO, and a fairness opinion was rendered by an independent third-party. TEPPCO will have no continued involvement in the contracts or in the operations of the Pioneer facility. In addition, the unaudited pro forma financial impact of this transaction is not significant.

In August 2006, we announced a joint venture in which we and TEPPCO will be partners in TEPPCO’s Jonah Gas Gathering Company. The Jonah Gas Gathering Company owns the Jonah Gas Gathering System (“the Jonah system”), located in the Greater Green River Basin of southwestern Wyoming, which gathers and transports natural gas produced from the Jonah and Pinedale fields to natural gas processing plants and major interstate pipelines that deliver natural gas to end-use markets.

A letter of intent executed by us and TEPPCO in February 2006 provided that we would manage the construction and fund the initial capital cost of the Phase V expansion of the Jonah system. In connection with the joint venture arrangement, we and TEPPCO intend to continue the Phase V expansion, which is expected to increase the system capacity of the Jonah system from 1.5 Bcf/d to 2.4 Bcf/d and to significantly reduce system operating pressures, which is anticipated to lead to increased production rates and ultimate reserve recoveries. The first portion of the expansion, which is believed to increase the system gathering capacity to 2 Bcf/d, is projected to be completed in the first quarter of 2007 at an estimated cost of approximately $275 million. The second portion of the expansion is expected to cost approximately $140 million and be completed by the end of 2007.

We will manage the Phase V construction project, and in the third quarter of 2006, TEPPCO will reimburse us for 50% of the Phase V capital cost incurred through August 1, 2006. After August 1, 2006, we and TEPPCO will equally share the capital costs of the Phase V expansion. Our ultimate ownership interest in Jonah Gas Gathering Company will be based on our share of the total cost of the Phase V expansion. Upon completion of the expansion project, we and TEPPCO are expected to own an approximate 20% and 80% interest, respectively, in Jonah Gas Gathering Company, with us serving as operator. Our expenditures associated with this project were $106.9 million during the six months ended June 30, 2006, of which $97.8 million has been paid to vendors. Other assets on our Unaudited Condensed Consolidated Balance Sheet at June 30, 2006 include the $106.9 million of expenditures related to this project.

Administrative Services Agreement. We have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement (“ASA”). Enterprise Products Partners, Enterprise Products GP, Enterprise GP Holdings, EPE Holdings, TEPPCO and TEPPCO GP, among other affiliates, are parties to the ASA. 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.

Relationships with unconsolidated affiliates

Our significant related party transactions with unconsolidated affiliates consist of the sale of natural gas to Evangeline 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.

14. Commitments and Contingencies

Litigation

On occasion, we are named as a defendant in litigation relating to our normal business activities, including regulatory and environmental matters. Although we insure against various business risks to the extent we believe 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 our ordinary business activities. We are not aware of any significant litigation, pending or threatened, that may have a significant adverse effect on our financial position, cash flows or results of operations.

A number of lawsuits have been filed by municipalities and other water suppliers against various manufacturers of reformulated gasoline containing methyl tertiary butyl ether (“MTBE”). In general, such suits have not named manufacturers of MTBE as defendants, and there have been no such lawsuits filed against our subsidiary that owns an octane-additive production facility. It is possible, however, that former MTBE manufacturers such as our subsidiary could ultimately be added as defendants in such lawsuits or in new lawsuits.

We acquired additional ownership interests in our octane-additive production facility from affiliates of Devon Energy Corporation (“Devon”), which sold us its 33.3% interest in 2003, and Sunoco, Inc. (“Sun”), which sold us its 33.3% interest in 2004. As a result of these acquisitions, we own 100% of our Mont Belvieu, Texas octane-additive production facility. Devon and Sun have indemnified us for any liabilities (including potential liabilities as described in the preceding paragraph) that are in respect of periods prior to the date we purchased such interests. There are no dollar limits or deductibles associated with the indemnities we received from Sun and Devon with respect to potential claims linked to the period of time they held ownership interests in our octane-additive production facility.

Operating leases

We lease certain property, plant and equipment under noncancelable and cancelable operating leases. Our significant lease agreements involve (i) the lease of underground caverns for the storage of natural gas and NGLs, (ii) leased office space with an affiliate of EPCO, and (iii) land held pursuant to right-of-way agreements. In general, our material lease agreements have original terms that range from 14 to 20 years and include renewal options that could extend the agreements for up to an additional 20 years.

There have been no material changes in our operating lease commitments since December 31, 2005, except for the renewal of our Wilson natural gas storage facility lease. During the first quarter of 2006, we exercised our right to renew the Wilson lease for an additional 20-year period. Our rental payments under the renewal agreement are at a fixed rate. Under the renewal agreement, we have the option to purchase the Wilson natural gas storage facility at either December 31, 2024 for $61 million or January 25, 2028 for $55 million. In addition, the lessor, at its election, may cause us to purchase the facility for $65 million at the end of any calendar quarter beginning on March 31, 2008 and extending through December 31, 2023. After adjusting for the renewal, the incremental future minimum lease payments associated with our lease of the Wilson natural gas storage facility are as follows: $4.1 million, 2008; $5.5 million, 2009; $5.5 million, 2010; and $94.9 million thereafter.

Performance guaranty

In December 2004, a subsidiary of the Operating Partnership entered into the Independence Hub Agreement (the “Hub Agreement”) with six oil and natural gas producers. The Hub Agreement, as amended, obligates the subsidiary (i) to construct an offshore platform production facility to process 1 Bcf/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 Hub Agreement, our Operating Partnership guaranteed the performance of its subsidiary under the Hub Agreement up to $426 million. In December 2004, 20% of this guaranteed amount was assumed by Helix Energy Solutions Group, Inc. (formerly known as Cal Dive International, Inc.), our joint venture partner in the Independence Hub project. The remaining $341 million represents our share of the anticipated construction cost of the platform facility. This amount represents the cap on our Operating Partnership’s potential obligation to the six producers for the cost of constructing the platform under the remote scenario where the six producers finish construction of the platform facility. This performance guarantee continues until the earlier to occur of (i) all of the guaranteed obligations of the subsidiary shall have been terminated, paid or otherwise discharged in full, (ii) upon mutual written consent of our Operating Partnership and the producers or (iii) mechanical completion of the production facility. We currently expect that mechanical completion of the platform will occur in January 2007; therefore, we anticipate that the performance guaranty will exist until at least this future period.

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 our Operating Partnership would be required to perform under this guaranty, we have estimated the fair value of the performance guaranty at approximately $1.2 million, which is a component of other current liabilities on our Unaudited Condensed Consolidated Balance Sheet at June 30, 2006.

15. Significant Risks and Uncertainties – Weather-Related Risks

EPCO renewed its property and casualty insurance programs during the second quarter of 2006. As a result of severe hurricanes such as Katrina and Rita that occurred in 2005, market conditions for obtaining property damage insurance coverage were difficult. Under our renewed insurance programs, coverage is more restrictive including increased physical damage and business interruption deductibles. For example, our deductible for onshore physical damage increased from $2.5 million to $5 million per event and our deductible period for onshore business interruption claims increased from 30 days to 60 days. Additional restrictions will also be applied in the event of damage from named windstorms.

In addition to changes in coverages, the cost of property damage insurance increased substantially from prior periods. At present, our annualized cost of insurance premiums for all lines of coverage is approximately $49.2 million, which represents a $28.1 million (or 133%) increase from our 2005 annualized insurance cost.

The following is a discussion of the general status of insurance claims related to significant storm events that affected our assets in 2004 and 2005. To the extent we include estimates regarding the dollar value of damages, please be aware that a change in our estimates may occur as additional information becomes available to us.

Hurricane Ivan insurance claims. Our final purchase price allocation related to the merger of GulfTerra with a wholly owned subsidiary of Enterprise Products Partners in September 2004 (the “GulfTerra Merger”) included a $26.2 million receivable for insurance claims related to expenditures to repair property damage to certain pre-merger GulfTerra assets caused by Hurricane Ivan. During the first quarter of 2006, we received cash reimbursements from insurance carriers totaling $24.1 million related to these property damage claims, and we expect to recover the remaining $2.1 million in late 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 first quarter of 2006, we received claim proceeds of $10.2 million, and in April 2006 we received an additional $2 million. To the extent we receive cash proceeds from business interruption insurance claims, they are recorded as a gain 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, evaluation and repair of property damage to our facilities is continuing. To the extent that insurance proceeds from property damage claims do not cover our estimated recoveries (in excess of the $5 million of insurance deductibles we expensed during the third quarter of 2005), such shortfall will be charged to earnings when realized. We recorded $63.5 million of estimated recoveries from property damage claims arising from Hurricanes Katrina and Rita, based on amounts expended through June 30, 2006. To the extent we receive cash proceeds from business interruption claims, they will be recorded as a gain in our statements of consolidated operations and comprehensive income in the period of receipt.

16. Condensed Financial Information of Operating Partnership

The Operating Partnership conducts substantially all of the business of Enterprise Products Partners. Currently, neither Enterprise Products GP nor Enterprise Products Partners have any independent operations and any material assets outside those of the Operating Partnership.

Enterprise Products Partners guarantees the debt obligations of its Operating Partnership, with the exception of the Dixie revolving credit facility and the senior subordinated notes assumed from GulfTerra. If the Operating Partnership were to default on any debt guaranteed by Enterprise Products Partners, Enterprise Products Partners would be responsible for full repayment of that obligation. For additional information regarding our consolidated debt obligations, see Note 10.

The reconciling items between our consolidated balance sheet and that of the Operating Partnership are substantially the same as the differences between our consolidated balance sheet and that of Enterprise Products Partners (see Note 1).

The following table shows condensed consolidated balance sheet data for the Operating Partnership at June 30, 2006:

ASSETS
Current assets		$ 2,000,077
Property, plant and equipment, net		9,018,275
Investments in and advances to unconsolidated affiliates, net		464,605
Intangible assets, net		909,323
Goodwill		493,995
Deferred tax asset		3,444
Other assets		147,578
	Total	$ 13,037,297

LIABILITIES AND PARTNERS' EQUITY
Current liabilities		$ 1,980,810
Long-term debt		4,821,401
Other long-term liabilities		131,201
Minority interest		124,497
Partners' equity		5,979,388
	Total	$ 13,037,297

Total Operating Partnership debt obligations guaranteed
by Enterprise Products Partners		$ 4,884,000

17. Subsequent Events

July 2006 Junior Notes Offering

In July 2006, the Operating Partnership sold $300 million in principal amount of fixed/floating, unsecured, long-term subordinated notes due 2066 (“Junior Notes A”). The Operating Partnership used the proceeds from issuing this subordinated debt to temporarily reduce borrowings outstanding under its Multi-Year Revolving Credit Facility and for general partnership purposes. The Operating Partnership’s payment obligations under Junior Notes A are subordinated to all of its current and future senior indebtedness (as defined in the Indenture Agreement). Enterprise Products Partners has guaranteed repayment of amounts due under Junior Notes A through an unsecured and subordinated guarantee.

The indenture agreement governing Junior Notes A allows the Operating Partnership to defer interest payments on one or more occasions for up to ten consecutive years subject to certain conditions. The indenture agreement also provides that, unless (i) all deferred interest on Junior Notes A has been paid in full as of the most recent interest payment date, (ii) no event of default under the Indenture has occurred and is continuing and (iii) Enterprise Products Partners is not in default of its obligations under related guarantee agreements, then the Operating Partnership and Enterprise Products Partners cannot declare or make any distributions with respect to any of their respective equity securities or make any payments on indebtedness or other obligations that rank pari passu with or subordinate to Junior Notes A.

The Junior Notes A will bear fixed rate interest of 8.375% from July 2006 to August 2016, payable semi-annually in arrears in February and August of each year, commencing in February 2007. Thereafter, the Junior Notes A will bear variable rate interest at an annual rate equal to the 3-month LIBOR rate for the related interest period plus 3.708%, payable quarterly in arrears in February, May, August and November of each year commencing in November 2016. Interest payments may be deferred on a cumulative basis for up to ten consecutive years, subject to the certain provisions. The Junior Notes A mature in August 2066 and are not redeemable by the Operating Partnership prior to August 2016 without payment of a make-whole premium.

In connection with the issuance of Junior Notes A, the Operating Partnership entered into a Replacement Capital Covenant in favor of the covered debtholders (as named therein) pursuant to which the Operating Partnership agreed for the benefit of such debtholders that it would not redeem or repurchase such junior notes unless such redemption or repurchase is made from the proceeds of issuance of certain securities.

July 2006 Acquisition of Natural Gas Gathering Assets in South Texas

In July 2006, we acquired certain natural gas gathering systems and related gathering and processing contracts from Cerrito Gathering Company, Ltd. (“Cerrito”), an affiliate of Lewis Energy Group, L.P. (“Lewis”). The total consideration paid by us was $325 million, which consisted of approximately $146 million in cash and the issuance of approximately 7.1 million of Enterprise Products Partners’ common units.

The Cerrito gathering systems are located in South Texas and are connected to over 1,450 wells having an aggregate production volume of over 100 MMcf/d of natural gas sourced from the Olmos and Wilcox Trends in South Texas. The Cerrito gathering systems consist of 484 miles of pipeline, comprised of 312 miles of pipeline we acquired from Lewis in this transaction and 172 miles of pipeline that we own and had previously leased to Lewis. The Cerrito gathering system is supported by 31,000 horsepower of compression. Volumes currently gathered by the Cerrito systems are delivered into our South Texas gas processing and pipeline transportation system.

These gathering systems will be supported by a long-term dedication by Lewis of its production from the Olmos formation. In addition to the natural gas gathering and processing dedication, the transaction also includes a long-term dedication to transport lean gas gathered and treated at Lewis’ Big

Reef Treating facility. The Big Reef facility will gather and treat sour gas production from the southern portion of the Edwards Trend in South Texas.

August 2006 Purchase of NGL Pipeline

In August 2006, we purchased 226 miles of NGL pipelines extending from Corpus Christi, Texas to Pasadena, Texas from ExxonMobil Pipeline Company. The total purchase price for these assets was $97.9 million in cash. We funded this asset purchase using borrowings under the Operating Partnership’s Multi-Year Revolving Credit Facility. This pipeline will be used to transport mixed NGLs from our South Texas natural gas processing plants to our Mont Belvieu fractionation facilities.