EXHIBIT 99.1

Enterprise Products GP, LLC

Unaudited Condensed Consolidated Balance Sheet at September 30, 2006

ENTERPRISE PRODUCTS GP, LLC

TABLE OF CONTENTS

		Page No.

Unaudited Condensed Consolidated Balance Sheet at September 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	7
	Note 4 – Financial Instruments	9
	Note 5 – Inventories	10
	Note 6 – Property, Plant and Equipment	11
	Note 7 – Investments in and Advances to Unconsolidated Affiliates	12
	Note 8 – Business Combinations	13
	Note 9 – Intangible Assets and Goodwill	15
	Note 10 – Debt Obligations	16
	Note 11 – Member’s Equity	19
	Note 12 – Business Segments	19
	Note 13 – Related Party Transactions	20
	Note 14 – Commitments and Contingencies	22
	Note 15 – Significant Risks and Uncertainties – Weather-Related Risks	24
	Note 16 – Condensed Financial Information of Operating Partnership	26
	Note 17 – Subsequent Events	26

ENTERPRISE PRODUCTS GP, LLC

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET

AT SEPTEMBER 30, 2006

(Dollars in thousands)

ASSETS
Current assets
	Cash and cash equivalents			$ 117,432
	Restricted cash			21,155
	Accounts and notes receivable – trade, net of allowance
		for doubtful accounts of $19,368		1,356,778
	Accounts receivable – related parties			25,066
	Inventories			462,278
	Prepaid and other current assets			171,469
			Total current assets	2,154,178
Property, plant and equipment, net				9,401,669
Investments in and advances to unconsolidated affiliates				540,186
Intangible assets, net of accumulated amortization of $228,676				1,018,695
Goodwill				591,497
Deferred tax asset				3,054
Other assets				47,171
			Total assets	$ 13,756,450

LIABILITIES AND MEMBER'S EQUITY
Current liabilities
	Accounts payable - trade			$ 276,086
	Accounts payable - related parties			28,295
	Accrued gas payables			1,436,504
	Accrued expenses			29,477
	Accrued interest			80,528
	Other current liabilities			231,343
			Total current liabilities	2,082,233
Long-term debt				4,884,261
Other long-term liabilities				102,727
Minority interest				6,134,997
Commitments and contingencies
Member's equity				552,232
			Total liabilities and member's equity	$ 13,756,450

See Notes to Unaudited Condensed Consolidated Balance Sheet

ENTERPRISE PRODUCTS GP, LLC

NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET

AT SEPTEMBER 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.

On November 2, 2006, a newly formed and wholly owned subsidiary of Enterprise Products Partners, Duncan Energy Partners L.P. (“Duncan Energy Partners”), filed its initial registration statement for a proposed public offering of its common units. Duncan Energy Partners will own interests in certain of Enterprise Products Partners’ midstream energy businesses. For additional information regarding this subsequent event, please read Note 17.

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 September 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 nine months ended September 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 affecting our financial position

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.

Financial Accounting Standards Board Interpretation (“FIN”) No. 48, “Accounting for Uncertainty in Income Taxes, an Interpretation of SFAS 109, Accounting for Income Taxes.” FIN 48 provides that tax effects of an uncertain tax position should be recognized in a company’s financial statements if the position taken by the entity is more likely than not sustainable, if it were to be examined by an appropriate taxing authority, based on technical merit. After determining a tax position meets such criteria, the amount of benefit to be recognized should be the largest amount of benefit that has more than a 50 percent chance of being realized upon settlement. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006. We are currently assessing the impact, if any, the adoption of FIN 48 will have on our financial position.

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.

SFAS 157, “Fair Value Measurements.” This accounting standard defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. SFAS 157 applies only to fair-value measurements that are already required or permitted by other accounting standards and is expected to increase the consistency of those measurements. The statement emphasizes that fair value is a market-based measurement that should be determined based on the assumptions that market participants would use in pricing an asset or liability. Companies will be required to disclose the extent to which fair value is used to measure assets and liabilities, the inputs used to develop the measurements, and the effect of certain of the measurements on earnings (or changes in net assets) for the period. SFAS 157 is effective for fiscal years beginning after December 15, 2007 and we will be required to adopt SFAS 157 as of January 1, 2008. We are currently evaluating the impact of adopting SFAS 157 on our financial position.

SFAS 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R).” This accounting standard requires an employer to recognize the over-funded or under-funded status of its defined benefit pension and other postretirement plans as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income. In addition, SFAS 158 eliminates the use of a measurement date that is different than the date of the employer's year-end financial statements. SFAS 158 requires an employer to disclose in the notes to financial statements additional information about certain effects on net periodic benefit cost for the next fiscal year that arise from delayed recognition of the gains or losses, prior service costs or credits, and transition asset or obligation. Under SFAS 158, we will be required to recognize the funded status of our defined benefit pension and postretirement plans and to provide the required disclosures commencing as of December 31, 2006. We do not believe the adoption of SFAS 158 will have a material effect on our financial position. For additional information regarding our accounting for employee benefit plans, please see “Accounting for employee benefit plans” in this Note 2.

Staff Accounting Bulletin (“SAB”) No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements.” SAB 108 addresses how the effects of prior-year uncorrected misstatements should be considered when quantifying misstatements in current-year financial statements. The SAB requires registrants to quantify misstatements using both the balance-sheet and income-statement approaches and to evaluate whether either approach results in quantifying an error that is material in light of relevant quantitative and qualitative factors. When the effect of initial adoption is determined to be material, SAB 108 allows registrants such as ourselves to record the effect as a cumulative-effect adjustment to beginning-of-year equity accounts. The requirements are effective for annual financial statements covering the first fiscal year ending after November 15, 2006. Additionally, the nature and amount of each individual error being corrected through the cumulative-effect adjustment, when and how each error arose, and the fact that the errors had previously been considered immaterial is required to be disclosed. We are required to adopt SAB 108 for our current fiscal year ending December 31, 2006. We do not expect the adoption of SAB 108 to have a material impact on our financial.

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 $0.1 million to its postretirement benefit plan and approximately $1 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 September 30, 2006:

Limited partners of Enterprise Products Partners:
	Non-affiliates of Enterprise Products GP	$ 5,267,480
	Affiliates of Enterprise Products GP	741,273
Joint venture partners		126,244
	Total minority interest on consolidated balance sheet	$ 6,134,997

Minority interest attributable to the limited partners of Enterprise Products Partners consists of common units held by the public and affiliates of EPCO. Minority interest attributable to consolidated joint ventures at September 30, 2006, primarily represents our partners in Tri-States NGL Pipeline LLC, Seminole Pipeline Company (“Seminole”), Wilprise Pipeline Company, LLC, Independence Hub, LLC, Dixie and Belle Rose NGL Pipeline LLC.

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 conduct business in Texas are subject to the Texas Margin Tax. Limited partnerships, limited liability companies, corporations and limited liability partnerships 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 will change 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 (i) 70% of total revenue or (ii) 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. On a consolidated basis, we recorded an estimated net deferred tax liability of approximately $6.6 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, as a benefit, a cumulative effect of change in accounting principle of $1.5 million, which $1.4 million 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	(155,000)	$ 15.14
	Forfeited	(45,000)	$ 24.28
Outstanding at September 30, 2006		2,472,000	$ 23.20	7.79	$ 3,872

Exercisable at September 30, 2006		622,000	$ 20.53	5.24	$ 3,872

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

The total intrinsic value of Enterprise Products Partners’ unit options exercised during the three and nine months ended September 30, 2006 was $1.1 million and $1.7 million, respectively. During the nine months ended September 30, 2006, we received cash of $4 million from the exercise of unit options, and our option-related reimbursements to EPCO were $1.7 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 1,956,433 remain authorized for issuance at September 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 nine months ended September 30, 2006.

			Weighted-
		Number of	average grant
		Units	date fair value
Restricted units at December 31, 2005		751,604	$ 24.49
	Granted	410,400	$ 24.90
	Vested	(39,711)	$ 23.91
	Forfeited	(70,631)	$ 24.16
Restricted units at September 30, 2006		1,051,662	$ 24.70

The total fair value of Enterprise Products Partners’ restricted units that vested during the three and nine months ended September 30, 2006 was $1 million.

Employee Partnership

In connection with the initial public offering of Enterprise GP Holdings in August 2005, EPE Unit L.P. (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 substantially all of EPE Holdings’ and Enterprise Products GP’s executive officers other than Dan L. Duncan, were 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 is 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 ranging from four to five years; (ii) risk-free interest rates ranging from 4.1% to 4.8%; (iii) an expected distribution yield on units of Enterprise GP Holdings ranging from 3.0% to 3.7%; and (iv) an expected Enterprise GP Holdings unit price volatility ranging from 21.1% to 30.0%. 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 September 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 8.89%	$50 million
Senior Notes C, 6.375% fixed rate, due Feb. 2013		2	Jan. 2004 to Feb. 2013	Feb. 2013	6.375% to 7.43%	$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 September 30, 2006 and December 31, 2005, was a liability of $30.4 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 during the second quarter of 2006. In July 2006, the Operating Partnership issued $300 million in principal amount of its Junior Notes A (see Note 10). 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 price 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) the value of 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 September 30, 2006 and December 31, 2005 was a benefit of $4.8 million and a liability of $0.1 million, respectively.

5. Inventories

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

Working inventory	$ 397,939
Forward-sales inventory	64,339
Inventory	$ 462,278

Our regular trade (or “working”) inventory is comprised of inventories of natural gas, NGLs, and certain 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 September 30, 2006, our property, plant and equipment and accumulated depreciation were as follows:

	Estimated
	Useful Life
	in Years
Plants and pipelines ⁽¹⁾	3-35 ⁽⁵⁾	$ 8,704,110
Underground and other storage facilities ⁽²⁾	5-35 ⁽⁶⁾	574,641
Platforms and facilities ⁽³⁾	23-31	161,880
Transportation equipment ⁽⁴⁾	3-10	24,806
Land		39,624
Construction in progress		1,304,698
Total		10,809,759
Less accumulated depreciation		1,408,090
Property, plant and equipment, net		$ 9,401,669

(1) Plants and pipelines include 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 include underground product storage caverns; storage tanks; water wells; and related assets. (3) Platforms and facilities include 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).

In March 2006, we paid $38.2 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. After completing this asset purchase, we increased the capacity of the Pioneer natural gas processing plant at an additional cost of $21 million. This expansion was completed in July 2006 and enables us to process natural gas production from the Jonah and Pinedale fields that will be transported to our Wyoming facilities as a result of the contract rights we acquired from TEPPCO. Of the $38.2 million we paid TEPPCO to acquire the Pioneer facility, $37.8 million was allocated to the contract rights we acquired. See Note 9 for information regarding the intangible assets recorded in connection with this asset purchase.

In August 2006, we acquired a 223-mile pipeline from ExxonMobil Pipeline Company for $97.7 million in cash. This pipeline originates in Corpus Christi, Texas and extends to Pasadena, Texas. This pipeline segment will be expanded (the “Phase I expansion”) to (i) connect with our Armstrong and Shoup NGL fractionation facilities through the construction of 45 miles of pipeline laterals; (ii) lease from TEPPCO a 10-mile interconnecting pipeline extending from Pasadena, Texas to Baytown, Texas; and (iii) purchase an additional 10-mile pipeline from TEPPCO that will connect the leased TEPPCO pipeline to Mont Belvieu, Texas. The purchase of the 10-mile segment from TEPPCO is estimated to cost $8 million and be completed during the fourth quarter of 2006. The primary term of the TEPPCO pipeline lease will expire in July 2007, and will continue on a month-to-month basis subject to customary termination provisions. Collectively, this 288-mile pipeline will be termed the South Texas NGL pipeline system. The South Texas NGL pipeline system is not in operation, but it is currently undergoing modifications, extensions and interconnections as described above to allow it to transport NGLs beginning in January 2007.

During 2007, we will construct an additional 21 miles of pipeline (the “Phase II upgrade”) to replace (i) the 10-mile pipeline we will lease from TEPPCO and (ii) certain segments of the pipeline we acquired in August 2006 from ExxonMobil Pipeline Company. The Phase II upgrade is expected to provide a significant increase in pipeline capacity and be operational during the third quarter of 2007.

We estimate the cost of the Phase I expansion to be $37.7 million, which includes the $8 million we will pay TEPPCO to acquire its 10-mile Baytown to Mont Belvieu pipeline. We expect the Phase II upgrade to cost an additional $30.9 million.

The South Texas NGL pipeline system will be owned by our new subsidiary, South Texas NGL Pipelines, LLC. Please see Note 17 for a subsequent event involving this subsidiary.

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 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 September 30, 2006.

		Ownership
		Percentage
NGL Pipelines & Services:
	Venice Energy Services Company, LLC (“VESCO”)	13.1%	$ 39,572
	K/D/S Promix LLC (“Promix”)	50%	54,111
	Baton Rouge Fractionators LLC (“BRF”)	32.3%	25,332
Onshore Natural Gas Pipelines & Services:
	Jonah Gas Gathering Company (“Jonah”)⁽¹⁾	11%⁽²⁾	83,294
	Evangeline ⁽³⁾	49.5%	3,907
	Coyote Gas Treating, LLC (“Coyote”)⁽⁴⁾	50%
Offshore Pipelines & Services:
	Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”)	36%	64,852
	Cameron Highway Oil Pipeline Company (“Cameron Highway”)	50%	58,828
	Deepwater Gateway, L.L.C. (“Deepwater Gateway”)	50%	120,777
	Neptune Pipeline Company, L.L.C. (“Neptune”)	25.7%	59,867
	Nemo Gathering Company, LLC (“Nemo”)	33.9%	10,682
Petrochemical Services:
	Baton Rouge Propylene Concentrator, LLC (“BRPC”)	30%	14,343
	La Porte ⁽⁵⁾	50%	4,621
Total			$ 540,186

(1) In August 2006, we announced a 50/50 common control joint venture in which we and TEPPCO will be partners in Jonah. Jonah owns the Jonah Gas Gathering System located in the Greater Green River Basin of southwestern Wyoming. This system gathers and transports natural gas produced from the Jonah and Pinedale fields to regional natural gas processing plants and major interstate pipelines that deliver natural gas to end users. See Note 13 for additional information regarding the Jonah joint venture with TEPPCO. (2) Upon completion of the Jonah Phase V expansion project in 2007 (see Note 13), we expect to own an approximate 20% equity interest in Jonah, with TEPPCO owning the remaining 80%. Our equity interest in Jonah at September 30, 2006 is approximately 11% based on capital contributions made by us through this date. TEPPCO is entitled to all distributions from the joint venture until specified milestones are achieved, at which point, we will be entitled to receive 50% of the incremental cash flow from portions of the system placed in service as part of the expansion. (3) Refers to our ownership interests in Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp., collectively. (4) We sold our 50% interest in Coyote in August 2006. (5) Refers to our ownership interests in La Porte Pipeline Company, L.P. and La Porte GP, LLC, collectively.

Equity method investments are evaluated for impairment when events or changes in circumstances indicate there is a loss in value of the investment which is an other than temporary decline. In the event we determine that the loss in value of an investment is other than a temporary decline, we would record a charge to earnings to adjust the carrying value to fair value.

Neptune owns the Manta Ray Offshore Gathering System (“Manta Ray”) and Nautilus Pipeline System (“Nautilus”). Manta Ray gathers natural gas originating from producing fields located in the Green Canyon, Southern Green Canyon, Ship Shoal, South Timbalier and Ewing Bank areas of the Gulf of Mexico to numerous downstream pipelines, including the Nautilus pipeline. Nautilus connects our Manta Ray pipeline to our Neptune natural gas processing plant located in South Louisiana. Due to a recent decrease in throughput volumes on the Manta Ray and Nautilus pipelines, we evaluated our 25.7% investment in Neptune for impairment during the third quarter of 2006. The decrease in throughput volumes is primarily due to underperformance of certain fields, natural depletion and hurricane-related delays in starting new production. These factors contributed to significant delays in throughput volumes Neptune expects to receive. As a result, Neptune has experienced operating losses in recent periods.

At December 31, 2005, the carrying value of our investment in Neptune was $68.1 million, which included $10.9 million of excess cost related to its original acquisition in 2001. Our review of Neptune’s estimated cash flows during the third quarter of 2006 indicated that the carrying value of our investment exceeded its fair value, which resulted in a non-cash impairment charge of $7.4 million. After recording this impairment charge, the carrying value of our investment in Neptune at September 30, 2006 was $59.9 million, which reflects $0.7 million in losses and $0.1 million of distributions we recorded during the first nine months of 2006.

Our investment in Neptune was written down to fair value, which management prepared using recognized business valuation techniques. The fair value analysis is based upon management’s expectation of future cash flows. Such expectation of future cash flows incorporates industry information and assumptions made by management. For example, the review of Neptune included management estimates regarding natural gas reserves of producers served by the Neptune pipelines. If the assumptions underlying our fair value analysis change and expected cash flows are reduced, additional impairment charges may result.

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 September 30, 2006, our investments in Promix, La Porte, Neptune, Poseidon, Cameron Highway and Nemo included excess cost amounts totaling $39.1 million, all of which was attributed to fair values in excess of the underlying carrying values of tangible assets at the time of our acquisition of interests in these entities. Amortization of such excess cost amounts was $0.5 million during each of the three month periods ended September 30, 2006 and 2005. For the nine months ended September 30, 2006 and 2005, amortization of such amounts was $1.6 million and $1.7 million, respectively.

8. Business Combinations

Effective July 1, 2006, we acquired the Encinal and Canales natural gas gathering systems and related gathering and processing contracts and other amounts that comprised the South Texas natural gas transportation and processing business of an affiliate of Lewis Energy Group, L.P. (“Lewis”). The aggregate value of total consideration we paid or issued to complete this business combination (referred to as the “Encinal acquisition”) was $326.1 million, consisting of $145 million in cash and 7,115,844 of Enterprise Products Partners’ common units.

The Encinal and Canales gathering systems are located in South Texas and are connected to over 1,450 natural gas production wells tapped into the Olmos and Wilcox formations. The Encinal system consists of 452 miles of pipeline, which is comprised of 280 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 Canales gathering system is comprised of 32 miles of pipeline. Currently, volumes gathered by the Encinal and

Canales systems are transported by our existing South Texas pipeline system and are processed by our South Texas natural gas processing plants.

As part of this transaction, we acquired long-term natural gas processing and gathering dedications from Lewis. First, these gathering systems will be supported by a life of reserves gathering and processing dedication of Lewis’ natural gas production from the Olmos formation. Second, Lewis entered into a 10-year agreement with us for the transportation of natural gas treated at its Big Reef facility. This facility processes natural gas production from the southern portion of the Edwards Trend in South Texas. Third, Lewis entered into a 10-year gathering and processing agreement with Enterprise Products Partners for rich gas developed below the Olmos formation.

The total consideration paid or granted for the Encinal acquisition is summarized in the following table:

Cash consideration, including third-party direct transaction costs		$ 144,973
Fair value of our 7,115,844 common units issued to Lewis		181,112
	Total consideration	$ 326,085

In accordance with purchase accounting, the value of Enterprise Products Partners common units issued to Lewis is based on the average closing price of such units immediately prior to and after the transaction was announced on July 12, 2006. The average closing price used was $25.45 per unit.

Purchase price allocation

This acquisition was accounted for under the purchase method of accounting and, accordingly, its cost has been allocated to the assets acquired and liabilities assumed based on estimated preliminary fair values. Such preliminary values have been developed using recognized business valuation techniques and are subject to change pending a final valuation report. We expect to finalize the purchase price allocation for this transaction during the third quarter of 2007.

Purchase price allocation:
	Assets acquired in business combination:
		Current assets		$ 218
		Property, plant and equipment, net		100,310
		Intangible assets		132,872
			Total assets acquired	233,400
	Liabilities assumed in business combination:
		Current liabilities		(2,149)
		Other long-term liabilities		(108)
			Total liabilities assumed	(2,257)
			Total assets acquired less liabilities assumed	231,143
			Total consideration given	326,085
	Remaining Goodwill			$ 94,942

As a result of our preliminary purchase price allocation, we recorded $132.9 million of amortizable intangible assets. The remaining preliminary amount represents goodwill of $94.9 million, which management attributes to potential future benefits we may realize from our other South Texas processing and NGL businesses as a result of the Encinal acquisition. Specifically, the long-term dedication rights acquired in connection with the Encinal acquisition are expected to add value to our South Texas processing facilities and related NGL businesses due to increased volumes. For additional information regarding our intangible assets and goodwill, see Note 9.

9. Intangible Assets and Goodwill

Identifiable Intangible assets

The following table summarizes our intangible assets by business segment at September 30, 2006. Our intangible assets primarily consist of values we assigned to contracts and customer relationships.

	Gross	Accum.	Carrying
Business Segment	Value	Amort.	Value
NGL Pipelines & Services ^(1,2)	$ 520,134	$ (101,459)	$ 418,675
Onshore Natural Gas Pipelines & Services⁽²⁾	463,551	(69,136)	394,415
Offshore Pipelines & Services	207,012	(49,385)	157,627
Petrochemical Services	56,674	(8,696)	47,978
Total	$ 1,247,371	$ (228,676)	$ 1,018,695

(1) In March 2006, we recorded an additional $37.8 million of contract-based intangible assets in connection with our acquisition of the Pioneer natural gas processing plant and associated natural gas processing rights. See Note 6 for additional information regarding this asset purchase. (2) In July 2006, we recorded an additional $132.9 million of customer relationship intangible assets in connection with our acquisition of the Encinal midstream energy business from Lewis. The amortization period for these intangible assets is 20 years. See Note 8 for additional information regarding this business combination.

Goodwill

The following table summarizes our goodwill amounts by segment at September 30, 2006.

NGL Pipelines & Services		$ 152,444
Onshore Natural Gas Pipelines & Services		282,977
Offshore Pipelines & Services		82,386
Petrochemical Services		73,690
	Totals	$ 591,497

In August 2006, we recorded $94.9 million of goodwill in connection with our preliminary purchase price allocation for the Encinal acquisition. Management attributes this goodwill amount to potential future benefits we may realize from our other South Texas processing and NGL businesses as a result of acquiring the Encinal business. Specifically, our acquisition of the long-term dedication rights associated with the Encinal business is expected to add value to our South Texas processing facilities and related NGL businesses due to increased volumes. The Encinal goodwill is recorded as part of the NGL Pipelines & Services business segment due to management’s belief that such future benefits will accrue to businesses classified within this segment.

The remainder of our goodwill is associated with previous acquisitions, principally the $387.1 million recorded in connection with the merger of GulfTerra Energy Partners, L.P. with a wholly owned subsidiary of Enterprise Products Partners in September 2004.

10. Debt Obligations

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

Operating Partnership debt obligations:
	Multi-Year Revolving Credit Facility, variable rate, due October 2011 ⁽¹⁾
	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 ⁽²⁾			10,000
Debt obligations assumed from GulfTerra			5,068
		Total principal amount of senior obligations	4,369,068
Junior Notes A, due August 2066			550,000
Total principal amount of senior and junior debt obligations			4,919,068
Other, including unamortized discounts and premiums and changes in fair value ⁽³⁾			(34,807)
		Long-term debt	$ 4,884,261

Standby letters of credit outstanding			$ 53,158

(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 maturity date of this facility was extended from June 2007 to June 2010 in August 2006. The other terms of the Dixie facility remain unchanged from those described in our annual report on Form 10-K for the year ended December 31, 2005. (3) The September 30, 2006 amount includes $21.3 million related to fair value hedges and $13.5 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 Enterprise Products Partners’ annual report on Form 10-K for the year ended December 31, 2005.

Multi-Year Revolving Credit Facility. At September 30, 2006, we did not have any amounts outstanding under this 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 $550 million in principal amount of Junior Notes A issued by the Operating Partnership during the third quarter of 2006 (see below).

In March 2006, Enterprise Products Partners generated net proceeds of $430 million in connection with the sale of 18,400,000 of our common units in an underwritten equity offering. In addition, in September 2006, Enterprise Products Partners generated net proceeds of $320.8 million in connection with the sale of 12,650,000 of our common units in an underwritten equity offering. Subsequently, these amounts were contributed to the Operating Partnership, which, in turn, primarily used the amounts to temporarily reduce debt outstanding under its Multi-Year Revolving Credit Facility.

Junior Notes A. The Operating Partnership sold $550 million in principal amount of fixed/floating, unsecured, long-term subordinated notes due 2066 (“Junior Notes A”) during the third quarter of 2006. The Operating Partnership used the proceeds from 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 interest at a fixed annual rate 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. After August 2016, 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 debt holders (as named therein) pursuant to which the Operating Partnership agreed for the benefit of such debt holders 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.

Covenants

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

Information regarding variable interest rates paid

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

	Range of	Weighted-average
	interest rates	interest rate
	paid	paid
Operating Partnership’s Multi-Year Revolving Credit Facility	4.87% to 8.25%	5.53%
Dixie Revolving Credit Facility	4.67% to 5.79%	5.18%

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	$ 500,000
2009	500,000
2010	569,068
Thereafter	3,350,000
Total scheduled principal payments	$ 4,919,068

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 September 30, 2006, (ii) total debt of each unconsolidated affiliate at September 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 unconsolidated affiliates contain various affirmative and negative covenants, including financial covenants. These businesses were in compliance with such covenants at September 30, 2006.

Amendment of Cameron Highway debt agreement. 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 agreement. 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 September 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	$ 4,880		4,880
Reclassification of gain on settlement of interest rate financial instruments		(3,158)	(3,158)
Balance, September 30, 2006	$ 4,880	$ 15,914	$ 20,794

During the remainder of 2006, we will reclassify $1.1 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 enter our asset system in a number of ways, such as an offshore natural gas or crude oil pipeline, an offshore platform, a natural gas processing plant, an onshore natural gas gathering pipeline, an NGL fractionator, an NGL storage facility or an NGL transportation or distribution pipeline.

Consolidated property, plant and equipment and investments in and advances to unconsolidated affiliates are assigned to each segment on the basis of each asset’s or investment’s principal operations. The principal reconciling difference 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 that 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 placed in service. Consolidated intangible assets and goodwill are assigned 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:

			Reportable Segments
			NGL	Onshore	Offshore		Adjustments
			Pipelines	Pipelines	Pipelines	Petrochemical	and	Consolidated
			& Services	& Services	& Services	Services	Eliminations	Totals
Segment assets:
		At September 30, 2006	$ 3,180,179	$ 3,667,364	$ 743,341	$ 506,087	$ 1,304,698	$ 9,401,669
Investments in and advances to
	unconsolidated affiliates (see Note 7):
		At September 30, 2006	119,015	87,201	315,006	18,964		540,186
Intangible Assets (see Note 9):
		At September 30, 2006	418,675	394,415	157,627	47,978		1,018,695
Goodwill (see Note 9):
		At September 30, 2006	152,444	282,977	82,386	73,690		591,497

13. Related Party Transactions

Relationship with EPCO and affiliates

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 private company 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.

Our revenues from EPCO and its other affiliates (including TEPPCO) were $86.9 million and $0.3 million for the nine months ended September 30, 2006 and 2005, respectively. Our operating costs and expenses paid to these related parties were $244.6 million and $189.1 million for the nine months ended September 30, 2006 and 2005, respectively. Our general and administrative costs paid to EPCO were $33 million and $28.5 million for the nine months ended September 30, 2006 and 2005, respectively.

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 September 30, 2006, EPCO and its affiliates beneficially owned 146,379,464 (or 33.9%) of the outstanding common units of Enterprise Products Partners. In addition, at September 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 $225.5 million and $243.9 million in cash distributions from us during the nine months ended September 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 Canadian affiliate of EPCO at market-related prices in the normal course of business. We acquired this foreign affiliate in October 2006. See Note 17 for additional information regarding this acquisition.

The general partner of TEPPCO and 2,500,000 common units of TEPPCO are owned by a private company subsidiary of EPCO. See Note 14 for recent litigation involving us and TEPPCO.

In March 2006, we paid $38.2 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. After an in-depth consideration of relevant factors, this transaction was approved by the Audit and Conflicts Committee of our general partner, and the Audit and Conflicts Committee of the general partner of TEPPCO. In addition, each party received a fairness opinion rendered by an independent advisor. TEPPCO will have no continued involvement in the contracts or in the operations of the Pioneer facility. 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 (“Jonah”). Jonah owns the Jonah Gas Gathering System (“the Jonah system”), located in the Greater Green River Basin of southwestern Wyoming. The Jonah system gathers and transports natural gas produced from the Jonah and Pinedale fields to regional natural gas processing plants and major interstate pipelines that deliver natural gas to end-use markets.

Prior to entering into the Jonah joint venture, we managed the construction of the Phase V expansion and funded the initial construction costs under a letter of intent we entered into in February 2006. In connection with the joint venture arrangement, we and TEPPCO intend to continue the Phase V expansion, which is expected to increase the 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 expected 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 $295 million. The second portion of the expansion is expected to cost approximately $170 million and be completed by the end of 2007.

We will continue to manage the Phase V construction project. TEPPCO is entitled to all distributions from the joint venture until specified milestones are achieved, at which point, we will be entitled to receive 50% of the incremental cash flow from portions of the system placed in service as part of the expansion. After subsequent milestones are achieved, we and TEPPCO will share distributions based on a formula that takes into account the respective capital contributions of the parties, including expenditures by TEPPCO prior to the expansion. From August 1, 2006, we and TEPPCO equally share in the construction costs of the Phase V expansion.

In the third quarter of 2006, TEPPCO reimbursed us $65 million for 50% of the Phase V cost incurred through August 1, 2006 (including carrying costs of $1.3 million). We had a receivable of $18.9 million from TEPPCO at September 30, 2006, for costs incurred through September 30, 2006. Upon completion of the expansion project and based on the formula in the joint venture partnership agreement, we expect to own an interest in Jonah of approximately 20%, with TEPPCO owning the remaining 80%. We will operate the system.

The Jonah joint venture is governed by a management committee comprised of two representatives approved by us and two appointed by TEPPCO, each with equal voting power. After an in-depth consideration of relevant factors, this transaction was approved by the Audit and Conflicts Committee of our general partner and the Audit and Conflicts Committee of the general partner of TEPPCO. In addition, each party received a fairness opinion rendered by an independent advisor.

We will account for our investment in the Jonah joint venture using the equity method. As a result of entering into the Jonah joint venture, we reclassified $52.1 million expended on this project through July 31, 2006 (representing our 50% share) from Other Assets to Investments in Unconsolidated Affiliates. The remaining $52.1 million we spent through this date is included in the $65 million we billed TEPPCO (see above). See Note 7 for information regarding our investments in unconsolidated affiliates.

We have agreed to indemnify TEPPCO from any and all losses, claims, demands, suits, liability, costs and expenses arising out of or related to breaches of our representations, warranties, or covenants related to the Jonah joint venture. A claim for indemnification cannot be filed until the losses suffered by TEPPCO exceed $1 million. The maximum potential amount of future payments under the indemnity agreement is limited to $100 million. All indemnity payments are net of insurance recoveries that TEPPCO may receive from third-party insurers. We carry insurance coverage that may offset any payments required under the indemnification.

See Note 6 for information regarding our purchase and lease of certain pipeline segments from TEPPCO during the fourth quarter of 2006.

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.

Our revenues from unconsolidated affiliates were $249 million and $257.8 million for the nine months ended September 30, 2006 and 2005, respectively. Our operating costs and expenses paid to these related parties were $19.1 million and $21.9 million for the nine months ended September 30, 2006 and 2005, respectively.

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.

On September 18, 2006, Peter Brinckerhoff, a purported unitholder of TEPPCO, filed a complaint in the Court of Chancery of New Castle County in the State of Delaware, in his individual capacity, as a putative class action on behalf of other unitholders of TEPPCO, and derivatively on behalf of TEPPCO, concerning, among other things, certain transactions involving TEPPCO and Enterprise Products Partners or its affiliates. The complaint names as defendants (i) TEPPCO, its directors, and certain of its affiliates; (ii) Enterprise Products Partners and certain of its affiliates, including the Enterprise GP Holdings; (iii) EPCO, Inc.; and (iv) Dan L. Duncan. The complaint alleges, among other things, that the defendants have caused TEPPCO to enter into certain transactions with us or our affiliates that are unfair to TEPPCO or otherwise unfairly favored us or our affiliates over TEPPCO. These transactions are alleged to include the joint venture to further expand the Jonah system entered into by TEPPCO and one of our affiliates in August 2006 (see Note 13) and the sale by TEPPCO to one of our affiliates of the Pioneer gas processing plant in March 2006 (see Note 6). The complaint seeks (i) rescission of these transactions or an award of rescissory damages with respect thereto; (ii) damages for profits and special benefits allegedly obtained by defendants as a result of the alleged wrongdoings in the complaint; and (iii) awarding plaintiff costs of the action, including fees and expenses of his attorneys and experts. We believe this lawsuit is without merit and intend to vigorously defend against it.

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 the first quarter of 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 September 30, 2006.

Other Claims

As part of our normal industry business activities with joint venture partners and certain customers and suppliers, we occasionally make claims against such parties or have claims made against us as a result of disputes related to contractual agreements or similar arrangements. As of September 30, 2006, our contingent claims against such parties were approximately $2 million and claims against us were approximately $34 million. These matters are in various stages of assessment and the ultimate outcome of such disputes cannot be reasonably estimated. However, in our opinion, the likelihood of a material adverse outcome related to disputes against us is remote. Accordingly, accruals for loss contingencies related to these matters, if any, that might result from the resolution of such disputes have not been reflected in our consolidated financial statements.

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 coverage, 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 nine months 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.

In addition, we have submitted business interruption insurance claims for our estimated losses caused by Hurricane Ivan. During the first nine months of 2006, we received claim proceeds of $17.4 million.

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. 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 $81.4 million of estimated recoveries from property damage claims arising from Hurricanes Katrina and Rita, based on amounts expended through September 30, 2006. During the first nine months of 2006, we received $9.7 million of physical damage proceeds.

In addition, during the first nine months of 2006 we received $45.1 million of business interruption proceeds. We estimate that up to $25 million of additional business interruption proceeds could be received by the end of 2007. Such additional amounts are subject to the review and concurrence of our insurers. Reviews of the outstanding claims are ongoing.

The following table summarizes our cash receipts with respect to business interruption and property damage proceeds for Hurricanes Ivan, Katrina and Rita for the periods indicated.

		For The	For The
		Three Months	Nine Months
		Ended	Ended
		September 30,	September 30,
		2006	2006
Business interruption proceeds:
	Hurricane Ivan	$ 5,157	$ 17,383
	Hurricane Katrina	24,325	24,325
	Hurricane Rita	20,740	20,740
	Total proceeds	$ 50,222	$ 62,448
Property damage proceeds:
	Hurricane Ivan		$ 24,104
	Hurricane Katrina	$ 6,975	6,975
	Hurricane Rita	2,730	2,730
	Total	$ 9,705	$ 33,809

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 presents the unaudited condensed consolidated balance sheet data for the Operating Partnership at September 30, 2006:

ASSETS
Current assets		$ 2,146,745
Property, plant and equipment, net		9,401,669
Investments in and advances to unconsolidated affiliates, net		540,186
Intangible assets, net		1,018,695
Goodwill		591,497
Deferred tax asset		3,054
Other assets		46,058
	Total	$ 13,747,904

LIABILITIES AND PARTNERS' EQUITY
Current liabilities		$ 2,257,968
Long-term debt		4,884,261
Other long-term liabilities		102,609
Minority interest		133,394
Partners' equity		6,369,672
	Total	$ 13,747,904

Total Operating Partnership debt obligations guaranteed
by Enterprise Products Partners		$ 4,904,000

17. Subsequent Events

Acquisition of Canadian NGL marketing business from EPCO and Dan L. Duncan

On October 1, 2006, we acquired all of the outstanding stock of an affiliated NGL marketing company located in Canada from EPCO and Dan L. Duncan. The purchase price of this business was $18.5 million in cash, of which $16.4 million was paid to EPCO and the remainder to Dan L. Duncan. The purpose of this business acquisition was to expand our North American operations to serve Canadian-based NGL customers and to enhance our access to Canadian NGL production.

Acquisition of Mexia and Genco pipeline assets from TEPPCO

On October 10, 2006, we purchased certain idle pipeline assets in the Houston, Texas area from TEPPCO for $11.7 million in cash. These purchases are part of the pipeline projects we announced in July

2006 in connection with our new long-term natural gas transportation and storage contracts with CenterPoint Energy Resources Corp. The acquired pipelines will be modified for natural gas service.

Initial Public Offering of Duncan Energy Partners

On November 2, 2006, our subsidiary, Duncan Energy Partners, filed its initial registration statement for a proposed initial public offering of its common units. Duncan Energy Partners was formed in September 2006 as a Delaware limited partnership to own, operate and acquire a diversified portfolio of midstream energy assets. At the closing of Duncan Energy Partner’s initial public offering, we will contribute 66% of the equity interests in following subsidiaries to Duncan Energy Partners:

Mont Belvieu Caverns, L.P. (“Mont Belvieu Caverns”), which receives, stores and delivers NGLs and petrochemical products for industrial customers located along the upper Texas Gulf Coast, which has the largest concentration for petrochemical plants and refineries in the United States.

Acadian Gas, LLC (“Acadian Gas”), which is an onshore natural gas pipeline system that gathers, transports, stores and markets natural gas in Louisiana. The Acadian Gas system links natural gas supplies from onshore and offshore Gulf of Mexico developments (including offshore pipelines, continental shelf and deepwater production) with local gas distribution companies, electric generation plants and industrial customers, including those in the Baton Rouge-New Orleans- Mississippi River corridor.

Sabine Propylene Pipeline L.P. (“Sabine Propylene”), which transports polymer-grade propylene between Port Arthur, Texas and a pipeline interconnect located in Cameron Parish, Louisiana;

Enterprise Lou-Tex Propylene Pipeline L.P. (“Lou-Tex Propylene”), which transports chemical-grade propylene between Mont Belvieu, Texas and Sorrento, Louisiana; and a

South Texas NGL Pipelines, LLC (“South Texas NGL”), which will transport NGLs from Corpus Christi, Texas to Mont Belvieu, Texas. South Texas NGL will own the South Texas NGL pipeline system. See Note 6 for a description of this pipeline.

We expect to retain a 34% ownership interest in each of these entities. In addition, we will own the 2% general partner and expect to own at least 25% of the limited partner interests of Duncan Energy Partners. Our ownership of the limited partner interests of Duncan Energy Partners (following its initial public offering) assumes that the underwriters exercise their overallotment option with respect to the offering. Our Operating Partnership will direct the business operations of Duncan Energy Partners through its ownership and control of Duncan Energy Partners.

From a financial reporting perspective, the formation of Duncan Energy Partners had no effect on our financial statements at September 30, 2006. Beginning with the quarterly period in which the initial public offering of Duncan Energy Partners is completed, we will consolidate the results of Duncan Energy Partners with minority interest treatment for the common units of Duncan Energy Partners owned by unitholders other than us.

We expect to have significant continuing involvement with all of these assets, including the following types of transactions:

We will continue to utilize storage services provided by Mont Belvieu Caverns to support our Mont Belvieu fractionation and other businesses;

We will continue to buy from and sell natural gas to Acadian Gas in connection with its normal business activities; and

We will be the sole shipper on the NGL pipeline system to be owned by South Texas NGL.