SEC Filing | Enterprise Products Partners L.P.

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epdform8k_111308.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT PURSUANT

TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

Date of report (Date of earliest event reported): September 30, 2008

ENTERPRISE PRODUCTS PARTNERS L.P.

(Exact Name of Registrant as Specified in Its Charter)

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

1100 Louisiana, 10th Floor, Houston, Texas (Address of Principal Executive Offices)	77002 (Zip Code)
(713) 381-6500 (Registrant’s Telephone Number, including Area Code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 8.01. Other Events.

We are filing the Unaudited Condensed Consolidated Balance Sheet of Enterprise Products GP, LLC at September 30, 2008, which is included as Exhibit 99.1 to this current report. Enterprise Products GP, LLC is the general partner of Enterprise Products Partners L.P.

Item 9.01. Financial Statements and Exhibits.

(d) Exhibits.

Exhibit No.	Description

99.1	Unaudited Condensed Consolidated Balance Sheet of Enterprise Products GP, LLC at September 30, 2008.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	ENTERPRISE PRODUCTS PARTNERS L.P.

	By: Enterprise Products GP, LLC, as General Partner




Date: November 13, 2008	By:	/s/ Michael J. Knesek
	Name:		Michael J. Knesek
	Title:		Senior Vice President, Controller and Principal Accounting Officer of Enterprise Products GP, LLC

exhibit99_1.htm

EXHIBIT 99.1

Enterprise Products GP, LLC

Unaudited Condensed Consolidated Balance Sheet at September 30, 2008

ENTERPRISE PRODUCTS GP, LLC

TABLE OF CONTENTS

		Page No.
Unaudited Condensed Consolidated Balance Sheet at September 30, 2008		2

Notes to Unaudited Condensed Consolidated Balance Sheet
	Note 1 – Company Organization	3
	Note 2 – General Accounting Policies and Related Matters	4
	Note 3 – Accounting for Unit-Based Awards	7
	Note 4 – Financial Instruments	11
	Note 5 – Inventories	16
	Note 6 – Property, Plant and Equipment	17
	Note 7 – Investments in and Advances to Unconsolidated Affiliates	18
	Note 8 – Business Combinations	19
	Note 9 – Intangible Assets and Goodwill	20
	Note 10 – Debt Obligations	21
	Note 11 – Member’s Equity	23
	Note 12 – Business Segments	24
	Note 13 – Related Party Transactions	25
	Note 14 – Commitments and Contingencies	29
	Note 15 – Significant Risks and Uncertainties – Weather-Related Risks	31
	Note 16 – Condensed Financial Information of EPO	33

ENTERPRISE PRODUCTS GP, LLC

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET

AT SEPTEMBER 30, 2008

(Dollars in thousands)

ASSETS
Current assets
Cash and cash equivalents		$	55,403
Restricted cash			183,221
Accounts and notes receivable – trade, net of allowance
for doubtful accounts of $15,781			1,840,584
Accounts receivable – related parties			88,860
Inventories			653,783
Prepaid and other current assets			161,233
	Total current assets		2,983,084
Property, plant and equipment, net			12,693,619
Investments in and advances to unconsolidated affiliates			917,193
Intangible assets, net of accumulated amortization of $408,304			866,313
Goodwill			616,996
Deferred tax asset			2,927
Other assets			69,067
	Total assets	$	18,149,199

LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable – trade		$	245,454
Accounts payable – related parties			75,635
Accrued product payables			2,241,336
Accrued expenses			75,156
Accrued interest			101,962
Other current liabilities			430,389
	Total current liabilities		3,169,932
Long-term debt: (see Note 10)
Senior debt obligations – principal			7,184,201
Junior subordinated notes – principal			1,250,000
Other			23,994
Total long-term debt			8,458,195
Deferred tax liabilities			23,159
Other long-term liabilities			66,207
Minority interest			6,024,122
Commitments and contingencies
Member’s equity, including accumulated other
comprehensive loss of $118,223			407,584
	Total liabilities and member's equity	$	18,149,199

See Notes to Unaudited Condensed Consolidated Balance Sheet.

ENTERPRISE PRODUCTS GP, LLC

NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET

AT SEPTEMBER 30, 2008

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

Note 1. Company Organization

Company Organization

Enterprise Products GP, LLC is a Delaware limited liability company that was formed in April 1998 to become the general partner of Enterprise Products Partners L.P. The business purpose of Enterprise Products GP, LLC is to manage the affairs and operations of Enterprise Products Partners L.P. At September 30, 2008, Enterprise GP Holdings L.P. owned 100% of the membership interests of Enterprise Products GP, LLC.

Unless the context requires otherwise, references to “we,” “us,” “our” or “the Company” 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 Partners” mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries. Enterprise Products Partners is a publicly traded Delaware limited partnership, the registered common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.” References to “EPGP” mean Enterprise Products GP, LLC, individually as the general partner of Enterprise Products Partners, and not on a consolidated basis. Enterprise Products Partners has no business activities outside those conducted by its operating subsidiary, Enterprise Products Operating LLC (“EPO”). Enterprise Products Partners and EPO were formed to acquire, own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO, Inc.

References to “Enterprise GP Holdings” mean the business and operations of Enterprise GP Holdings L.P. and its consolidated subsidiaries. Enterprise GP Holdings is a publicly traded Delaware limited partnership, the registered units of which are listed on the NYSE under the ticker symbol “EPE.” References to “EPE Holdings” mean EPE Holdings, LLC, which is the general partner of Enterprise GP Holdings.

References to “TEPPCO” mean TEPPCO Partners, L.P., a publicly traded affiliate, the common units of which are listed on the NYSE under the ticker symbol “TPP.” References to “TEPPCO GP” refer to Texas Eastern Products Pipeline Company, LLC, which is the general partner of TEPPCO and is wholly owned by Enterprise GP Holdings.

References to “Energy Transfer Equity” mean the business and operations of Energy Transfer Equity, L.P. and its consolidated subsidiaries. References to “LE GP” mean LE GP, LLC, which is the general partner of Energy Transfer Equity. On May 7, 2007, Enterprise GP Holdings acquired non-controlling interests in both LE GP and Energy Transfer Equity. Enterprise GP Holdings accounts for its investments in LE GP and Energy Transfer Equity using the equity method of accounting.

References to “Employee Partnerships” mean EPE Unit L.P. (“EPE Unit I”), EPE Unit II, L.P. (“EPE Unit II”), EPE Unit III, L.P. (“EPE Unit III”) and Enterprise Unit L.P. (“Enterprise Unit”), collectively, which are private company affiliates of EPCO, Inc.

On February 5, 2007, a consolidated subsidiary of EPO, Duncan Energy Partners L.P. (“Duncan Energy Partners”), completed an initial public offering of its common units (see Note 13). Duncan Energy Partners owns equity interests in certain of the midstream energy businesses of EPO. Duncan Energy Partners is a publicly traded Delaware limited partnership, the common units of which are listed on the

NYSE under the ticker symbol “DEP.” References to “DEP GP” mean DEP Holdings, LLC, which is the general partner of Duncan Energy Partners and a wholly owned subsidiary of EPO.

References to “EPCO” mean EPCO, Inc. and its wholly-owned private company affiliates, which are related parties to all of the foregoing named entities. Dan L. Duncan is the Group Co-Chairman and controlling shareholder of EPCO.

For financial reporting purposes, Enterprise Products Partners consolidates the balance sheet of Duncan Energy Partners with that of its own. Enterprise Products Partners controls Duncan Energy Partners through the ownership of its general partner. Public ownership of Duncan Energy Partners’ net assets is presented as a component of minority interest in our consolidated balance sheet. The borrowings of Duncan Energy Partners are presented as part of our consolidated debt; however, neither Enterprise Products Partners nor EPGP has any obligation for the payment of interest or repayment of borrowings incurred by Duncan Energy Partners.

Basis of Presentation

EPGP owns a 2% general partner interest in Enterprise Products Partners, which conducts substantially all of its business. EPGP has 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 in our consolidated subsidiaries.

Note 2. General Accounting Policies and Related Matters

Consolidation Policy

Our consolidated balance sheet includes our accounts and those of our majority-owned subsidiaries in which we have a controlling financial or equity interest, after the elimination of intercompany accounts and transactions. We evaluate our financial interests in companies to determine if they represent variable interest entities where we are the primary beneficiary. If such criteria are met, we consolidate the balance sheets of such businesses with that of our own.

We consolidate the balance sheet of Enterprise Products Partners with that of EPGP. This accounting consolidation is required because EPGP owns 100% of the general partnership interest in Enterprise Products Partners, which gives EPGP the ability to exercise control over Enterprise Products Partners.

If an investee is organized as a limited partnership or limited liability company and maintains separate ownership accounts, we account for our investment using the equity method if our ownership interest is between 3% and 50% and we exercise significant influence over the investee’s operating and financial policies. For all other types of investments, we apply the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the investee’s operating and financial policies. In consolidation we eliminate our proportionate share of profits and losses from transactions with our equity method unconsolidated affiliates to the extent such amounts are material and remain on our balance sheet (or those of our equity method investees) in inventory or similar accounts.

If our ownership interest in an investee does not provide us with either control or significant influence over the investee, we account for the investment using the cost method.

Dixie Employee Benefit Plans

Dixie Pipeline Company (“Dixie”), a consolidated subsidiary of EPO, directly employs the personnel that operate its pipeline system. Certain of these employees are eligible to participate in Dixie’s defined contribution plan and pension and postretirement benefit plans. Dixie contributed $0.1 million and $0.2 million to its company-sponsored defined contribution plan during the three and nine month periods ended September 30, 2008, respectively. During the remainder of 2008, Dixie expects to contribute approximately $0.1 million to its postretirement benefit plan and approximately $0.5 million to its pension plan.

Environmental Costs

Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals. Ongoing environmental compliance costs are charged to expense as incurred. In accruing for environmental remediation liabilities, costs of future expenditures for environmental remediation are not discounted to their present value, unless the amount and timing of the expenditures are fixed or reliably determinable. At September 30, 2008, none of our estimated environmental remediation liabilities are discounted to present value since the ultimate amount and timing of cash payments for such liabilities are not readily determinable. Expenditures to mitigate or prevent future environmental contamination are capitalized.

At September 30, 2008, our accrued liabilities for environmental remediation projects totaled $21.2 million. These amounts were derived from a range of reasonable estimates based upon studies and site surveys. Unanticipated changes in circumstances and/or legal requirements could result in expenses being incurred in future periods in addition to an increase in actual cash required to remediate contamination for which we are responsible.

Estimates

Preparing our financial statements in conformity with U.S. generally accepted accounting principles (“GAAP”) requires management to make estimates and assumptions that affect amounts presented in the financial statements (i.e. assets, liabilities, revenue and expenses) and disclosures about contingent assets and liabilities. Our actual results could differ from these estimates. On an ongoing basis, management reviews its estimates based on currently available information. Changes in facts and circumstances may result in revised estimates.

We revised the remaining useful lives of certain assets, most notably the assets that constitute our Texas Intrastate System, effective January 1, 2008. This revision adjusted the remaining useful life of such assets to incorporate recent data showing that proved natural gas reserves supporting throughput and processing volumes for these assets have changed since our original determination made in September 2004. These revisions will prospectively reduce our depreciation expense on assets having carrying values totaling $2.72 billion at January 1, 2008. For additional information regarding this change in estimate, see Note 6.

Minority Interest

As presented in our Unaudited Condensed Consolidated Balance Sheet, minority interest represents third-party and affiliate ownership interests in the net assets of our consolidated subsidiaries. For financial reporting purposes, the assets and liabilities of our controlled subsidiaries, including Duncan Energy Partners, are consolidated with those of our own, with any third-party or affiliate ownership interests in such amounts presented as minority interest. The following table shows the components of minority interest at September 30, 2008:

Limited partners of Enterprise Products Partners:
Third-party owners of Enterprise Products Partners (1)	$	5,035,041
Related party owners of Enterprise Products Partners (2)		576,169
Limited partners of Duncan Energy Partners:
Third-party owners of Duncan Energy Partners (3)		281,913
Joint venture partners (4)		130,999
Total minority interest on consolidated balance sheet	$	6,024,122

(1) Consists of non-affiliate public unitholders of Enterprise Products Partners. (2) Consists of unitholders of Enterprise Products Partners that are related party affiliates. This group is primarily comprised of EPCO and certain of its private company consolidated subsidiaries. (3) Consists of non-affiliate public unitholders of Duncan Energy Partners. (4) Represents third-party ownership interests in joint ventures that we consolidate, including Seminole Pipeline Company (“Seminole”), Tri-States Pipeline, L.L.C. (“Tri-States”), Independence Hub, LLC (“Independence Hub”), Wilprise Pipeline Company, L.L.C. (“Wilprise”) and Belle Rose NGL Pipeline, L.L.C. (“Belle Rose”).

Recent Accounting Developments

The following information summarizes recently issued accounting guidance since those reported in our Audited Consolidated Balance Sheet for the year ended December 31, 2007, which was included as an exhibit to the Current Report on Form 8-K filed by Enterprise Products Partners on March 14, 2008, that will or may affect our future balance sheet.

Statement of Financial Accounting Standards (“SFAS”) No. 161, Disclosures about Derivative Instruments and Hedging Activities – An Amendment of FASB Statement No. 133. Issued in March 2008, SFAS 161 changes the disclosure requirements for financial instruments and hedging activities with the intent to provide users of financial statements with an enhanced understanding of (i) how and why an entity uses financial instruments, (ii) how financial instruments and related hedged items are accounted for under SFAS 133, Accounting for Derivative Instruments and Hedging Activities, and its related interpretations and (iii) how financial instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. SFAS 161 requires qualitative disclosures about objectives and strategies for using financial instruments, quantitative disclosures about fair value amounts of and gains and losses on financial instruments and disclosures about credit-risk-related contingent features in financial instrument agreements. This statement has the same scope as SFAS 133, and accordingly applies to all entities. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. This statement encourages, but does not require, comparative disclosures for earlier periods at initial adoption. SFAS 161 only affects disclosure requirements; therefore, our adoption of this statement effective January 1, 2009 will not impact our financial position.

FASB Staff Position (“FSP”) No. EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities. FSP EITF 03-6-1 was issued in June 2008. FSP EITF 03-6-1 clarifies that unvested share-based payment awards constitute participating securities, if such awards include nonforfeitable rights to dividends or dividend equivalents. Consequently, awards that are deemed to be participating securities must be allocated earnings in the computation of earnings per share under the two-class method. FSP EITF 03-6-1 is effective for us on January 1, 2009.

We do not believe that FSP EITF 03-6-1 will have a material impact on our earnings per unit computations and disclosures.

FSP No. FAS 157-2, Effective Date of FASB Statement No. 157. FSP 157-2 defers the effective date of SFAS 157, Fair Value Measurements, to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years, for all nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). As allowed under FSP 157-2, we have not applied the provisions of SFAS 157 to our nonfinancial assets and liabilities measured at fair value, which include certain assets and liabilities acquired in business combinations. On January 1, 2008, we adopted the provisions of SFAS 157 that apply to financial assets and liabilities. See Note 4 for these fair value disclosures. We do not expect any immediate impact from adoption of the remaining portions of SFAS 157 on January 1, 2009.

In light of current market conditions, the FASB has issued additional clarifying guidance regarding the implementation of SFAS 157, particularly with respect to financial assets that do not trade in active markets such as investments in joint ventures. This clarifying guidance did not result in a change in our accounting, reporting or impairment testing for such investments. We continue to monitor developments at the FASB and SEC for new matters and guidance that may affect our valuation processes.

FSP No. FAS 142-3, Determination of the Useful Life of Intangible Assets. In April 2008, the FASB issued FSP 142-3, which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful lives of recognized intangible assets under SFAS 142, Goodwill and Other Intangible Assets. This change is intended to improve consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of such assets under SFAS 141(R) and other accounting guidance. The requirement for determining useful lives must be applied prospectively to intangible assets acquired after January 1, 2009 and the disclosure requirements must be applied prospectively to all intangible assets recognized as of, and subsequent to, January 1, 2009. We will adopt the provisions of FSP 142-3 on January 1, 2009.

Restricted Cash

Restricted cash represents amounts held in connection with our commodity financial instruments portfolio and New York Mercantile Exchange (“NYMEX”) physical natural gas purchases. Additional cash may be restricted to maintain our positions as commodity prices fluctuate or deposit requirements change. At September 30 2008, there was $183.2 million in restricted cash.

Note 3. Accounting for Unit-Based Awards

We account for unit-based awards in accordance with SFAS 123(R), Share-Based Payment. SFAS 123(R) requires us to recognize compensation expense related to unit-based awards based on the fair value of the award at grant date. The fair value of restricted unit awards is based on the market price of the underlying common units on the date of grant. The fair value of other unit-based awards is estimated using the Black-Scholes option pricing model. The fair value of an equity-classified award (such as a restricted unit award) is amortized to earnings on a straight-line basis over the requisite service or vesting period. Compensation expense for liability-classified awards (such as unit appreciation rights (“UARs”)) is recognized over the requisite service or vesting period of an award based on the fair value of the award remeasured at each reporting period. Liability-type awards are settled in cash upon vesting.

1998 Plan

The 1998 Plan provides for the issuance of up to 7,000,000 of Enterprise Products Partners’ common units. After giving effect to outstanding option awards at September 30, 2008 and the issuance and forfeiture of restricted unit awards through September 30, 2008, a total of 771,546 additional common units could be issued under the 1998 Plan.

Unit option awards. Under the 1998 Plan, non-qualified incentive options to purchase a fixed number of Enterprise Products Partners’ common units may be granted to key employees of EPCO who perform management, administrative or operational functions for us. The following table presents unit option activity under the 1998 Plan for the periods indicated:

						Weighted-
				Weighted-		Average
				Average		Remaining		Aggregate
	Number of			Strike Price		Contractual		Intrinsic
	Units			(dollars/unit)		Term (in years)		Value (1)
Outstanding at December 31, 2007 (2)		2,315,000		$	26.18
Exercised		(61,500	)	$	20.38
Forfeited or terminated		(85,000	)	$	26.72
Outstanding at September 30, 2008		2,168,500		$	26.32		5.44	$	2,356
Options exercisable at
September 30, 2008		548,500		$	21.47		4.33	$	2,356

(1) Aggregate intrinsic value reflects fully vested unit options at September 30, 2008. (2) During 2008, we amended the terms of certain of Enterprise Products Partners’ outstanding unit options. In general, the expiration dates of these awards were modified from May and August 2017 to December 2012.

The total intrinsic value of unit options exercised during the three and nine months ended September 30, 2008 was $0.1 million and $0.6 million, respectively. At September 30, 2008, there was an estimated $1.9 million of total unrecognized compensation cost related to nonvested unit options granted under the 1998 Plan. We expect to recognize our share of this cost over a weighted-average period of 2.4 years in accordance with the EPCO administrative services agreement (the “ASA”).

During the nine months ended September 30, 2008, we received cash of $0.7 million from the exercise of unit options. Conversely, our option-related reimbursements to EPCO were $0.6 million.

Restricted unit awards. Under the 1998 Plan, Enterprise Products Partners may also issue restricted common units to key employees of EPCO and directors of EPGP. The following table summarizes information regarding Enterprise Products Partners’ restricted common units for the periods indicated:

				Weighted-
				Average Grant
	Number of			Date Fair Value
	Units			per Unit (1)
Restricted units at December 31, 2007		1,688,540
Granted (2)		750,900		$	25.30
Forfeited		(84,677	)	$	26.83
Vested		(115,150	)	$	22.83
Restricted units at September 30, 2008		2,239,613

(1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. The weighted-average grant date fair value per unit for forfeited and vested awards is determined before an allowance for forfeitures. (2) Aggregate grant date fair value of restricted common unit awards issued during 2008 was $19.0 million based on a grant date market price of Enterprise Products Partners’ common units ranging from $28.21 to $32.31 per unit and an estimated forfeiture rate of 17.0%.

The total fair value of Enterprise Products Partners’ restricted unit awards that vested during the three and nine months ended September 30, 2008 was $1.2 million and $2.6 million, respectively. As of September 30, 2008, there was $34.6 million of total unrecognized compensation cost related to restricted common units. We will recognize our share of such costs in accordance with the EPCO ASA. At September 30, 2008, these costs are expected to be recognized over a weighted-average period of 2.4 years.

Phantom unit awards. The 1998 Plan also provides for the issuance of phantom unit awards. These liability awards are automatically redeemed for cash based on the vested portion of the fair market

value of the phantom units at redemption dates in each award. No phantom unit awards have been issued to date under the 1998 Plan.

Enterprise Products 2008 Long-Term Incentive Plan

On January 29, 2008, Enterprise Products Partners’ unitholders approved the Enterprise Products 2008 Long-Term Incentive Plan (the “2008 LTIP”), which provides for awards of Enterprise Products Partners’ common units and other rights to non-employee EPGP directors and to consultants and employees of EPCO and its affiliates providing services to Enterprise Products Partners. Awards under the 2008 LTIP may be granted in the form of unit options, restricted units, phantom units, UARs and distribution equivalent rights. The 2008 LTIP is administered by EPGP’s Audit, Conflicts and Governance (“ACG”) Committee. The 2008 LTIP provides for the issuance of up to 10,000,000 of Enterprise Products Partners’ common units. After giving effect to option awards outstanding at September 30, 2008, a total of 9,205,000 additional common units could be issued under the 2008 LTIP.

The 2008 LTIP may be amended or terminated at any time by the Board of Directors of EPCO or EPGP’s ACG Committee; however, the rules of the NYSE require that any material amendment, such as a significant increase in the number of common units available under the plan or a change in the types of awards available under the plan, would require the approval of Enterprise Products Partners’ unitholders. The ACG Committee is also authorized to make adjustments in the terms and conditions of, and the criteria included in, awards under the plan in specified circumstances. The 2008 LTIP is effective until the earlier of January 29, 2018 or the time which all available units under the incentive plan have been delivered to participants or the time of termination of the plan by EPCO or EPGP’s ACG Committee.

Unit option awards. The exercise price of unit options awarded to participants is determined by the ACG Committee (at its discretion) at the date of grant and may be no less than the fair market value of Enterprise Products Partners’ common units at the date of grant. The following table presents unit option activity under the 2008 LTIP for the periods indicated:

Weighted-

Average

Remaining

Number of

Strike Price

Contractual

Units

(dollars/unit)

Term (in years)

Outstanding at January 29, 2008

Granted (1)

795,000

30.93

Outstanding at September 30, 2008

795,000

30.93

5.25

(1) Aggregate grant date fair value of these unit options issued during 2008 was $1.6 million based on the following assumptions: (i) a grant date market price of Enterprise Products Partners’ common units of $30.93 per unit; (ii) expected life of options of 4.7 years; (iii) risk-free interest rate of 3.3%; (iv) expected distribution yield on Enterprise Products Partners’ common units of 7.0%; (v) expected unit price volatility on Enterprise Products Partners’ common units of 19.8%; and (vi) an estimated forfeiture rate of 17.0%.

At September 30, 2008, there was an estimated $1.4 million of total unrecognized compensation cost related to nonvested unit options granted under the 2008 LTIP. We expect to recognize our share of this cost over a remaining period of 3.6 years in accordance with the EPCO ASA.

Employee Partnerships

EPCO formed the Employee Partnerships to serve as an incentive arrangement for key employees of EPCO by providing them a “profits interest” in the Employee Partnerships. Currently, there are four Employee Partnerships: EPE Unit I, EPE Unit II, EPE Unit III and Enterprise Unit. EPE Unit I was formed in August 2005 in connection with Enterprise GP Holdings’ initial public offering, EPE Unit II was formed in December 2006, EPE Unit III was formed in May 2007 and Enterprise Unit was formed in February 2008. For a detailed description of EPE Unit I, EPE Unit II and EPE Unit III, see our Audited

Consolidated Balance Sheet for the year ended December 31, 2007, which was included as an exhibit to the Current Report on Form 8-K filed by Enterprise Products Partners on March 14, 2008.

In July 2008, each of EPE Unit I, EPE Unit II and EPE Unit III entered into a second amendment to its respective agreement of limited partnership (“Second Amendment”). The Second Amendments for EPE Unit I and EPE Unit II provide for the reduction of the rate at which the Class A Limited Partner, Duncan Family Interests, Inc., earns a preferred return on its investment in EPE Unit I and EPE Unit II (“Class A Preference Return Rate”). The Class A Preference Return Rate in each of these two limited partnership agreements was reduced from 6.25% to a floating preference rate to be determined by EPCO (in its sole discretion) that will be between 4.50% and 5.725% per annum. The Second Amendment for EPE Unit I and EPE Unit II also provides that the liquidation date of these partnerships be extended to November 2012 and February 2014, respectively. The Second Amendment for EPE Unit III extends the liquidation date of EPE Unit III to May 2014. Collectively, the Second Amendment to these partnership agreements resulted in an aggregate $18.2 million increase in non-cash compensation costs attributable to the profits interest awards in EPE Unit I, EPE Unit II and EPE Unit III.

As of September 30, 2008, there was $43.4 million of total unrecognized compensation cost related to the four Employee Partnerships. We will recognize our share of these costs in accordance with the EPCO ASA over a weighted-average period of 5.2 years.

Enterprise Unit. On February 20, 2008, EPCO formed Enterprise Unit to serve as an incentive arrangement for certain employees of EPCO through a “profits interest” in Enterprise Unit. On that date, EPCO Holdings, Inc. (“EPCO Holdings”) agreed to contribute $18.0 million in the aggregate (the “Initial Contribution”) to Enterprise Unit and was admitted as the Class A limited partner. Certain key employees of EPCO, including Enterprise Products Partners’ Chief Executive Officer and Chief Financial Officer, were issued Class B limited partner interests and admitted as Class B limited partners of Enterprise Unit without any capital contributions. EPCO Holdings made capital contributions to Enterprise Unit in addition to its Initial Contribution and may make additional contributions, although it has no legal obligation to do so. As of September 30, 2008, EPCO Holdings has contributed a total of $51.5 million to Enterprise Unit.

As with the awards granted in connection with the other Employee Partnerships, these awards are designed to provide additional long-term incentive compensation for certain employees. The profits interest awards (or Class B limited partner interests) in Enterprise Unit entitle the holder to participate in the appreciation in value of Enterprise GP Holdings’ units and Enterprise Products Partners’ common units and are subject to early vesting or forfeiture upon the occurrence of certain events.

An allocated portion of the fair value of these equity awards will be charged to us under the EPCO ASA as a non-cash expense. We will not reimburse EPCO, Enterprise Unit or any of their affiliates or partners, through the ASA or otherwise, in cash for any expenses related to Enterprise Unit, including the Initial Contribution by EPCO Holdings.

The Class B limited partner interests in Enterprise Unit that are owned by EPCO employees are subject to forfeiture if the participating employee’s employment with EPCO and its affiliates is terminated prior to February 20, 2014, with customary exceptions for death, disability and certain retirements that will result in early vesting. The risk of forfeiture associated with the Class B limited partner interests in Enterprise Unit will also lapse (i.e. the interests will become vested) upon certain change of control events.

Unless otherwise agreed to by EPCO, EPCO Holdings and a majority in interest of the Class B limited partners of Enterprise Unit, Enterprise Unit will terminate at the earlier of February 20, 2014 (six years from the date of the agreement) or a change in control of Enterprise Products Partners or Enterprise GP Holdings. Enterprise Unit has the following material terms regarding its quarterly cash distribution to partners:

§	Distributions of cash flow – Each quarter, 100% of the cash distributions received by Enterprise Unit from Enterprise GP Holdings and Enterprise Products Partners will be distributed to the

Class A limited partner until EPCO Holdings has received an amount equal to the Class A preferred return (as defined below), and any remaining distributions received by Enterprise Unit will be distributed to the Class B limited partners. The Class A preferred return equals the Class A capital base (as defined below) multiplied by 5.0% per annum. The Class A limited partner’s capital base equals the amount of any contributions of cash or cash equivalents made by the Class A limited partner to Enterprise Unit, plus any unpaid Class A preferred return from prior periods, less any distributions made by Enterprise Unit of proceeds from the sale of units owned by Enterprise Unit (as described below).

Liquidating Distributions – Upon liquidation of Enterprise Unit, units having a fair market value equal to the Class A limited partner capital base will be distributed to EPCO Holdings, plus any accrued and unpaid Class A preferred return for the quarter in which liquidation occurs. Any remaining units will be distributed to the Class B limited partners.

§	Sale Proceeds – If Enterprise Unit sells any units that it beneficially owns, the sale proceeds will be distributed to the Class A limited partner and the Class B limited partners in the same manner as liquidating distributions described above.

DEP GP UARs

The non-employee directors of DEP GP, the general partner of Duncan Energy Partners, have been granted UARs in the form of letter agreements. These liability awards are not part of any established long-term incentive plan of EPCO, Enterprise Products Partners, Enterprise GP Holdings or Duncan Energy Partners. These UARs entitle each non-employee director to receive a cash payment on the vesting date equal to the excess, if any, of the fair market value of Enterprise GP Holdings’ units (determined as of a future vesting date) over the grant date fair value. These UARs are accounted for similarly to liability awards under SFAS 123(R) since they will be settled with cash. At September 30, 2008, we had a total of 90,000 outstanding UARs granted to non-employee directors of DEP GP that cliff vest in 2012. If a director resigns prior to vesting, his UAR awards are forfeited.

Note 4. Financial Instruments

We are exposed to financial market risks, including changes in commodity prices, interest rates and foreign exchange rates. We may use financial instruments (e.g., futures, forwards, swaps, options and other financial instruments with similar characteristics) to mitigate the risks of certain identifiable and anticipated transactions. In general, the types 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 applicable interest rates, commodity prices or exchange rates.

We recognize financial instruments as assets and liabilities on our Unaudited Condensed Consolidated Balance Sheet based on fair value. Fair value is generally defined as the amount at which a financial instrument could be exchanged in a current transaction between willing parties, not in a forced or liquidation sale. The estimated fair values of our financial instruments have been determined using available market information and appropriate valuation techniques. We must use considerable judgment, however, in interpreting market data and developing these estimates. Accordingly, our fair value estimates are not necessarily indicative of the amounts that we could realize upon disposition of these instruments. The use of different market assumptions and/or estimation techniques could have a material effect on our estimates of fair value.

Changes in fair value of financial instrument contracts are recognized in earnings in the current period unless specific hedge accounting criteria are met. If the financial instrument meets the criteria of a fair value hedge, gains and losses incurred on the instrument will be recorded in earnings to offset corresponding losses and gains on the hedged item. If the financial instrument meets the criteria of a cash flow hedge, gains and losses incurred on the instrument are recorded in accumulated other comprehensive income. Gains and losses on cash flow hedges are reclassified from accumulated other comprehensive

income to earnings when the forecasted transaction occurs or, as appropriate, over the economic life of the hedged item. A contract designated as a hedge of an anticipated transaction that is no longer likely to occur is immediately recognized in earnings.

To qualify for hedge accounting, the item to be hedged must expose us to risk and the related hedging instrument must reduce the exposure and meet the formal hedging requirements of SFAS 133, Accounting for Derivative Instruments and Hedging Activities (as amended and interpreted). We formally designate the financial instrument as a hedge and document and assess the effectiveness of the hedge at its inception and thereafter on a quarterly basis. Any hedge ineffectiveness is immediately recognized in earnings.

We routinely review our outstanding financial instruments in light of current market conditions. If market conditions warrant, some financial instruments may be closed out in advance of their contractual settlement dates thus realizing income or loss depending on the specific hedging criteria. When this occurs, we may enter into a new financial instrument to reestablish the hedge to which the closed instrument relates.

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 five interest rate swap agreements outstanding at September 30, 2008 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)	Value
Senior Notes C, 6.375% fixed rate, due Feb. 2013	1	Jan. 2004 to Feb. 2013	Feb. 2013	6.375% to 5.02%	$100.0 million
Senior Notes G, 5.60% fixed rate, due Oct. 2014	4	4th Qtr. 2004 to Oct. 2014	Oct. 2014	5.60% to 3.63%	$400.0 million
(1) The variable rate indicated is the all-in variable rate for the current settlement period.

The aggregate fair value of the five interest rate swaps at September 30, 2008 was an asset of $13.2 million, with an offsetting increase in the fair value of the underlying debt.

The following table summarizes the termination of our interest rate swaps during 2008 (dollars in millions):

	Notional			Cash
	Value			Gains
Interest rate swap portfolio, December 31, 2007	$	1,050.0		$	--
First quarter of 2008 terminations		(200.0	)		6.3
Second quarter of 2008 terminations		(250.0	)		12.0
Third quarter of 2008 terminations (1)		(100.0	)		--
Interest rate swap portfolio, September 30, 2008	$	500.0		$	18.3

(1) In early October 2008, one counterparty filed for bankruptcy. At September 30, 2008, the fair value of this interest rate swap was $3.4 million and this amount has been fully reserved. Hedge accounting for this swap has been discontinued.

Cash Flow Hedges – Interest Rate Swaps. Duncan Energy Partners had three floating-to-fixed interest rate swap agreements outstanding at September 30, 2008 that were accounted for as cash flow hedges.

	Number	Period Covered	Termination	Variable to	Notional
Hedged Variable Rate Debt	of Swaps	by Swap	Date of Swap	Fixed Rate (1)	Value
Duncan Energy Partners’ Revolver, due Feb. 2011	3	Sep. 2007 to Sep. 2010	Sep. 2010	3.77% to 4.62%	$175.0 million
(1) Amounts receivable from or payable to the swap counterparties are settled every three months (the “settlement period”).

The aggregate fair value of these interest rate swaps at September 30, 2008 was a liability of $4.3 million.

Cash Flow Hedges – Treasury Locks. We occasionally use treasury lock financial instruments to hedge the underlying U.S. treasury rates related to our anticipated issuances of debt. Cash gains or losses on the termination, or monetization, of such instruments are amortized to earnings using the effective interest method over the estimated term of the underlying fixed-rate debt. Each of our treasury lock transactions were designated as a cash flow hedge. The following table summarizes changes in our treasury lock portfolio since December 31, 2007 (dollars in millions).

	Notional			Cash
	Value			Losses
Treasury lock portfolio, December 31, 2007	$	600.0		$	--
First quarter of 2008 terminations		(350.0	)		27.7
Second quarter of 2008 terminations		(250.0	)		12.7
Treasury lock portfolio, September 30, 2008	$	--		$	40.4

Commodity Risk Hedging Program

The prices of natural gas, NGLs and certain 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 reduce 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. From time to time, we inject natural gas into storage and may utilize hedging instruments to lock in the value of our inventory positions. The commodity financial instruments we utilize may be settled in cash or with another financial instrument.

We have segregated our commodity financial instruments portfolio between those financial instruments utilized in connection with our natural gas marketing activities and those used in connection with our NGL and petrochemical operations.

Natural gas marketing activities. At September 30, 2008, the aggregate fair value of those financial instruments utilized in connection with our natural gas marketing activities was an asset of $0.8 million. Our natural gas marketing business and its related use of financial instruments has increased since December 31, 2007. For additional information regarding our natural gas marketing activities, see Note 12. We currently utilize mark-to-market accounting for substantially all of the financial instruments utilized in connection with our natural gas marketing activities.

NGL and petrochemical operations. At September 30, 2008, the aggregate fair value of financial instruments utilized in connection with our NGL and petrochemical operations was a liability of $116.6 million. Almost all of the financial instruments within this portion of the commodity financial instruments portfolio are accounted for as cash flow hedges, with a small number accounted for using mark-to-market accounting.

EPO has employed a program to economically hedge a portion of earnings from its natural gas processing business (a component of its NGL Pipelines & Services business segment). This program consists of (i) the forward sale of a portion of EPO’s expected equity NGL production volumes at fixed prices through 2009 and (ii) the purchase (using commodity financial instruments) of the amount of natural gas expected to be consumed as plant thermal reduction (“PTR”) in the production of such equity NGL volumes. The objective of this strategy is to hedge a level of gross margins (i.e., NGL sales revenues less actual costs for PTR and the gain or loss on the PTR hedge) associated with the forward sales contracts by fixing the cost of natural gas used for PTR, through the use of commodity financial instruments.

NGL forward sales contracts are not accounted for as financial instruments under SFAS 133; therefore, changes in the aggregate economic value of these sales contracts are not reflected in earnings and comprehensive income until the volumes are delivered to customers. On the other hand, the commodity financial instruments used to purchase the related quantities of PTR (i.e., “PTR hedges”) are accounted for as cash flow hedges; therefore, changes in the aggregate fair value of the PTR hedges are presented in other comprehensive income.

Prior to actual settlement, if the market price of natural gas is less than the price stipulated in a PTR hedge, we recognize an unrealized loss in other comprehensive income for the excess of the natural gas price stated in the PTR hedge over the market price. To the extent that we realize such financial losses upon settlement of the instrument, the losses are added to the actual cost we have to pay for PTR (which would then be based on the lower market price). The end result of this relationship – financial gain/loss on the PTR hedges plus the market price of actual natural gas purchases at the time of consumption – is that our total cost of natural gas used for PTR approximates the amount we originally hedged under this program The converse is true if the price of natural gas decreases. During the third quarter of 2008, the price of natural gas decreased approximately 45% from June 30, 2008. Once the forecasted NGL forward sales transactions occur, any realized gains and losses on the cash flow hedges would be reclassified into earnings at that time.

A significant number of the financial instruments in this portfolio hedge the purchase of physical natural gas. If natural gas prices fall below the price stipulated in such financial instruments, we recognize a liability for the difference; however, if prices partially or fully recover, this liability would be reduced or eliminated, as appropriate. Our restricted cash balance at September 30, 2008 was $183.2 million in order to meet commodity exchange deposit requirements and the negative change in the fair value of our commodity positions.

Foreign Currency Hedging Program

We are exposed to foreign currency exchange rate risk primarily through our Canadian NGL marketing subsidiary. As a result, we could be adversely affected by fluctuations in the foreign currency exchange rate between the U.S. dollar and the Canadian dollar. We attempt to hedge this risk using foreign exchange purchase contracts to fix the exchange rate. Mark-to-market accounting is utilized for these contracts, which typically have a duration of one month.

Adoption of SFAS 157 - Fair Value Measurements

On January 1, 2008, we adopted the provisions of SFAS 157 that apply to financial assets and liabilities. We will adopt the provisions of SFAS 157 that apply to nonfinancial assets and liabilities on January 1, 2009. SFAS 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date.

Our fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability. These assumptions include estimates of risk. Recognized valuation techniques employ inputs such as product prices, operating costs, discount factors and business growth rates. These inputs may be either readily observable, corroborated by market data or generally unobservable. In developing our estimates of fair value, we endeavor to utilize the best information available and apply market-based data to the extent possible. Accordingly, we utilize valuation

techniques (such as the market approach) that maximize the use of observable inputs and minimize the use of unobservable inputs.

SFAS 157 established a three-tier hierarchy that classifies fair value amounts recognized or disclosed in the financial statements based on the observability of inputs used to estimate such fair values. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). At each balance sheet reporting date, we categorize our financial assets and liabilities using this hierarchy. The characteristics of fair value amounts classified within each level of the SFAS 157 hierarchy are described as follows:

Level 1 fair values are based on quoted prices, which are available in active markets for identical assets or liabilities as of the measurement date. Active markets are defined as those in which transactions for identical assets or liabilities occur in sufficient frequency so as to provide pricing information on an ongoing basis (e.g., the NYSE or NYMEX). Level 1 primarily consists of financial assets and liabilities such as exchange-traded financial instruments, publicly-traded equity securities and U.S. government treasury securities.

Level 2 fair values are based on pricing inputs other than quoted prices in active markets (as reflected in Level 1 fair values) and are either directly or indirectly observable as of the measurement date. Level 2 fair values include instruments that are valued using financial models or other appropriate valuation methodologies. Such financial models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value of money, volatility factors for stocks and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are (i) observable in the marketplace throughout the full term of the instrument, (ii) can be derived from observable data or (iii) are validated by inputs other than quoted prices (e.g., interest rate and yield curves at commonly quoted intervals). Level 2 includes non-exchange-traded instruments such as over-the-counter forward contracts, options and repurchase agreements.

Level 3 fair values are based on unobservable inputs. Unobservable inputs are used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. Unobservable inputs reflect the reporting entity’s own ideas about the assumptions that market participants would use in pricing an asset or liability (including assumptions about risk). Unobservable inputs are based on the best information available in the circumstances, which might include the reporting entity’s internally-developed data. The reporting entity must not ignore information about market participant assumptions that is reasonably available without undue cost and effort. Level 3 inputs are typically used in connection with internally developed valuation methodologies where management makes its best estimate of an instrument’s fair value. Level 3 generally includes specialized or unique financial instruments that are tailored to meet a customer’s specific needs.

The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities measured on a recurring basis at September 30, 2008. These financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels. At September 30, 2008 there were no Level 1 financial assets or liabilities.

	Level 2		Level 3		Total
Financial assets:
Commodity financial instruments	$	15,320	$	18,445	$	33,765
Interest rate financial instruments		13,151		--		13,151
Total	$	28,471	$	18,445	$	46,916

Financial liabilities:
Commodity financial instruments	$	149,577	$	--	$	149,577
Interest rate financial instruments		4,301		--		4,301
Total	$	153,878	$	--	$	153,878

Fair values associated with our interest rate, commodity and foreign currency financial instrument portfolios were developed using available market information and appropriate valuation techniques in accordance with SFAS 157.

The following table sets forth a reconciliation of changes in the fair value of our Level 3 financial assets and liabilities for the periods indicated:

Balance, January 1, 2008	$	(4,660	)
Total gains (losses) included in:
Net income		(2,254	)
Other comprehensive income		2,419
Purchases, issuances, settlements		1,861
Balance, March 31, 2008		(2,634	)
Total gains (losses) included in:
Net income		322
Other comprehensive income		(2,428	)
Purchases, issuances, settlements		71
Balance, June 30, 2008		(4,669	)
Total gains (losses) included in:
Net income		(2,190	)
Other comprehensive loss		23,114
Purchases, issuances, settlements		2,190
Balance, September 30, 2008	$	18,445

Note 5. Inventories

Our inventory amounts were as follows at September 30, 2008:

Working inventory (1)	$	602,909
Forward-sales inventory (2)		50,874
Total inventory	$	653,783

(1) Working inventory is comprised of inventories of natural gas, NGLs and certain petrochemical products that are either available-for-sale or used in the provision for services. (2) Forward sales inventory consists of segregated NGL and natural gas volumes dedicated to the fulfillment of forward-sales contracts.

Our inventory values reflect payments for product purchases, freight charges associated with such purchase volumes, terminal and storage fees, vessel inspection costs, demurrage charges and other related costs. We value our inventories at the lower of average cost or market.

Due to fluctuating commodity prices in the NGL, natural gas and petrochemical industry, we recognize lower of cost or market (“LCM”) adjustments when the carrying value of our inventories exceed their net realizable value.

Note 6. Property, Plant and Equipment

Our property, plant and equipment values and accumulated depreciation balances were as follows at September 30, 2008:

	Estimated
	Useful Life
	in Years
Plants and pipelines (1)	3-35(5)	$	12,019,063
Underground and other storage facilities (2)	5-35(6)		784,808
Platforms and facilities (3)	20-31		634,809
Transportation equipment (4)	3-10		35,865
Land			50,560
Construction in progress			1,417,947
Total			14,943,052
Less accumulated depreciation			2,249,433
Property, plant and equipment, net		$	12,693,619

(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 as follows: 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 as follows: 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).

We recorded $17.3 million and $53.0 million of capitalized interest during the three and nine months ended September 30, 2008.

We reviewed assumptions underlying the estimated remaining useful lives of certain of our assets during the first quarter of 2008. As a result of our review, effective January 1, 2008, we revised the remaining useful lives of these assets, most notably the assets that constitute our Texas Intrastate System. This revision increased the remaining useful lives of such assets to incorporate recent data showing that proved natural gas reserves supporting throughput and processing volumes for these assets have changed since our original determination made in September 2004. These revisions will prospectively reduce our depreciation expense on assets having carrying values totaling $2.72 billion as of January 1, 2008. On average, we extended the life of these assets by 3.1 years.

Asset retirement obligations

Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of a tangible long-lived asset that results from its acquisition, construction, development or normal operation or

a combination of these factors. The following table summarizes amounts recognized in connection with AROs since December 31, 2007:

ARO liability balance, December 31, 2007	$	40,614
Liabilities incurred		810
Liabilities settled		(7,154	)
Revisions in estimated cash flows		2,411
Accretion expense		1,660
ARO liability balance, September 30, 2008	$	38,341

Property, plant and equipment at September 30, 2008 includes $8.8 million of asset retirement costs capitalized as an increase in the associated long-lived asset.

Note 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 of accounting. Our investments in and advances to unconsolidated affiliates are grouped according to the business segment to which they relate. See Note 12 for a general discussion of our business segments. The following table presents our investments in and advances to unconsolidated affiliates at September 30, 2008.

	Ownership
	Percentage
NGL Pipelines & Services:
Venice Energy Service Company, L.L.C. (“VESCO”)	13.1%	$	38,542
K/D/S Promix, L.L.C. (“Promix”)	50.0%		47,291
Baton Rouge Fractionators LLC (“BRF”)	32.2%		25,410
Onshore Natural Gas Pipelines & Services:
Jonah Gas Gathering Company (“Jonah”)	19.4%		278,736
Evangeline (2)	49.5%		4,494
White River Hub, LLC (“White River Hub”) (1)	50.0%		19,654
Offshore Pipelines & Services:
Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”)	36.0%		59,364
Cameron Highway Oil Pipeline Company (“Cameron Highway”)	50.0%		260,713
Deepwater Gateway, L.L.C. (“Deepwater Gateway”)	50.0%		109,263
Neptune Pipeline Company, L.L.C. (“Neptune”)	25.7%		52,278
Nemo Gathering Company, LLC (“Nemo”)	33.9%		784
Texas Offshore Port System (“TOPS”)	33.3%		2,355
Petrochemical Services:
Baton Rouge Propylene Concentrator LLC (“BRPC”)	30.0%		14,255
La Porte (3)	50.0%		4,054
Total		$	917,193

(1) In February 2008, we acquired a 50.0% ownership interest in White River Hub. (2) Refers to our ownership interests in Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp., collectively. (3) 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 acquire a non-controlling ownership interest in a company exceeds the underlying book value of the net assets we acquire. Such excess cost amounts are included within the carrying values of our investments in and advances to unconsolidated affiliates. At September 30, 2008, our investments in Promix, La Porte, Neptune, Poseidon, Cameron Highway and Jonah included excess cost amounts totaling $44.1 million. These amounts are attributable to the excess of the fair value of each entity’s tangible assets over their respective book carrying values at the time we acquired an interest in each entity.

White River Hub Joint Venture

In February 2008, we formed a joint venture, White River Hub, with a wholly-owned subsidiary of Questar Corporation to design, construct, own and operate a natural gas hub located in the vicinity of Meeker, Colorado. White River Hub will construct a FERC-regulated interstate natural gas transmission system for the purpose of providing natural gas transportation and hub services to its customers. The newly constructed natural gas hub will connect six interstate natural gas pipelines in northwest Colorado and have a capacity in excess of 2.0 billion cubic feet per day (“Bcf/d”). This project is expected to be completed during the fourth quarter of 2008 and our share of the estimated construction costs is $22.1 million.

Texas Offshore Port System Joint Venture

In August 2008, we, together with TEPPCO and Oiltanking Holding Americas, Inc. (“Oiltanking”), announced the formation of a joint venture to design, construct, operate and own a Texas offshore crude oil port and related pipeline and storage infrastructure that would facilitate delivery of waterborne crude oil to refining centers located along the upper Texas Gulf Coast. Demand for such projects is being driven by planned and expected refinery expansions along the Gulf Coast, expected increases in shipping traffic and operating limitations of regional ship channels.

The joint venture’s primary project, referred to as “TOPS,” includes (i) an offshore port (which will be located approximately 36 miles from Freeport, Texas), (ii) an onshore storage facility with approximately 3.9 million barrels of crude oil storage capacity, and (iii) an 85-mile crude oil pipeline system having a transportation capacity of up to 1.8 million barrels per day, that will extend from the offshore port to a Texas City, Texas storage facility. TOPS is expected to begin service as early as the fourth quarter of 2010. The joint venture’s second and complementary project, referred to as the Port Arthur Crude Oil Express (or “PACE”) will transport crude oil from Texas City, including crude oil from TOPS, and will consist of a 75-mile pipeline and 1.2 million barrels of crude oil storage capacity in the Port Arthur, Texas area. PACE is expected to begin service as early as the third quarter of 2010. Development of the TOPS and PACE projects is supported by long-term contracts with affiliates of Motiva Enterprises LLC and Exxon Mobil Corporation, which have committed a combined 725,000 barrels per day of crude oil to the projects.

We, TEPPCO and Oiltanking each own, through our respective subsidiaries, a one-third interest in the joint venture. The aggregate cost of the TOPS and PACE projects is expected to be approximately $1.8 billion (excluding capitalized interest), with the majority of such capital expenditures occurring in 2009 and 2010. We and TEPPCO have each guaranteed up to approximately $700.0 million of the capital contribution obligations of our respective subsidiary partners in the joint venture. As of September 30, 2008, our investment in TOPS was $2.4 million.

Note 8. Business Combinations

Acquisition of Remaining Interest in Dixie

In August 2008, we acquired the remaining 25.8% ownership interest in Dixie for $57.1 million. As a result of this transaction, we own 100% of Dixie, which owns a 1,300-mile pipeline system that delivers NGLs (primarily propane and other chemical feedstocks) to customers along the U.S. Gulf Coast and southeastern United States.

Purchase Price Allocations

We accounted for business combinations completed during the nine months ended September 30, 2008 using the purchase method of accounting and, accordingly, such costs have been allocated to 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 analysis. We expect to finalize the purchase price allocations for these transactions during 2008.

			South
	Dixie		Monco (1)			Total
Assets acquired in business combination:
Current assets	$	--	$	35		$	35
Property, plant and equipment, net		24,114		(12,781	)		11,333
Intangible assets		--		12,747			12,747
Total assets acquired		24,114		1			24,115
Liabilities assumed in business combination:
Minority interest		7,631		--			7,631
Total liabilities assumed		7,631		--			7,631
Total assets acquired plus liabilities assumed		31,745		1			31,746
Total cash used for business combinations		57,089		1			57,090
Goodwill	$	25,344	$	--		$	25,344

(1) Represents non-cash reclassification adjustments to December 2007 preliminary fair value estimates for assets acquired in the South Monco natural gas pipeline acquisition.

Note 9. Intangible Assets and Goodwill

Identifiable Intangible Assets

The following table summarizes our intangible assets by segment at September 30, 2008:

	Gross		Accum.			Carrying
	Value		Amort.			Value
NGL Pipelines & Services	$	523,401	$	(174,863	)	$	348,538
Onshore Natural Gas Pipelines & Services		476,298		(133,962	)		342,336
Offshore Pipelines & Services		207,012		(86,797	)		120,215
Petrochemical Services		67,906		(12,682	)		55,224
Total	$	1,274,617	$	(408,304	)	$	866,313

Goodwill

The following table summarizes our goodwill amounts by segment at September 30, 2008:

NGL Pipelines & Services (1)	$	179,050
Onshore Natural Gas Pipelines & Services		282,121
Offshore Pipelines & Services		82,135
Petrochemical Services		73,690
Totals	$	616,996

(1) See Note 8 for information regarding our recent acquisition of the remaining ownership interest in Dixie, which resulted in additional goodwill of $25.3 million.

Note 10. Debt Obligations

Our consolidated debt obligations consisted of the following at September 30, 2008:

EPO senior debt obligations:
Multi-Year Revolving Credit Facility, variable rate, due November 2012	$	1,150,701
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 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
Senior Notes L, 6.30% fixed-rate, due September 2017		800,000
Senior Notes M, 5.65% fixed-rate, due April 2013		400,000
Senior Notes N, 6.50% fixed-rate, due January 2019		700,000
Petal GO Zone Bonds, variable rate, due August 2037		57,500
Duncan Energy Partners’ debt obligation:
$300 Million Revolving Credit Facility, variable rate, due February 2011		212,000
Dixie Revolving Credit Facility, variable rate, due June 2010		10,000
Total principal amount of senior debt obligations		7,184,201
EPO Junior Subordinated Notes A, fixed/variable rates, due August 2066		550,000
EPO Junior Subordinated Notes B, fixed/variable rates, due January 2068		700,000
Total principal amount of senior and junior debt obligations		8,434,201
Other, non-principal amounts:
Change in fair value of debt-related financial instruments (see Note 4)		20,096
Unamortized discounts, net of premiums		(7,405	)
Unamortized deferred net gains related to terminated interest rate swaps (see Note 4)		11,303
Total other, non-principal amounts		23,994
Long-term debt	$	8,458,195

Standby letters of credit outstanding	$	61,100

Enterprise Products Partners L.P. acts as guarantor of the consolidated debt obligations of EPO with the exception of Dixie’s revolving credit facility and Duncan Energy Partners’ revolving credit facility. If EPO were to default on any of its guaranteed debt, Enterprise Products Partners L.P. would be responsible for full repayment of that obligation.

We consolidate the debt of Dixie and Duncan Energy Partners; however, neither Enterprise Products Partners L.P. nor EPGP have the obligation to make interest or debt payments with respect to such obligations.

With respect to debt agreements existing at September 30, 2008, there have been no significant changes in the terms of our consolidated debt obligations since December 31, 2007.

Letters of credit. During the third quarter of 2008, a $60.0 million letter of credit was issued under EPO’s Multi-Year Revolving Credit Facility to support our NYMEX margin requirements for natural gas financial instruments that are part of an economic hedge related to our natural gas processing business. In October 2008, EPO entered into a $100.0 million letter of credit facility. EPO issued a $70.0 million letter of credit under this new facility that replaced the letter of credit issued under its Multi-Year Revolving Credit Facility which was outstanding at September 30, 2008.

Senior Notes M and N. In April 2008, EPO sold $400.0 million in principal amount of 5-year senior unsecured notes (“Senior Notes M”) and $700.0 million in principal amount of 10-year senior unsecured notes (“Senior Notes N”) under its universal registration statement. Senior Notes M were issued at 99.906% of their principal amount, have a fixed interest rate of 5.65% and mature in April 2013. Senior

Notes N were issued at 99.866% of their principal amount, have a fixed interest rate of 6.50% and mature in January 2019.

Senior Notes M pay interest semi-annually in arrears on April 1 and October 1 of each year. Senior Notes N pay interest semi-annually in arrears on January 31 and July 31 of each year. Net proceeds from the issuance of Senior Notes M and N were used to temporarily reduce indebtedness outstanding under the EPO Multi-Year Revolving Credit Facility.

Senior Notes M and N rank equal with EPO’s existing and future unsecured and unsubordinated indebtedness. They are senior to any existing and future subordinated indebtedness of EPO. Senior Notes M and N are subject to make-whole redemption rights and were issued under indentures containing certain covenants, which generally restrict EPO’s ability, with certain exceptions, to incur debt secured by liens and engage in sale and leaseback transactions.

Covenants

We are in compliance with the covenants of our consolidated debt agreements at September 30, 2008.

Information regarding variable interest rates paid

The following table presents the weighted-average interest rate paid on our consolidated variable-rate debt obligations during the nine months ended September 30, 2008.

	Weighted-average
	interest rate
	paid
EPO’s Multi-Year Revolving Credit Facility	3.62%
Duncan Energy Partners’ Revolving Credit Facility	4.15%
Dixie Revolving Credit Facility	3.25%
Petal GO Zone Bonds	2.27%

Consolidated debt maturity table

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

2008	$	--
2009		500,000
2010		564,000
2011		662,000
2012		1,150,701
Thereafter		5,557,500
Total scheduled principal payments	$	8,434,201

Debt Obligations of Unconsolidated Affiliates

We have two unconsolidated affiliates with long-term debt obligations. The following table shows (i) our ownership interest in each entity at September 30, 2008, (ii) total debt of each unconsolidated affiliate at September 30, 2008 (on a 100% basis to the affiliate) and (iii) the corresponding scheduled maturities of such debt.

	Our			Scheduled Maturities of Debt
	Ownership													After
	Interest	Total		2008		2009		2010		2011		2012		2012
Poseidon	36.0%	$	109,000	$	--	$	--	$	--	$	109,000	$	--	$	--
Evangeline	49.5%		20,650		5,000		5,000		3,150		7,500		--		--
Total		$	129,650	$	5,000	$	5,000	$	3,150	$	116,500	$	--	$	--

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, 2008. The credit agreements of our unconsolidated affiliates restrict their ability to pay cash dividends if a default or an event of default (as defined in each credit agreement) has occurred and is continuing at the time such dividend is scheduled to be paid.

There have been no significant changes in the terms of the debt obligations of our unconsolidated affiliates since those reported in our Audited Consolidated Balance Sheet for the year ended December 31, 2007, which was included as an exhibit to the Current Report on Form 8-K filed by Enterprise Products Partners on March 14, 2008.

Note 11. Member’s Equity

At September 30, 2008, member’s equity consisted of the capital account of Enterprise GP Holdings and accumulated other comprehensive loss.

Accumulated other comprehensive income (loss)

The following table summarizes transactions affecting our accumulated other comprehensive income (loss) since December 31, 2007.

	Cash Flow Hedges														Accumulated
				Interest			Foreign			Foreign		Pension			Other
	Commodity			Rate			Currency			Currency		And			Comprehensive
	Financial			Financial			Financial			Translation		Postretirement			Income (Loss)
	Instruments			Instruments			Instruments			Adjustment		Plans			Balance
Balance, December 31, 2007	$	(21,619	)	$	34,980		$	1,308		$	1,200	$	588		$	16,457
Net commodity financial instrument losses during period		(108,294	)		--			--			--		--			(108,294	)
Net interest rate financial instrument losses during period		--			(21,283	)		--			--		--			(21,283	)
Amortization of cash flow financing hedges		--			(3,983	)		--			--		--			(3,983	)
Change in funded status of Dixie benefit plans, net of tax		--			--			--			--		(264	)		(264	)
Foreign currency hedge losses during period		--			--			(1,308	)		--		--			(1,308	)
Foreign currency translation adjustment		--			--			--			452		--			452
Balance, September 30, 2008 (see Note 4)	$	(129,913	)	$	9,714		$	--		$	1,652	$	324		$	(118,223	)

Note 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 technologies 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, crude oil and certain petrochemicals. 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.

Many of our equity investees are included within our integrated midstream asset system. For example, we have ownership interests in several offshore natural gas and crude oil pipelines. Other examples include our use of the Promix NGL fractionator to process mixed NGLs extracted by our gas plants. The fractionated NGLs we receive from Promix can then be sold in our NGL marketing activities.

The majority of our plant-based operations are located in Texas, Louisiana, Mississippi, New Mexico, Colorado and Wyoming. Our natural gas, NGL and crude oil pipelines are located in a number of regions of the United States including (i) the Gulf of Mexico offshore Texas and Louisiana; (ii) the south and southeastern United States (primarily in Texas, Louisiana, Mississippi and Alabama); and (iii) certain regions of the central and western United States, including the Rocky Mountains. Our marketing activities are headquartered in Houston, Texas and serve customers in a number of regions of the United States including the Gulf Coast, West Coast and Mid-Continent areas.

Consolidated property, plant and equipment and investments in and advances to unconsolidated affiliates are 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
			Onshore
	NGL		Natural Gas		Offshore				Adjustments
	Pipelines		Pipelines		Pipelines		Petrochemical		and		Consolidated
	& Services		& Services		& Services		Services		Eliminations		Totals
Segment assets:
At September 30, 2008	$	5,248,670	$	3,922,181	$	1,407,855	$	696,966	$	1,417,947	$	12,693,619
Investments in and advances to
unconsolidated affiliates (see Note 7):
At September 30, 2008		111,243		302,884		484,757		18,309		--		917,193
Intangible assets, net (see Note 9):
At September 30, 2008		348,538		342,336		120,215		55,224		--		866,313
Goodwill (see Note 9):
At September 30, 2008		179,050		282,121		82,135		73,690		--		616,996

Our natural gas marketing business, which is included in our Onshore Natural Gas Pipelines & Services segment, has increased significantly during 2008. These marketing activities have four primary objectives: (i) to mitigate risk; (ii) maximize the use of our natural gas assets; (iii) to provide real-time

market intelligence; and (iv) to link our noncontiguous natural gas assets together to enhance the profitability of such operations. To achieve these objectives, our natural gas marketing activities transact with various parties to provide transportation, balancing, storage, supply and sales services. The majority of our natural gas marketing activities are focused on the Gulf Coast and Rocky Mountain regions.

Our natural gas marketing business acquires a significant portion of the natural gas it sells from our processing plants and attracts additional supplies from third parties at pipeline interconnects to facilitate incremental throughput on our natural gas transportation pipelines. This purchased gas is then sold to industrial consumers, utilities and power plants at prices that include a transportation fee. In addition, sales are made with third party marketing companies at industry hub locations in order to balance our supply/demand portfolio. Our purchase and sale transactions are typically based on published daily or monthly index prices. We utilize financial instruments to hedge various transactions within our natural gas marketing business (see Note 4).

We use third party transportation and storage capacity to link together our non-contiguous natural gas assets. Our natural gas marketing business contracts with third party transportation and storage providers to provide services on both a firm and interruptible basis. This strategy allows us to compliment and strengthen our portfolio of natural gas assets.

Note 13. Related Party Transactions

We believe that the terms and provisions of our related party agreements are fair to us; however, such agreements and transactions may not be as favorable to us as we could have obtained from unaffiliated third parties.

Relationship with EPCO and affiliates

We have an extensive and ongoing relationship with EPCO and its affiliates, which include the following significant entities that are not part of our consolidated group of companies:

§	EPCO and its private company subsidiaries;

§	Enterprise GP Holdings, which owns and controls EPGP;

§	TEPPCO, which is owned and controlled by Enterprise GP Holdings; and

§	the Employee Partnerships (see Note 3).

We also have an ongoing relationship with Duncan Energy Partners, the balance sheet of which is consolidated with that of our own. Our transactions with Duncan Energy Partners are eliminated in consolidation. A description of our relationship with Duncan Energy Partners is presented within this Note 13.

EPCO is a private company controlled by Dan L. Duncan, who is also a Director and Chairman of EPGP. At September 30, 2008, EPCO and its affiliates beneficially owned 149,433,410 (or 34.1%) of Enterprise Products Partners’ outstanding common units, which include 13,454,498 of Enterprise Products Partners’ common units owned by Enterprise GP Holdings. In addition, at September 30, 2008, EPCO and its affiliates beneficially owned 77.8% of the limited partner interests of Enterprise GP Holdings and 100% of its general partner, EPE Holdings. Enterprise GP Holdings owns all of the membership interests of EPGP. The principal business activity of EPGP is to act as Enterprise Products Partners’ managing partner. The executive officers and certain of the directors of EPGP and EPE Holdings are employees of EPCO.

In connection with its general partner interest in Enterprise Products Partners, EPGP received cash distributions of $106.4 million from Enterprise Products Partners during the nine months ended September

30, 2008. This amount includes incentive distributions of $92.8 million for the nine months ended September 30, 2008.

Enterprise Products Partners and EPGP are both separate legal entities apart from each other and apart from EPCO, Enterprise GP Holdings and their respective other affiliates, with assets and liabilities that are separate from those of EPCO, Enterprise GP Holdings and their respective other affiliates. EPCO and its private company subsidiaries depend on the cash distributions they receive from Enterprise Products Partners, Enterprise GP Holdings and other investments to fund their other operations and to meet their debt obligations. EPCO and its private company affiliates received directly from Enterprise Products Partners $300.2 million in cash distributions during the nine months ended September 30, 2008.

The ownership interests in Enterprise Products Partners that are owned or controlled by Enterprise GP Holdings are pledged as security under its credit facility. In addition, substantially all of the ownership interests in Enterprise Products Partners 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 a private company affiliate of EPCO. This credit facility contains customary and other events of default relating to EPCO and certain affiliates, including Enterprise GP Holdings, TEPPCO and Enterprise Products Partners.

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.

EPCO Administrative Services Agreement

We have no employees. All of our operating functions and general and administrative support services are provided by employees of EPCO pursuant to the ASA. Enterprise Products Partners, Duncan Energy Partners, Enterprise GP Holdings, TEPPCO and their respective general partners are parties to the ASA. The ACG Committees of each general partner have approved the ASA.

Under the ASA, we reimburse EPCO for all costs and expenses it incurs in providing management, administrative and operating services for us, including compensation of employees (i.e., salaries, medical benefits and retirement benefits). Since the vast majority of such expenses are charged to us on an actual basis (i.e. no mark-up or subsidy is charged or received by EPCO), we believe that such expenses are representative of what the amounts would have been on a stand-alone basis. With respect to allocated costs, we believe that the proportional direct allocation method employed by EPCO is reasonable and reflective of the estimated level of costs we would have incurred on a stand-alone basis. The ASA also addresses potential conflicts in business opportunities that may arise among Enterprise Products Partners, Enterprise GP Holdings, Duncan Energy Partners and other affiliates of EPCO.

Relationship with TEPPCO

TEPPCO became a related party to us in February 2005 when its general partner was acquired by private company affiliates of EPCO. Our relationship with TEPPCO was further reinforced by the acquisition of TEPPCO’s general partner by Enterprise GP Holdings in May 2007. Enterprise GP Holdings also owns EPGP.

In August 2006, we formed a joint venture with TEPPCO involving Jonah, which owns the Jonah Gas Gathering System located in the Greater Green River Basin of southwestern Wyoming. The Jonah Gas Gathering 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-user markets. Currently, the gathering capacity of this system is 2.4 Bcf/d. We own an approximate 19.4% interest in Jonah and TEPPCO owns the remaining 80.6% interest. We account for our investment in the Jonah joint venture using the equity method of accounting.

During the first quarter of 2008, Jonah initiated a separate project to increase gathering capacity on that portion of its system that serves the Pinedale production field. This new project is expected to increase overall capacity of the Jonah Gas Gathering System by an additional 0.2 Bcf/d. The total anticipated cost of this new project is $125.0 million, of which we will be responsible for our share of the construction costs.

In August 2008, we, together with TEPPCO and Oiltanking, announced the formation of a joint venture to design, construct, operate and own a Texas offshore crude oil port and pipeline system to facilitate delivery of waterborne crude oil to refining centers located along the upper Texas Gulf Coast. See Note 7 for additional information regarding the Texas Offshore Port System joint venture.

Relationship with Duncan Energy Partners

On February 5, 2007, Duncan Energy Partners completed its initial public offering of 14,950,000 common units. At September 30, 2008, Enterprise Products Partners beneficially owned 5,351,571 of Duncan Energy Partners’ common units. Enterprise Products Partners also own the 2% general partner interest in Duncan Energy Partners. EPO directs the business operations of Duncan Energy Partners through its ownership and control of the general partner of Duncan Energy Partners.

As a result of contributions EPO made at the time of Duncan Energy Partners’ initial public offering in February 2007, Duncan Energy Partners owns 66% of the equity interests in the following entities and EPO owns the remaining 34% of the equity interests:

§	Mont Belvieu Caverns, LLC (“Mont Belvieu Caverns”),

§	Acadian Gas, LLC (“Acadian Gas”),

§	Sabine Propylene Pipeline L.P. (“Sabine Propylene”),

§	Enterprise Lou-Tex Propylene Pipeline L.P. (“Lou-Tex Propylene”), and

§	South Texas NGL Pipelines, LLC (“South Texas NGL”).

Enterprise Products Partners has significant involvement with all of the subsidiaries of Duncan Energy Partners, including the following types of transactions:

§	It utilizes storage services provided by Mont Belvieu Caverns to support its Mont Belvieu fractionation and other businesses;

§	It buys natural gas from and sells natural gas to Acadian Gas in connection with its normal business activities; and

§	It is currently the sole shipper on the DEP South Texas NGL Pipeline System.

EPO may contribute or sell other equity interests in its subsidiaries, or other of its or its subsidiaries’ assets, to Duncan Energy Partners. EPO has no obligation or commitment to make such contributions or sales to Duncan Energy Partners.

Effective February 1, 2007, EPO is allocated all operational measurement gains and losses relating to Mont Belvieu Caverns’ underground storage activities. Operational measurement gains and losses are created when product is moved between storage wells and are attributable to pipeline and well connection measurement variances. As a result, EPO is required each period to contribute cash to Mont Belvieu Caverns for net operational measurement losses and is entitled to receive distributions from Mont Belvieu Caverns for net operational measurement gains.

Omnibus Agreement. In February 2007, EPO entered into an Omnibus Agreement with Duncan Energy Partners that governs the following matters:

§	indemnification by EPO of certain environmental liabilities, tax liabilities and right-of-way defects with respect to assets EPO contributed to Duncan Energy Partners in February 2007;

§	reimbursement by EPO of certain capital expenditures incurred by South Texas NGL and Mont Belvieu Caverns with respect to projects under construction at the time of Duncan Energy Partners’ initial public offering;

§	a right of first refusal to EPO in Duncan Energy Partners’ current and future subsidiaries and a right of first refusal on the material assets of such subsidiaries, other than sales of inventory and other assets in the ordinary course of business; and

§	a preemptive right with respect to equity securities issued by certain of Duncan Energy Partners’ subsidiaries, other than as consideration in an acquisition or in connection with a loan or debt financing.

Neither EPO nor any of its affiliates are restricted under the Omnibus Agreement from competing against Duncan Energy Partners. As provided for in the EPCO ASA, EPO and its affiliates may acquire, construct or dispose of additional midstream energy or other assets in the future without any obligation to offer Duncan Energy Partners the opportunity to acquire or construct such assets.

As noted previously, EPO indemnified Duncan Energy Partners for certain environmental liabilities, tax liabilities and right-of-way defects associated with the assets EPO contributed to Duncan Energy Partners in February 2007. These indemnifications terminate on February 5, 2010. There is an aggregate cap of $15.0 million on the amount of indemnity coverage and Duncan Energy Partners is not entitled to indemnification until the aggregate amount of claims it incurs exceeds $250 thousand. Environmental liabilities resulting from a change of law after February 5, 2007 are excluded from the indemnity. Duncan Energy Partners made no claims to EPO during the three and nine months ended September 30, 2008 in connection with these indemnity provisions.

Under the Omnibus Agreement, EPO agreed to make additional cash contributions to South Texas NGL and Mont Belvieu Caverns to fund 100% of project costs in excess of (i) the $28.6 million of estimated costs to complete the Phase II expansion of the DEP South Texas NGL Pipeline System and (ii) the $14.1 million of estimated costs for additional Mont Belvieu brine production capacity and above-ground storage reservoir projects. These projects were in progress at the time of Duncan Energy Partners’ initial public offering. EPO made cash contributions of $32.5 million under the Omnibus Agreement to the subsidiaries of Duncan Energy Partners during the nine months ended September 30, 2008. This amount was primarily contributed to South Texas NGL to fund costs of its Phase II pipeline project. We expect EPO to make contributions of approximately $2.1 million during the remainder of 2008 in satisfaction of its project funding obligations under the Omnibus Agreement.

EPO will not receive an increased allocation of earnings or cash flows as a result of these contributions to South Texas NGL and Mont Belvieu Caverns. EPO’s payments under the Omnibus Agreement are accounted for as additional investments by EPO in the underlying companies and are subsequently eliminated in the preparation of our consolidated balance sheet.

Mont Belvieu Caverns’ LLC Agreement. The Mont Belvieu Caverns’ LLC Agreement (the “Caverns LLC Agreement”) states that if Duncan Energy Partners elects to not participate in certain projects of Mont Belvieu Caverns, then EPO is responsible for funding 100% of such projects. To the extent such non-participated projects generate identifiable incremental cash flows for Mont Belvieu Caverns in the future, the earnings and cash flows of Mont Belvieu Caverns will be adjusted to allocate such incremental amounts to EPO by special allocation or otherwise. Under the terms of the Caverns LLC Agreement, Duncan Energy Partners may elect to acquire a 66% share of these projects from EPO within 90 days of such projects being placed in-service. In November 2008, the Caverns LLC Agreement was

amended to provide that EPO would prospectively receive a special allocation of 100% of the depreciation related to projects that it has fully funded.

EPO made cash contributions of $86.4 million under the Caverns LLC Agreement during the nine months ended September 30, 2008. These expenditures are associated with storage-related projects sponsored by EPO’s NGL marketing activities and represent 100% of the costs of such projects to date. EPO expects that its NGL marketing activities will benefit from these projects. At present, Mont Belvieu Caverns is not expected to generate any identifiable incremental cash flows in connection with these projects; thus, the sharing ratio for Mont Belvieu Caverns is not expected to change from the current ratio of 66% for Duncan Energy Partners and 34% for EPO. However, as noted above, beginning in November 2008, EPO will receive a special allocation of depreciation related to these projects. We expect EPO to make $37.5 million of contributions to Mont Belvieu Caverns in connection with these construction projects during the remainder of 2008 through the first quarter of 2009. The constructed assets are the property of Mont Belvieu Caverns.

EPO’s payments under the Caverns LLC Agreement are accounted for as additional investments by EPO in Mont Belvieu Caverns and are subsequently eliminated in the preparation of our consolidated balance sheet.

Relationship with Energy Transfer Equity

Enterprise GP Holdings acquired equity method investments in Energy Transfer Equity and its general partner in May 2007. As a result, Energy Transfer Equity and its consolidated subsidiaries became related parties to our consolidated businesses.

We have a long-term revenue generating contract with Titan Energy Partners, L.P. (“Titan”), a consolidated subsidiary of ETP. Titan purchases substantially all of its propane requirements from us. We and Energy Transfer Company (“ETC OLP”) transport natural gas on each other’s systems and share operating expenses on certain pipelines. ETC OLP also sells natural gas to us.

Relationships with Unconsolidated Affiliates

Our significant related party revenue and expense 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. For additional information regarding our unconsolidated affiliates, see Note 7.

See “Relationship with TEPPCO” within this Note 13 for a description of ongoing transactions involving our Jonah and TOPS joint ventures with TEPPCO.

Note 14. Commitments and Contingencies

Litigation

On occasion, we or our unconsolidated affiliates are named as a defendant in litigation relating to our normal business activities, including regulatory and environmental matters. Although we are insured 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 unaware of any significant litigation, pending or threatened, that could have a significant adverse effect on our financial position.

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 our affiliates. Mr. Brinkerhoff filed an amended complaint on July 12, 2007. The complaint names as defendants (i) TEPPCO, certain of its current and former directors, and certain of its affiliates; (ii) Enterprise Products Partners and certain of our affiliates; (iii) EPCO; and (iv) Dan L. Duncan.

The amended complaint alleges, among other things, that the defendants caused TEPPCO to enter into certain transactions that were unfair to TEPPCO or otherwise unfairly favored Enterprise Products Partners or its affiliates over TEPPCO. These transactions are alleged to include: (i) the joint venture to further expand the Jonah system entered into by TEPPCO and Enterprise Products Partners in August 2006; (ii) the sale by TEPPCO of its Pioneer natural gas processing plant to Enterprise Products Partners in March 2006; and (iii) certain amendments to TEPPCO’s partnership agreement, including a reduction in the maximum tier of TEPPCO’s incentive distribution rights in exchange for TEPPCO common units. The amended complaint seeks (i) rescission of the amendments to TEPPCO’s partnership agreement; (ii) damages for profits and special benefits allegedly obtained by defendants as a result of the alleged wrongdoings in the amended 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. See Note 13 for additional information regarding our relationship with TEPPCO.

On February 14, 2007, EPO received a letter from the Environment and Natural Resources Division (“ENRD”) of the U.S. Department of Justice (“DOJ”) related to an ammonia release in Kingman County, Kansas on October 27, 2004 from a pressurized anhydrous ammonia pipeline owned by a third party, Magellan Ammonia Pipeline, L.P. (“Magellan”) and a previous release of ammonia on September 27, 2004 from the same pipeline. EPO was the operator of this pipeline until July 1, 2008. The ENRD has indicated that it may pursue civil damages against EPO and Magellan as a result of these incidents. Based on this correspondence from the ENRD, the statutory maximum amount of civil fines that could be assessed against EPO and Magellan is up to $17.4 million in the aggregate. EPO is cooperating with the DOJ and is hopeful that an expeditious resolution of this civil matter acceptable to all parties will be reached in the near future. Magellan has agreed to indemnify EPO for the civil matter. At this time, we do not believe that a final resolution of the civil claims by the ENRD will have a material impact on our consolidated financial position.

On October 25, 2006, a rupture in the Magellan Ammonia Pipeline resulted in the release of ammonia near Clay Center, Kansas. The pipeline has been repaired and environmental remediation tasks related to this incident have been completed. At this time, we do not believe that this incident will have a material impact on our consolidated financial position.

Several lawsuits have been filed by municipalities and other water suppliers against a number of manufacturers of reformulated gasoline containing methyl tertiary butyl ether. In general, such suits have not named manufacturers of this product 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 manufacturers such as our subsidiary could ultimately be added as defendants in such lawsuits or in new lawsuits.

The Attorney General of Colorado on behalf of the Colorado Department of Public Health and Environment filed suit against us and others on April 15, 2008 in connection with the construction of a pipeline near Parachute, Colorado. The State sought a temporary restraining order and an injunction to halt construction activities since it alleged that the defendants failed to install measures to minimize damage to the environment and to follow requirements for the pipeline’s stormwater permit and appropriate stormwater plan. The State’s complaint also seeks penalties for the above alleged failures. Defendants and the State agreed to certain stipulations that, among other things, require us to install specified environmental protection measures in the disturbed pipeline right-of-way to comply with regulations. We have complied with the stipulations and the State has dismissed the portions of the complaint seeking the temporary restraining order and injunction. The State has not yet assessed penalties and we are unable to predict the amount of penalties that may be assessed. At this time, we do not believe that this incident will have a material impact on our consolidated financial position.

Contractual Obligations

Operating Lease Obligations. 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 affiliates of EPCO, (iii) a railcar unloading terminal in Mont Belvieu, Texas and (iv) land held pursuant to right-of-way agreements. In general, our material lease agreements have original terms that range from two to 28 years and include renewal options that could extend the agreements for up to an additional 20 years.

Scheduled Maturities of Long-Term Debt. With the exception of the issuance of Senior Notes M and N by EPO in April 2008 and routine fluctuations in the balance of our consolidated revolving credit facilities, there have been no significant changes in our consolidated scheduled maturities of long-term debt since those reported in our Audited Consolidated Balance Sheet for the year ended December 31, 2007, which was included as an exhibit to the Current Report on Form 8-K filed by Enterprise Products Partners on March 14, 2008. See Note 10 for additional information regarding the issuance of senior notes by EPO.

Purchase Obligations. There have been no material changes in our consolidated purchase obligations since December 31, 2007, except for commitments associated with two long-term natural gas purchase agreements and certain pipeline capacity reservation agreements that we executed in 2008 to support our natural gas marketing activities. The following table presents our estimated purchase commitments (in terms of volumes and cost) under these new agreements for the periods indicated:

			Payment or Settlement due by Period
			Less than			1-3		4-5	More than
	Total		1 year		years		years		5 years
Product purchase commitments:
Estimated payment obligations:
Natural gas	$	5,707,213	$	261,703	$	985,430	$	1,232,670	$	3,227,410
Underlying volume commitment:
Natural gas (in billion British thermal units)		927,765		45,360		158,775		199,505		524,125
Service payment commitments
for pipeline capacity reservation	$	157,633	$	2,730	$	27,414	$	30,074	$	97,415

Estimated future payment obligations for natural gas shown in the preceding table are based on the contractual price under each contract for purchases made at September 30, 2008 applied to all future volume commitments. Actual future payment obligations under these natural gas purchase agreements will vary depending on market prices at the time of delivery.

Other Claims

As part of our normal business activities with joint venture partners and certain customers and suppliers, we occasionally have claims made against us as a result of disputes related to contractual agreements or similar arrangements. As of September 30, 2008, claims against us totaled approximately $3.0 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 such disputes 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 balance sheet.

Note 15. Significant Risks and Uncertainties – Weather-Related Risks

We participate as a named insured in EPCO’s insurance program, which provides us with property damage, business interruption and other coverages, the scope and amounts of which are customary and sufficient for the nature and extent of our operations. While we believe EPCO maintains adequate insurance coverage on our behalf, insurance will not cover every type of interruption that might occur. If we were to incur a significant liability for which we were not fully insured, it could have a material impact

on our consolidated financial position. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient to reimburse us for our repair costs or lost income. Any event that interrupts the revenues generated by our consolidated operations, or which causes us to make significant expenditures not covered by insurance, could reduce our ability to pay distributions to our partners and, accordingly, adversely affect the market price of Enterprise Products Partners’ common units.

For windstorm events such as hurricanes and tropical storms, EPCO’s deductible for onshore physical damage is $10.0 million per storm. For offshore assets, the windstorm deductible is $10.0 million per storm plus a one-time $15.0 million aggregate deductible per policy period. For non-windstorm events, EPCO’s deductible for onshore and offshore physical damage is $5.0 million per occurrence. In meeting the deductible amounts, property damage costs are aggregated for EPCO and its affiliates, including Enterprise Products Partners. Accordingly, our exposure with respect to the deductibles may be equal to or less than the stated amounts depending on whether other EPCO or affiliate assets are also affected by an event.

To qualify for business interruption coverage in connection with a windstorm event, covered assets must be out-of-service in excess of 60 days for onshore assets and 75 days for offshore assets. To qualify for business interruption coverage in connection with a non-windstorm event, covered onshore and offshore assets must be out-of-service in excess of 60 days.

Hurricanes Gustav and Ike

In the third quarter of 2008, our onshore and offshore facilities located along the Gulf Coast of Texas and Louisiana were adversely impacted by Hurricanes Gustav and Ike. The disruptions in natural gas, NGL and crude oil production caused by these storms resulted in decreased volumes for some of our pipeline systems, natural gas processing plants, NGL fractionators and offshore platforms. As a result of our allocated share of EPCO’s insurance deductibles for windstorm coverage, we expensed a combined $46.0 million of repair costs for property damage in connection with these two storms. We expect to file property damage insurance claims to the extent repair costs exceed this amount. Due to the recent nature of these storms, we are still evaluating the total cost of repairs and the potential for business interruption claims on certain assets.

Pre-2008 Hurricanes (Katrina, Rita, et al)

The following table summarizes the proceeds we received from business interruption and property damage insurance claims with respect to certain named storms for the nine months ended September 30, 2008:

Business interruption proceeds:
Hurricane Ivan	$	--
Hurricane Katrina		501
Hurricane Rita		662
Other		--
Total proceeds		1,163
Property damage proceeds:
Hurricane Ivan		--
Hurricane Katrina		9,404
Hurricane Rita		2,678
Other		--
Total proceeds		12,082
Total	$	13,245

At September 30, 2008, we have $30.8 million of estimated property damage claims outstanding related to these storms that we believe are probable of collection through 2009. To the extent we estimate the dollar value of such damages, please be aware that a change in our estimates may occur as additional information becomes available.

Note 16. Condensed Financial Information of EPO

EPO conducts substantially all of our business. Currently, neither EPGP nor Enterprise Products Partners have any independent operations and material assets outside those of EPO. EPO consolidates the balance sheet of Duncan Energy Partners with that of its own.

Enterprise Products Partners L.P. guarantees the debt obligations of EPO, with the exception of the Dixie revolving credit facility and the Duncan Energy Partners’ revolving credit facility. If EPO were to default on any of its guaranteed debt, Enterprise Products Partners L.P. would be responsible for full repayment of that obligation. See Note 10 for additional information regarding our consolidated debt obligations.

The reconciling items between our consolidated balance sheet and that of EPO are insignificant. The following table presents condensed consolidated balance sheet data for EPO at September 30, 2008:

ASSETS
Current assets	$	2,993,491
Property, plant and equipment, net		12,693,619
Investments in and advances to unconsolidated affiliates, net		917,193
Intangible assets, net		866,313
Goodwill		616,996
Deferred tax asset		2,320
Other assets		69,067
Total	$	18,158,999
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	$	3,170,816
Long-term debt		8,458,195
Other long-term liabilities		89,263
Minority interest		422,499
Partners’ equity		6,018,226
Total	$	18,158,999

Total EPO debt obligations guaranteed by Enterprise Products Partners L.P.	$	8,212,201