8-K

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):  October 26, 2009

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:

¨ 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.

Unless the context requires otherwise, references in this Current Report on Form 8-K to “we,” “us,” or “our” are intended to mean the business and operations of Enterprise Products GP, LLC (“EPGP”) and its consolidated subsidiaries, which include Enterprise Products Partners L.P. (“Enterprise Products Partners”) and its consolidated subsidiaries. EPGP is the general partner of Enterprise Products Partners.

As described in our Current Report on Form 8-K dated November 16, 2009 and within this Current Report on Form 8-K, Enterprise Products Partners completed the related mergers of its wholly owned subsidiaries with TEPPCO Partners, L.P. (“TEPPCO”) and its general partner, Texas Eastern Products Pipeline Company, LLC (“TEPPCO GP”), on October 26, 2009 (such related mergers referred to herein individually and together as the “TEPPCO Merger”).

The TEPPCO Merger transactions were accounted for as a reorganization of entities under common control in a manner similar to a pooling of interests.  The financial and operating activities of Enterprise Products Partners, TEPPCO and Enterprise GP Holdings L.P. and their respective general partners, and EPCO, Inc. and its privately held subsidiaries, are under the common control of Dan L. Duncan.   The purpose of the disclosures presented in this Current Report on Form 8-K is to recast certain financial and other information of EPGP to include TEPPCO and TEPPCO GP.

The inclusion of TEPPCO and TEPPCO GP in the supplemental consolidated balance sheets and other disclosures presented within this Current Report on Form 8-K was effective January 1, 2005 since an affiliate of EPCO under common control with Enterprise Products Partners originally acquired ownership interests in TEPPCO GP in February 2005.

Our supplemental consolidated balance sheets prior to the effective date of the TEPPCO Merger reflect the combined financial information of EPGP, TEPPCO and TEPPCO GP on a 100% basis.  Third party and related party ownership interests in TEPPCO and TEPPCO GP prior to the merger have been reflected as “Former owners of TEPPCO,” which is a component of noncontrolling interest.

We revised our business segments and related disclosures to reflect the TEPPCO Merger.  Our reorganized business segments reflect the manner in which these businesses are managed and reviewed by the chief executive officer of EPGP.  Under our new business segment structure, we have five reportable business segments:  (i) NGL Pipelines & Services; (ii) Onshore Natural Gas Pipelines & Services; (iii) Onshore Crude Oil Pipelines & Services; (iv) Offshore Pipelines & Services; and (v) Petrochemical & Refined Products Services.

Item 9.01.  Financial Statements and Exhibits.

(d)  Exhibits.

Exhibit No.	Description
23.1	Consent of Deloitte & Touche LLP
99.1	Recast of Exhibit 99.2 of Enterprise Products Partners L.P.’s Current Report on Form 8-K dated
	July 8, 2009.
99.2	Recast of Exhibit 99.1 of Enterprise Products Partners L.P.’s Current Report on Form 8-K dated         November 16, 2009.

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: December 18, 2009	By:	/s/ Michael J. Knesek
	Name:		Michael J. Knesek
	Title:		Senior Vice President, Controller and Principal Accounting Officer of Enterprise Products GP, LLC

EX-23.1

EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in (i) Registration Statement Nos. 333-36856, 333-82486, 333-115633, 333-115634, 333-150680, 333-162666 of Enterprise Products Partners L.P. on Form S-8; (ii) Registration Statement No. 333-145709 of Enterprise Products Partners L.P. and Enterprise Products Operating LLC on Form S-3; and (iii) Registration Statement No. 333-142106 of Enterprise Products Partners L.P. on Form S-3 of our report dated December 18, 2009 (which report expresses an unqualified opinion and includes an explanatory paragraph concerning the retroactive effects of the common control acquisition of TEPPCO Partners, L.P. and Texas Eastern Products Pipeline Company, LLC by Enterprise Products Partners L.P. and the related change in business segments described in Note 1), relating to the supplemental consolidated balance sheet of Enterprise Products GP, LLC and subsidiaries at December 31, 2008, appearing in this Current Report on Form 8-K of Enterprise Products Partners L.P.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

December 18, 2009

EX-99.1

EXHIBIT 99.1

ENTERPRISE PRODUCTS GP, LLC

RECAST OF EXHIBIT 99.2 FROM CURRENT REPORT ON FORM 8-K DATED JULY 8, 2009

TABLE OF CONTENTS

		Page No.
Report of Independent Registered Public Accounting Firm		2
Supplemental Consolidated Balance Sheet as of December 31, 2008		3
Notes to Supplemental Consolidated Balance Sheet
	Note 1 – Company Organization and Basis of Presentation	4
	Note 2 – General Accounting Matters	6
	Note 3 – Recent Accounting Developments	13
	Note 4 – Accounting for Equity Awards	15
	Note 5 – Employee Benefit Plans	22
	Note 6 – Derivative Instruments, Hedging Activities and Fair Value Measurements	23
	Note 7 – Inventories	29
	Note 8 – Property, Plant and Equipment	30
	Note 9 – Investments in Unconsolidated Affiliates	32
	Note 10 – Business Combinations	35
	Note 11 – Intangible Assets and Goodwill	37
	Note 12 – Debt Obligations	41
	Note 13 – Equity	51
	Note 14 – Business Segments	52
	Note 15 – Related Party Transactions	53
	Note 16 – Provision for Income Taxes	61
	Note 17 – Commitments and Contingencies	62
	Note 18 – Significant Risks and Uncertainties	67
	Note 19 – Subsequent Events	69

1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Enterprise Products GP, LLC

Houston, Texas

We have audited the accompanying supplemental consolidated balance sheet of Enterprise Products GP, LLC (the "Company") at December 31, 2008.  This supplemental consolidated financial statement is the responsibility of the Company's management.  Our responsibility is to express an opinion on this supplemental consolidated financial statement based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting.  Accordingly, we express no such opinion.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.  An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall supplemental consolidated balance sheet presentation.  We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such supplemental consolidated balance sheet presents fairly, in all material respects, the financial position of the Company at December 31, 2008, in conformity with accounting principles generally accepted in the United States of America.

The supplemental consolidated balance sheet gives retroactive effect to the acquisition of TEPPCO Partners, L.P. (“TEPPCO”) and Texas Eastern Products Pipeline Company, LLC (“TEPPCO GP”) by Enterprise Products Partners L.P. on October 26, 2009, which has been accounted for at historical cost as a reorganization of entities under common control as described in Note 1 to the supplemental consolidated balance sheet.  Also as discussed in Note 1 to the supplemental consolidated balance sheet, the disclosures in the accompanying supplemental consolidated balance sheet have been retrospectively adjusted for a change in the composition of reportable segments as a result of the acquisition TEPPCO and TEPPCO GP by Enterprise Products Partners L.P.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

December 18, 2009

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ENTERPRISE PRODUCTS GP, LLC

SUPPLEMENTAL CONSOLIDATED BALANCE SHEET

AT DECEMBER 31, 2008

(Dollars in millions)

ASSETS
Current assets:
Cash and cash equivalents	$	61.8
Restricted cash		203.8
Accounts and notes receivable – trade, net of allowance for doubtful accounts of $17.7		2,028.5
Accounts receivable – related parties		35.3
Inventories		405.0
Derivative assets		218.6
Prepaid and other current assets		149.8
Total current assets		3,102.8
Property, plant and equipment, net		16,732.8
Investments in unconsolidated affiliates		911.9
Intangible assets, net of accumulated amortization of $675.1		1,182.9
Goodwill		2,019.6
Deferred tax asset		0.4
Other assets		261.3
Total assets	$	24,211.7
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable – trade	$	388.9
Accounts payable – related parties		17.4
Accrued product payables		1,845.7
Accrued interest payable		188.3
Other accrued expenses		65.7
Derivative liabilities		302.9
Other current liabilities		292.3
Total current liabilities		3,101.2
Long-term debt: (see Note 12)
Senior debt obligations – principal		10,030.1
Junior subordinated notes – principal		1,532.7
Other		75.1
Total long-term debt		11,637.9
Deferred tax liabilities		66.1
Other long-term liabilities		110.6
Commitments and contingencies
Equity: (see Note 13)
Member’s interest		526.8
Accumulated other comprehensive loss		(2.0	)
Total member’s equity		524.8
Noncontrolling interest		8,771.1
Total equity		9,295.9
Total liabilities and equity	$	24,211.7

See Notes to Supplemental Consolidated Balance Sheet.

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ENTERPRISE PRODUCTS GP, LLC

NOTES TO SUPPLEMENTAL CONSOLIDATED BALANCE SHEET

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

Note 1.  Company Organization and Basis of Presentation

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 December 31, 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, which now include TEPPCO Partners, L.P. and its general partner.  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” and “TEPPCO GP” mean TEPPCO Partners, L.P. and Texas Eastern Products Pipeline Company, LLC (which is the general partner of TEPPCO), respectively, prior to their mergers with subsidiaries of Enterprise Products Partners.  On October 26, 2009, Enterprise Products Partners completed the mergers with TEPPCO and TEPPCO GP (such related mergers referred to herein individually and together as the “TEPPCO Merger”).  See “TEPPCO Merger and Basis of Presentation” within this Note 1 for additional information regarding the TEPPCO Merger.

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 noncontrolling 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”), Enterprise Unit L.P. (“Enterprise Unit”), EPCO Unit L.P. (“EPCO Unit”), TEPPCO Unit L.P. (“TEPPCO Unit I”), and TEPPCO Unit II L.P. (“TEPPCO Unit II”), collectively, all of which are private company affiliates of EPCO.

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 15).  Duncan Energy Partners owns equity interests in certain of our midstream energy businesses.  References to “DEP GP”

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NOTES TO SUPPLEMENTAL CONSOLIDATED BALANCE SHEET

mean DEP Holdings, LLC, which is the general partner of Duncan Energy Partners and is wholly owned by 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 noncontrolling interest in our Supplemental Consolidated Balance Sheet.  The borrowings of Duncan Energy Partners are presented as part of our consolidated debt; however, neither Enterprise Products Partners nor EPGP have any obligation for the payment of interest or repayment of borrowings incurred by Duncan Energy Partners.

TEPPCO Merger and Basis of Presentation

General.  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 noncontrolling 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 13 for additional information regarding noncontrolling interest in our consolidated subsidiaries.

TEPPCO Merger.  On October 26, 2009, the related mergers of wholly owned subsidiaries of Enterprise Products Partners with TEPPCO and TEPPCO GP were completed.  Under terms of the merger agreements, TEPPCO and TEPPCO GP became wholly owned subsidiaries of Enterprise Products Partners and each of TEPPCO's unitholders, except for a privately held affiliate of EPCO, were entitled to receive 1.24 common units of Enterprise Products Partners for each TEPPCO unit.  In total, Enterprise Products Partners issued an aggregate of 126,932,318 common units and 4,520,431 Class B units (described below) as consideration in the TEPPCO Merger for both TEPPCO units and the TEPPCO GP membership interests.  TEPPCO’s units, which had been trading on the NYSE under the ticker symbol TPP, have been delisted and are no longer publicly traded.

A privately held affiliate of EPCO exchanged a portion of its TEPPCO units, based on the 1.24 exchange rate, for 4,520,431 Class B units of Enterprise Products Partners in lieu of common units.  The Class B units are not entitled to regular quarterly cash distributions for the first sixteen quarters following the closing date of the merger.  The Class B units automatically convert into the same number of common units on the date immediately following the payment date for the sixteenth quarterly distribution following the closing date of the merger.  The Class B units are entitled to vote together with the common units as a single class on partnership matters and, except for the payment of distributions, have the same rights and privileges as Enterprise Products Partners’ common units.

Under the terms of the TEPPCO Merger agreements, Enterprise GP Holdings received 1,331,681 common units of Enterprise Products Partners and an increase in the capital account of EPGP to maintain its 2% general partner interest in Enterprise Products Partners as consideration for 100% of the membership interests of TEPPCO GP.  Following the closing of the TEPPCO Merger, affiliates of EPCO owned approximately 31.3% of Enterprise Products Partners’ outstanding limited partner units, including 3.4% owned by Enterprise GP Holdings.

Since Enterprise Products Partners, TEPPCO and TEPPCO GP are under common control of Mr. Duncan, the TEPPCO Merger was accounted for at historical costs as a reorganization of entities under common control in a manner similar to a pooling of interests.  The inclusion of TEPPCO and TEPPCO GP in our Supplemental Consolidated Balance Sheet was effective January 1, 2005 since an affiliate of EPCO

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ENTERPRISE PRODUCTS GP, LLC

NOTES TO SUPPLEMENTAL CONSOLIDATED BALANCE SHEET

under common control with Enterprise Products Partners originally acquired ownership interests in TEPPCO GP in February 2005.

Our Supplemental Consolidated Balance Sheet at December 31, 2008 reflects the combined balance sheet of Enterprise Products Partners, TEPPCO and TEPPCO GP on a 100% basis.  Third party and related party ownership interests in TEPPCO and TEPPCO GP prior to the merger have been reflected as “Former owners of TEPPCO” a component of noncontrolling interest.

Our supplemental balance sheet has been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”).  The balance sheets of TEPPCO and TEPPCO GP were prepared from the separate accounting records maintained by TEPPCO and TEPPCO GP.  All intercompany balances and transactions were eliminated in consolidation.

We revised our business segments and related disclosures to reflect the TEPPCO Merger.  Our reorganized business segments reflect the manner in which these businesses are managed and reviewed by the chief executive officer of our general partner.  Under our new business segment structure, we have five reportable business segments:  (i) NGL Pipelines & Services; (ii) Onshore Natural Gas Pipelines & Services; (iii) Onshore Crude Oil Pipelines & Services; (iv) Offshore Pipelines & Services; and (v) Petrochemical & Refined Products Services.

Note 2.  General Accounting Matters

Allowance for Doubtful Accounts

Our allowance for doubtful accounts is determined based on specific identification and estimates of future uncollectible accounts.  Our procedure for determining the allowance for doubtful accounts is based on (i) historical experience with customers, (ii) the perceived financial stability of customers based on our research and (iii) the levels of credit we grant to customers.  In addition, we may increase the allowance account in response to the specific identification of customers involved in bankruptcy proceedings and similar financial difficulties.  On a routine basis, we review estimates associated with the allowance for doubtful accounts to ensure that we have recorded sufficient reserves to cover potential losses.  Our allowance also includes estimates for uncollectible natural gas imbalances based on specific identification of accounts.

The following table presents the activity of our allowance for doubtful accounts for the year ended December 31, 2008:

Balance at beginning of period	$	21.8
Charges to expense		3.5
Deductions		(7.6	)
Balance at end of period	$	17.7

See “Credit Risk Due to Industry Concentrations” in Note 18 for more information.

Cash and Cash Equivalents

Cash and cash equivalents represent unrestricted cash on hand and highly liquid investments with original maturities of less than three months from the date of purchase.

Consolidation Policy

Our Supplemental Consolidated Balance Sheet includes our accounts and those of our majority-owned subsidiaries in which we have a controlling interest, after the elimination of all material intercompany accounts and transactions.  We also consolidate other entities and ventures in which we possess a controlling financial interest as well as partnership interests where we are the sole general partner

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NOTES TO SUPPLEMENTAL CONSOLIDATED BALANCE SHEET

of the partnership.  We evaluate our financial interests in business enterprises to determine if they represent variable interest entities where we are the primary beneficiary.  If such criteria are met, we consolidate the balance sheet 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 the entity 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 entity’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 entity’s operating and financial policies.  In consolidation we eliminate our proportionate share of profits and losses from transactions with equity method unconsolidated affiliates to the extent such amounts are material and remain on our Supplemental Consolidated Balance Sheet (or those of our equity method investments) in inventory or similar accounts.

If our ownership interest in an entity does not provide us with either control or significant influence we account for the investment using the cost method.  We currently do not have any investments accounted for using the cost method.

Contingencies

Certain conditions may exist as of the date our supplemental balance sheet is issued, which may result in a loss to us but which will only be resolved when one or more future events occur or fail to occur.  Our management and its legal counsel assess such contingent liabilities, and such assessment inherently involves an exercise in judgment.  In assessing loss contingencies related to legal proceedings that are pending against us or unasserted claims that may result in proceedings, our management and legal counsel evaluate the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.

If the assessment of a contingency indicates that it is probable that a material loss has been incurred and the amount of liability can be estimated, then the estimated liability would be accrued in our supplemental balance sheet.  If the assessment indicates that a potentially material loss contingency is not probable but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss (if determinable and material), is disclosed.

Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed.

Current Assets and Current Liabilities

We present, as individual captions in our Supplemental Consolidated Balance Sheet, all components of current assets and current liabilities that exceed 5% of total current assets and liabilities, respectively.

Deferred Revenues

Amounts billed in advance of the period in which the service is rendered or product delivered are recorded as deferred revenue.  At December 31, 2008, deferred revenues totaled $118.5 million and were recorded as a component of other current and long-term liabilities, as appropriate, on our Supplemental Consolidated Balance Sheet.

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ENTERPRISE PRODUCTS GP, LLC

NOTES TO SUPPLEMENTAL CONSOLIDATED BALANCE SHEET

Employee Benefit Plans

SFAS 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of SFAS 87, 88, 106, and 132(R), requires businesses to record the over-funded or under-funded status of defined benefit pension and other postretirement plans as an asset or liability at a measurement date and to recognize annual changes in the funded status of each plan through other comprehensive income (loss).  

Our consolidated results reflect immaterial amounts related to active and terminated benefit plans.  See Note 5 for additional information regarding our current employee benefit plans.

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.  Expenditures to mitigate or prevent future environmental contamination are capitalized.  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 December 31, 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.

Environmental costs and related accruals were not significant prior to the GulfTerra Merger.  As a result of the merger, we assumed an environmental liability for remediation costs associated with mercury gas meters.  The balance of this environmental liability was $6.3 million at December 31, 2008.  At December 31, 2008, total reserves for environmental liabilities, including those related to the mercury gas meters, were $22.3 million.  At December 31, 2008, $5.3 million of these amounts are classified as current liabilities.

The following table presents the activity of our environmental reserves for the year ended December 31, 2008:

Balance at beginning of period	$	30.5
Charges to expense		5.9
Deductions		(14.1	)
Balance at end of period	$	22.3

Equity Awards

See Note 4 for information regarding our accounting for equity awards.

Estimates

Preparing our supplemental balance sheet in conformity with GAAP requires management to make estimates and assumptions that affect amounts presented in the supplemental balance sheet (i.e. assets and liabilities) 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

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NOTES TO SUPPLEMENTAL CONSOLIDATED BALANCE SHEET

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 8.

Exchange Contracts

Exchanges are contractual agreements for the movements of NGLs and certain petrochemical products between parties to satisfy timing and logistical needs of the parties.  Net exchange volumes borrowed from us under such agreements are valued at market-based prices and included in accounts receivable, and net exchange volumes loaned to us under such agreements are valued at market-based prices and accrued as a liability in accrued product payables.

Receivables and payables arising from exchange transactions are settled with movements of products rather than with cash.  When payment or receipt of monetary consideration is required for product differentials and service costs, such items are recognized in our Supplemental Consolidated Balance Sheet on a net basis.

Derivative Instruments

We use derivative instruments such as swaps, forwards and other contracts to manage price risks associated with inventories, firm commitments, interest rates, foreign currency and certain anticipated transactions.  We recognize these transactions as assets or liabilities on our Supplemental Consolidated Balance Sheet based on the instrument’s fair value.  Fair value is generally defined as the amount at which a derivative instrument could be exchanged in a current transaction between willing parties, not in a forced or liquidation sale.

Changes in fair value of derivative instrument contracts are recognized in earnings in the current period (i.e., using mark-to-market accounting) unless specific hedge accounting criteria are met.  If the derivative 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 derivative instrument meets the criteria of a cash flow hedge, gains and losses incurred on the instrument are recorded in accumulated other comprehensive income (loss), which is generally referred to as “AOCI.”  Gains and losses on cash flow hedges are reclassified from accumulated other comprehensive income (loss) 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 hedging requirements of SFAS 133, Accounting for Derivative Instruments and Hedging Activities (as amended and interpreted).  We formally designate the derivative 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.  See Note 6 for additional information regarding our derivative instruments.

Foreign Currency Translation

We own a NGL marketing business located in Canada.  The financial statements of this foreign subsidiary are translated into U.S. dollars from the Canadian dollar, which is the subsidiary’s functional currency, using the current rate method.  Its assets and liabilities are translated at the rate of exchange in effect at the balance sheet date.  Exchange gains and losses arising from foreign currency translation adjustments are reflected as separate components of accumulated other comprehensive income (loss) in the accompanying Supplemental Consolidated Balance Sheet.  Our net cash flows from this Canadian subsidiary may be adversely affected by changes in foreign currency exchange rates.  See Note 6 for information regarding our hedging of currency risk.

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ENTERPRISE PRODUCTS GP, LLC

NOTES TO SUPPLEMENTAL CONSOLIDATED BALANCE SHEET

Impairment Testing for Goodwill

Our goodwill amounts are assessed for impairment (i) on a routine annual basis or (ii) when impairment indicators are present.  If such indicators occur (e.g., the loss of a significant customer, economic obsolescence of plant assets, etc.), the estimated fair value of the reporting unit to which the goodwill is assigned is determined and compared to its book value.  If the fair value of the reporting unit exceeds its book value including associated goodwill amounts, the goodwill is considered to be unimpaired and no impairment charge is required.  If the fair value of the reporting unit is less than its book value including associated goodwill amounts, a charge to earnings is recorded to reduce the carrying value of the goodwill to its implied fair value.  See Note 11 for additional information regarding our goodwill.

Impairment Testing for Long-Lived Assets

Long-lived assets (including intangible assets with finite useful lives and property, plant and equipment) are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable.

Long-lived assets with carrying values that are not expected to be recovered through future cash flows are written-down to their estimated fair values in accordance with SFAS 144.  The carrying value of a long-lived asset is deemed not recoverable if it exceeds the sum of undiscounted cash flows expected to result from the use and eventual disposition of the asset.  If the asset carrying value exceeds the sum of its undiscounted cash flows, a non-cash asset impairment charge equal to the excess of the asset’s carrying value over its estimated fair value is recorded.  Fair value is defined as the amount at which an asset or liability could be bought or settled in an arm’s-length transaction.  We measure fair value using market price indicators or, in the absence of such data, appropriate valuation techniques.

Impairment Testing for Unconsolidated Affiliates

We evaluate our equity method investments for impairment when events or changes in circumstances indicate that there is a loss in value of the investment attributable to an other than temporary decline.  Examples of such events or changes in circumstances include continuing operating losses of the entity and/or long-term negative changes in the entity’s industry.  In the event we determine that the loss in value of an investment is other than a temporary decline, we record a charge to earnings to adjust the carrying value of the investment to its estimated fair value.  See Note 9 for additional information regarding our equity method investments.

Income Taxes

Provision for income taxes is primarily applicable to our state tax obligations under the Revised Texas Franchise Tax and certain federal and state tax obligations of Seminole Pipeline Company (“Seminole”) and Dixie Pipeline Company (“Dixie”), both of which are consolidated subsidiaries of ours.  Deferred income tax assets and liabilities are recognized for temporary differences between the assets and liabilities of our tax paying entities for financial reporting and tax purposes.

In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax.  In May 2006, the State of Texas expanded its pre-existing franchise tax, which applied to corporations and limited liability companies, to include limited partnerships and limited liability partnerships.  As a result of the change in tax law, our tax status in the State of Texas changed from non-taxable to taxable. 

Since we are structured as a pass-through entity, we are not subject to federal income taxes.  As a result, our partners are individually responsible for paying federal income taxes on their share of our taxable income.  Since we do not have access to information regarding each partner’s tax basis, we cannot readily determine the total difference in the basis of our net assets for financial and tax reporting purposes.

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In accordance with Financial Accounting Standards Board Interpretation 48, Accounting for Uncertainty in Income Taxes, we must recognize the tax effects of any uncertain tax positions we may adopt, if the position taken by us is more likely than not sustainable.  If a tax position meets such criteria, the tax effect to be recognized by us would be the largest amount of benefit with more than a 50% chance of being realized upon settlement.  This guidance was effective January 1, 2007, and our adoption of this guidance had no material impact on our financial position.  See Note 16 for additional information regarding our income taxes.

Inventories

Inventories primarily consist of NGLs, petroleum products, certain petrochemical products and natural gas volumes that are valued at the lower of average cost or market.  We capitalize, as a cost of inventory, shipping and handling charges directly related to volumes we purchase from third parties or take title to in connection with processing or other agreements.  As these volumes are sold and delivered out of inventory, the average cost of these products (including freight-in charges that have been capitalized) are charged to operating costs and expenses.  Shipping and handling fees associated with products we sell and deliver to customers are charged to operating costs and expenses as incurred.  See Note 7 for additional information regarding our inventories.

Natural Gas Imbalances

In the natural gas pipeline transportation business, imbalances frequently result from differences in natural gas volumes received from and delivered to our customers.  Such differences occur when a customer delivers more or less gas into our pipelines than is physically redelivered back to them during a particular time period.  We have various fee-based agreements with customers to transport their natural gas through our pipelines.  Our customers retain ownership of their natural gas shipped through our pipelines.  As such, our pipeline transportation activities are not intended to create physical volume differences that would result in significant accounting or economic events for either our customers or us during the course of the arrangement.

We settle pipeline gas imbalances through either (i) physical delivery of in-kind gas or (ii) in cash. These settlements follow contractual guidelines or common industry practices.  As imbalances occur, they may be settled (i) on a monthly basis, (ii) at the end of the agreement or (iii) in accordance with industry practice, including negotiated settlements.  Certain of our natural gas pipelines have a regulated tariff rate mechanism requiring customer imbalance settlements each month at current market prices.

However, the vast majority of our settlements are through in-kind arrangements whereby incremental volumes are delivered to a customer (in the case of an imbalance payable) or received from a customer (in the case of an imbalance receivable).  Such in-kind deliveries are on-going and take place over several periods. In some cases, settlements of imbalances built up over a period of time are ultimately cashed out and are generally negotiated at values which approximate average market prices over a period of time.  For those gas imbalances that are ultimately settled over future periods, we estimate the value of such current assets and liabilities using average market prices, which is representative of the estimated value of the imbalances upon final settlement.  Changes in natural gas prices may impact our estimates.

At December 31, 2008, our natural gas imbalance receivables, net of allowance for doubtful accounts, were $63.4 million and are reflected as a component of “Accounts and notes receivable – trade” on our Supplemental Consolidated Balance Sheet.  At December 31, 2008, our imbalance payables were $50.8 million and are reflected as a component of “Accrued product payables” on our Supplemental Consolidated Balance Sheet.

Noncontrolling Interest

As presented in our Supplemental Consolidated Balance Sheet, noncontrolling 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 Enterprise Products

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Partners, Duncan Energy Partners, TEPPCO and TEPPCO GP, are consolidated with those of our own, with any third-party or affiliate ownership in such amounts presented as noncontrolling interest.  See Note 13 for information regarding noncontrolling interest.

Property, Plant and Equipment

Property, plant and equipment is recorded at cost.  Expenditures for additions, improvements and other enhancements to property, plant and equipment are capitalized and minor replacements, maintenance, and repairs that do not extend asset life or add value are charged to expense as incurred.  When property, plant and equipment assets are retired or otherwise disposed of, the related cost and accumulated depreciation is removed from the accounts and any resulting gain or loss is included in the results of operations for the respective period.

In general, depreciation is the systematic and rational allocation of an asset’s cost, less its residual value (if any), to the periods it benefits.  The majority of our property, plant and equipment is depreciated using the straight-line method, which results in depreciation expense being incurred evenly over the life of the assets.  Our estimate of depreciation incorporates assumptions regarding the useful economic lives and residual values of our assets.  At the time we place our assets in service, we believe such assumptions are reasonable.  Under our depreciation policy for midstream energy assets, the remaining economic lives of such assets are limited to the estimated life of the natural resource basins (based on proved reserves at the time of the analysis) from which such assets derive their throughput or processing volumes.  Our forecast of the remaining life for the applicable resource basins is based on several factors, including information published by the U.S. Energy Information Administration.  Where appropriate, we use other depreciation methods (generally accelerated) for tax purposes.

                Leasehold improvements are recorded as a component of property, plant and equipment.  The cost of leasehold improvements is charged to earnings using the straight-line method over the shorter of the remaining lease term or the estimated useful lives of the improvements.  We consider renewal terms that are deemed reasonably assured when estimating remaining lease terms.

Our assumptions regarding the useful economic lives and residual values of our assets may change in response to new facts and circumstances, which would change our depreciation amounts prospectively.  Examples of such circumstances include, but are not limited to, the following: (i) changes in laws and regulations that limit the estimated economic life of an asset; (ii) changes in technology that render an asset obsolete; (iii) changes in expected salvage values; or (iv) significant changes in the forecast life of proved reserves of applicable resource basins, if any.  See Note 8 for additional information regarding our property, plant and equipment, including a change in depreciation expense beginning January 1, 2008 resulting from a change in the estimated useful life of certain assets.

Certain of our plant operations entail periodic planned outages for major maintenance activities.  These planned shutdowns typically result in significant expenditures, which are principally comprised of amounts paid to third parties for materials, contract services and related items.  We use the expense-as-incurred method for our planned major maintenance activities; however, the cost of annual planned major maintenance projects are deferred and recognized ratably over the remaining portion of the calendar year in which such projects occur.

Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of tangible long-lived assets that result from their acquisition, construction, development and/or normal operation.  When an ARO is incurred, we record a liability for the ARO and capitalize an equal amount as an increase in the carrying value of the related long-lived asset.  Over time, the liability is accreted to its present value (accretion expense) and the capitalized amount is depreciated over the remaining useful life of the related long-lived asset.  We will incur a gain or loss to the extent that our ARO liabilities are not settled at their recorded amounts.

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Restricted Cash

Restricted cash represents amounts held in connection with our commodity derivative 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.  During 2008, virtually all proceeds from the Petal GO Zone bonds were released by the trustee to fund construction costs associated with the expansion of our Petal, Mississippi storage facility.  The following table presents the components of our restricted cash balances at December 31, 2008:

Amounts held in brokerage accounts related to
commodity hedging activities and physical natural gas purchases	$	203.8
Total restricted cash	$	203.8

Note 3.  Recent Accounting Developments

The accounting standard setting bodies have recently issued the following accounting guidance that will affect our future financial statements:  SFAS 141(R), Business Combinations;  FASB Staff Position (“FSP”) SFAS 142-3, Determination of the Useful Life of Intangible Assets;  SFAS 157, Fair Value Measurements;  SFAS 160, Noncontrolling Interests in Consolidated Financial Statements – An amendment of ARB 51; SFAS 161, Disclosures about Derivative Instruments and Hedging Activities – An Amendment of SFAS 133; and Emerging Issues Task Force (“EITF”) 08-6, Equity Method Investment Accounting Considerations.

SFAS 141(R), Business Combinations. SFAS 141(R) replaces SFAS 141, Business Combinations and was effective January 1, 2009.  SFAS 141(R) retains the fundamental requirements of SFAS 141 in that the acquisition method of accounting (previously termed the “purchase method”) be used for all business combinations and for the “acquirer” to be identified in each business combination.  SFAS 141(R) defines the acquirer as the entity that obtains control of one or more businesses in a business combination and establishes the acquisition date as the date that the acquirer achieves control.  This new guidance also retains guidance in SFAS 141 for identifying and recognizing intangible assets separately from goodwill.   SFAS 141(R) will have an impact on the way in which we evaluate acquisitions.

The objective of SFAS 141(R) is to improve the relevance, representational faithfulness, and comparability of the information a reporting entity provides in its financial reports about business combinations and their effects.  To accomplish this, SFAS 141(R) establishes principles and requirements for how the acquirer:

§   Recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interests in the acquiree.

§   Recognizes and measures any goodwill acquired in the business combination or a gain resulting from a bargain purchase.  SFAS 141(R) defines a bargain purchase as a business combination in which the total acquisition-date fair value of the identifiable net assets acquired exceeds the fair value of the consideration transferred plus any noncontrolling interest in the acquiree, and requires the acquirer to recognize that excess in net income as a gain attributable to the acquirer.

§   Determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination.

SFAS 141(R) also requires that direct costs of an acquisition (e.g. finder’s fees, outside consultants, etc.) be expensed as incurred and not capitalized as part of the purchase price.

FSP FAS 142-3, Determination of the Useful Life of Intangible Assets.  FSP 142-3 revised the factors that should be considered in developing renewal or extension assumptions used in determining the useful life of recognized intangible assets under SFAS 142, Goodwill and Other Intangible Assets.  These

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revisions are 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 measurement and disclosure requirements of this new guidance will be applied to intangible assets acquired after January 1, 2009.   Our adoption of this guidance is not expected to have a material impact on our Supplemental Consolidated Balance Sheet.

SFAS 157, Fair Value Measurements. SFAS 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements.  Although certain provisions of SFAS 157 were effective January 1, 2008, the remaining guidance of this new standard applicable to nonfinancial assets and liabilities was effective January 1, 2009.  See Note 6 for information regarding fair value-related disclosures required for 2008 in connection with SFAS 157.

SFAS 157 applies to fair-value measurements that are already required (or permitted) by other accounting standards and is expected to increase the consistency of those measurements.  SFAS 157 emphasizes that fair value is a market-based measurement that should be determined based on the assumptions that market participants would use in pricing an asset or liability. Companies are required to disclose the extent to which fair value is used to measure assets and liabilities, the inputs used to develop such measurements, and the effect of certain of the measurements on earnings (or changes in net assets) during a period.  Our adoption of this guidance is not expected to have a material impact on our Supplemental Consolidated Balance Sheet.  SFAS 157 will impact the valuation of assets and liabilities (and related disclosures) in connection with future business combinations and impairment testing.

SFAS 160, Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51.  SFAS 160 established accounting and reporting standards for noncontrolling interests, which have been referred to as minority interests in prior accounting literature.  SFAS 160 was effective January 1, 2009.  A noncontrolling interest is that portion of equity in a consolidated subsidiary not attributable, directly or indirectly, to a reporting entity.  This new standard requires, among other things, that (i) ownership interests of noncontrolling interests be presented as a component of equity on the balance sheet (i.e., elimination of the “mezzanine” presentation); (ii) elimination of minority interest expense as a line item on the statement of income and, as a result, that net income be allocated between the reporting entity and noncontrolling interests on the face of the statement of income; and (iii) enhanced disclosures regarding noncontrolling interests.

Effective January 1, 2009, we adopted the provisions of SFAS 160.  The presentation and disclosure requirements of SFAS 160 have been applied retrospectively to the Supplemental Consolidated Balance Sheet and Notes included in this Exhibit 99.1.

SFAS 161, Disclosures about Derivative Instruments and Hedging Activities - An Amendment of SFAS 133.  SFAS 161 revised the disclosure requirements for derivative instruments and related hedging activities to provide users of financial statements with an enhanced understanding of (i) why and how an entity uses derivative instruments, (ii) how an entity accounts for derivative instruments and related hedged items under SFAS 133, Accounting for Derivative Instruments and Hedging Activities (including related interpretations), and (iii) how derivative instruments and related hedged items affect an entity’s financial position.

SFAS 161 requires qualitative disclosures about objectives and strategies for using derivative instruments, quantitative disclosures about fair value amounts of and gains and losses on derivative instruments, and disclosures about credit risk-related contingent features in derivative instrument agreements.  SFAS 161 was effective January 1, 2009 and we will apply its requirements beginning with the first quarter of 2009.

EITF 08-6, Equity Method Investment Accounting Considerations.  EITF 08-6 clarifies the accounting for certain transactions and impairment considerations involving equity method investments under SFAS 141(R) and SFAS 160.  EITF 08-6 generally requires that (i) transaction costs should be included in the initial carrying value of an equity method investment; (ii) an equity method investor shall not test separately an investee’s underlying assets for impairment, rather such testing should be performed

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in accordance with Opinion 18 (i.e., on the equity method investment itself); (iii) an equity method investor shall account for a share issuance by an investee as if the investor had sold a proportionate share of its investment (any gain or loss to the investor resulting from the investee’s share issuance shall be recognized in earnings);  and (iv) a gain or loss should not be recognized when changing the method of accounting for an investment from the equity method to the cost method.  EITF 08-6 was effective January 1, 2009.

Note 4.  Accounting for Equity Awards

We account for equity awards in accordance with SFAS 123(R), Share-Based Payment.  SFAS 123(R) requires us to recognize compensation expense related to equity 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 equity 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-classified awards are settled in cash upon vesting.

As used in the context of the EPCO plans, the term “restricted unit” represents a time-vested unit under SFAS 123(R).  Such awards are non-vested until the required service period expires.

Employee Partnerships

As long-term incentive arrangements, EPCO has granted its key employees who perform services on behalf of us, EPCO and other affiliated companies, “profits interests” in seven limited partnerships (the “Employee Partnerships”), which are private company affiliates of EPCO.  The employees were issued Class B limited partner interests and admitted as Class B limited partners in the Employee Partnerships without capital contributions.  As discussed and defined in Note 1, the Employee Partnerships are:  EPE Unit I; EPE Unit II; EPE Unit III; Enterprise Unit; EPCO Unit; TEPPCO Unit and TEPPCO Unit II.    Enterprise Unit, EPCO Unit, TEPPCO Unit and TEPPCO Unit II were formed in 2008.

The Class B limited partner interests entitle each holder to participate in the appreciation in value of the publicly traded limited partner units owned by the underlying Employee Partnership.  The Employee Partnerships own either Enterprise GP Holdings units (“EPE units”) or Enterprise Products Partners’ common units (“EPD units”) or both.  TEPPCO Unit and TEPPCO Unit II owned units of TEPPCO (“TPP units”) prior to their conversion to EPD units in connection with the TEPPCO Merger.  The Class B limited partner interests are subject to forfeiture if the participating employee’s employment with EPCO is terminated prior to vesting, with customary exceptions for death, disability and certain retirements and upon certain change of control events.

We account for the profits interest awards under SFAS 123(R).  As a result, the compensation expense attributable to these awards is based on the estimated grant date fair value of each award.  An allocated portion of the fair value of these equity-based awards is charged to us under the EPCO administrative services agreement (“ASA”) (see Note 15).  We are not responsible for reimbursing EPCO for any expenses of the Employee Partnerships, including the value of any contributions of cash or limited partner units made by private company affiliates of EPCO at the formation of each Employee Partnership.  However, pursuant to the ASA, beginning in February 2009, we will reimburse EPCO for our allocated share of distributions of cash or securities made to the Class B limited partners of EPCO Unit and TEPPCO Unit II.

Each Employee Partnership has a single Class A limited partner, which is a privately held indirect subsidiary of EPCO, and a varying number of Class B limited partners.  At formation, the Class A limited partner either contributes cash or limited partner units it owns to the Employee Partnership.   If cash is contributed, the Employee Partnership uses these funds to acquire limited partner units on the open market.  In general, the Class A limited partner earns a preferred return (either fixed or variable depending on the

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partnership agreement) on its investment (“Capital Base”) in the Employee Partnership and any residual quarterly cash amounts, if any, are distributed to the Class B limited partners.  Upon liquidation, Employee Partnership assets having a fair market value equal to the Class A limited partner’s Capital Base, plus any preferred return for the period in which liquidation occurs, will be distributed to the Class A limited partner.   Any remaining assets will be distributed to the Class B limited partner(s) as a residual profits interest.

The following table summarizes key elements of each Employee Partnership as of December 31, 2008:

		Initial	Class A
		Class A	Partner	Award	Grant Date	Unrecognized
Employee	Description	Capital	Preferred	Vesting	Fair Value	Compensation
Partnership	of Assets	Base	Return	Date (1)	of Awards (2)	Cost (3)
EPE Unit I	1,821,428 EPE units	$51.0 million	4.50%  to 5.725% (4)	November 2012	$17.0 million	$9.3 million
EPE Unit II	40,725 EPE units	$1.5 million	4.50%  to 5.725% (4)	February 2014	$0.3 million	$0.2 million
EPE Unit III	4,421,326 EPE units	$170.0 million	3.80%	May 2014	$32.7 million	$25.1 million
Enterprise Unit	881,836 EPE units 844,552 EPD units	$51.5 million	5.00%	February 2014	$4.2 million	$3.7 million
EPCO Unit	779,102 EPD units	$17.0 million	4.87%	November 2013	$7.2 million	$7.0 million
TEPPCO Unit	241,380 TPP units	$7.0 million	4.50% to 5.725%	September 2013	$2.1 million	$1.7 million
TEPPCO Unit II	123,185 TPP units	$3.1 million	6.31%	November 2013	$1.4 million	$1.4 million
(1)   The vesting date may be accelerated for change of control and other events as described in the underlying partnership agreements. (2)   Our estimated grant date fair values were determined using a Black-Scholes option pricing model and reflect adjustments for forfeitures, regrants and other modifications.  See following table for information regarding our fair value assumptions. (3)   Unrecognized compensation cost represents the total future expense to be recognized by the EPCO group of companies as of December 31, 2008.   We expect to recognize our allocated share of such costs in the future in accordance with the ASA.   The period over which the unrecognized compensation cost will be recognized is as follows for each Employee Partnership:  3.9 years, EPE Unit I; 5.1 years, EPE Unit II; 5.4 years, EPE Unit III; 5.1 years, Enterprise Unit; 4.9 years, EPCO Unit; 4.7 years, TEPPCO Unit; and 4.9 years, TEPPCO Unit II. (4)   In July 2008, the Class A preferred return was reduced from 6.25% to the floating amounts presented.

The following table summarizes the assumptions we used in deriving the estimated grant date fair value for each of the Employee Partnerships using a Black-Scholes option pricing model:

	Expected	Risk-Free	Expected		Expected
Employee	Life	Interest	Distribution Yield		Unit Price Volatility
Partnership	of Award	Rate	EPE/EPD units	TPP units	EPE/EPD units	TPP units
EPE Unit I	3 to 5 years	2.7% to 5.0%	3.0% to 4.8%	n/a	16.6% to 30.0%	n/a
EPE Unit II	5 to 6 years	3.3% to 4.4%	3.8% to 4.8%	n/a	18.7% to 19.4%	n/a
EPE Unit III	4 to 6 years	3.2% to 4.9%	4.0% to 4.8%	n/a	16.6% to 19.4%	n/a
Enterprise Unit	6 years	2.7% to 3.9%	4.5% to 8.0%	n/a	15.3% to 22.1%	n/a
EPCO Unit	5 years	2.4%	11.1%	n/a	50.0%	n/a
TEPPCO Unit	5 years	2.9%	n/a	7.3%	n/a	16.4%
TEPPCO Unit II	5 years	2.4%	n/a	13.9%	n/a	66.4%

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EPCO 1998 Plan

Unit option awards.  Under the EPCO 1998 Long-Term Incentive Plan (“EPCO 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.  When issued, the exercise price of each option grant is equivalent to the market price of the underlying equity on the date of grant.  During 2008, in response to changes in the federal tax code applicable to certain types of equity awards, Enterprise Products Partners amended the terms of certain of its outstanding unit options.  In general, the expiration dates of these awards were modified from May and August 2017 to December 2012.

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

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

The EPCO 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 December 31, 2008 and the issuance and forfeiture of restricted unit awards through December 31, 2008, a total of 814,674 additional common units could be issued under the EPCO 1998 Plan.

The following table presents unit option activity under the EPCO 1998 Plan for the year ended December 31, 2008:

						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		(85,000	)		26.72
Outstanding at December 31, 2008 (3)		2,168,500			26.32		5.19	$	--
Options exercisable at:
December 31, 2008 (3)		548,500		$	21.47		4.08	$	--
(1)   Aggregate intrinsic value reflects fully vested unit options at the date indicated. (2)   During 2008, Enterprise Products Partners amended the terms of certain of its outstanding unit options. In general, the expiration dates of these awards were modified from May and August 2017 to December 2012. (3)   Enterprise Products Partners was committed to issue 2,168,500 and 2,315,000 of its common units at December 31, 2008 and 2007, respectively, if all outstanding options awarded under the EPCO 1998 Plan (as of these dates) were exercised. An additional 365,000, 480,000 and 775,000 of these options are exercisable in 2009, 2010 and 2012, respectively.

The total intrinsic value of option awards exercised during the year ended December 31, 2008 was $0.6 million.  During the year ended December 31, 2008, we received cash of $0.7 million from the exercise of option awards granted under the EPCO 1998 Plan.  Conversely, our option-related reimbursements to EPCO were $0.6 million.

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Restricted unit awards.  Under the EPCO 1998 Plan, we may also issue restricted common units of Enterprise Products Partners to key employees of EPCO and directors of EPGP.  In general, the restricted unit awards of Enterprise Products Partners allow recipients to acquire the underlying common units at no cost to the recipient once a defined cliff vesting period expires, subject to certain forfeiture provisions.  The restrictions on such units generally lapse four years from the date of grant.  Fair value of such restricted units is based on the market price of the underlying common units on the date of grant and an allowance for estimated forfeitures.

The following table presents restricted unit activity under the EPCO 1998 Plan for the year ended December 31, 2008:

				Weighted-
				Average Grant
	Number of			Date Fair Value
	Units			per Unit (1)
Restricted units at December 31, 2007		1,688,540
Granted (2)		766,200		$	24.93
Vested		(285,363	)	$	23.11
Forfeited		(88,777	)	$	26.98
Restricted units at December 31, 2008		2,080,600
(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 unit awards issued during 2008 was $19.1 million based on grant date market prices of Enterprise Products Partners’ common units ranging from $25.00 to $32.31 per unit and an estimated forfeiture rate of 17.0%.

The total fair value of restricted unit awards that vested during the year ended December 31, 2008 was $6.6 million.

Phantom unit awards.  The EPCO 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.  The fair market value of each phantom unit award is equal to the market closing price of Enterprise Products Partners’ common units on the redemption date.  Each participant is required to redeem their phantom units as they vest, which typically is four years from the date the award is granted.  No phantom unit awards have been issued to date under the EPCO 1998 Plan.

The EPCO 1998 Plan also provides for the award of distribution equivalent rights (“DERs”) in tandem with its phantom unit awards.  A DER entitles the participant to cash distributions equal to the product of the number of phantom units outstanding for the participant and the cash distribution rate paid by Enterprise Products Partners to its unitholders.  No DERs have been issued as of December 31, 2008 under the EPCO 1998 Plan.

EPD 2008 LTIP

On January 29, 2008, Enterprise Products Partners’ unitholders approved the Enterprise Products Partners 2008 Long-Term Incentive Plan (“EPD 2008 LTIP”), which provides for awards of Enterprise Products Partners’ common units and other rights to our non-employee directors and to consultants and employees of EPCO and its affiliates providing services to us.  Awards under the EPD 2008 LTIP may be granted in the form of unit options, restricted units, phantom units, UARs and DERs.  The EPD 2008 LTIP is administered by EPGP’s Audit, Conflicts and Governance (“ACG”) Committee.  The EPD 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 December 31, 2008, a total of 9,205,000 additional common units could be issued under the EPD 2008 LTIP.

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The EPD 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 EPD 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 EPD 2008 LTIP for the period indicated:

					Weighted-
			Weighted-		Average
			Average		Remaining
	Number of		Strike Price		Contractual
	Units		(dollars/unit)		Term (in years)
Outstanding at January 1, 2008		--
Granted (1)		795,000	$	30.93
Outstanding at December 31, 2008 (2)		795,000	$	30.93		5.00
(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%. (2)   The 795,000 units outstanding at December 31, 2008 will become exercisable in 2013.

Phantom unit awards.  The EPD 2008 LTIP 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.  The fair market value of each phantom unit award is equal to the market closing price of Enterprise Products Partners’ common units on the redemption date.  Each participant is required to redeem their phantom units as they vest, which typically is three years from the date the award is granted.  There were a total of 4,400 phantom units granted under the EPD 2008 LTIP during the fourth quarter of 2008 and outstanding at December 31, 2008.  These awards cliff vest in 2011.  At December 31, 2008, we had an accrued liability of $5 thousand for compensation related to these phantom unit awards.

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 GP Holdings, Duncan Energy Partners or Enterprise Products 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 EPE units (determined as of a future vesting date) over the grant date fair value.  If a director resigns prior to vesting, his UAR awards are forfeited.  These UARs are accounted for similar to liability awards under SFAS 123(R) since they will be settled with cash.

As of December 31, 2008, a total of 90,000 UARs had been 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.  The grant date fair value with respect to these UARs is based on an EPE unit price of $36.68.

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TEPPCO 1999 Plan

The TEPPCO 1999 Phantom Unit Retention Plan (“TEPPCO 1999 Plan”) provides for the issuance of phantom unit awards as incentives to key employees of EPCO working on behalf of TEPPCO.  These liability awards are settled for cash based on the fair market value of the vested portion of the phantom units at redemption dates in each award.  The fair market value of each phantom unit award is equal to the closing price of TEPPCO’s units on the NYSE on the redemption date.  Each participant is required to redeem their phantom units as they vest.  In addition, each participant is entitled to cash distributions equal to the product of the number of phantom unit awards granted under the TEPPCO 1999 Plan and the cash distribution per unit paid by TEPPCO on its units.  Grants under the 1999 Plan are subject to forfeiture if the participant’s employment with EPCO is terminated.

A total of 18,600 phantom units were outstanding under the TEPPCO 1999 Plan at December 31, 2008.  In April 2008, 13,000 phantom units vested and $0.4 million was paid out to a participant in the second quarter of 2008.  The awards outstanding at December 31, 2008 cliff vest as follows:  13,000 in April 2009 and 5,600 in January 2010.  At December 31, 2008, we had an accrued liability balance of $0.4 million related to the TEPPCO 1999 Plan.

TEPPCO 2000 LTIP

The TEPPCO 2000 Long-Term Incentive Plan (“TEPPCO 2000 LTIP”) provides key employees of EPCO working on behalf of TEPPCO incentives to achieve improvements in TEPPCO’s financial performance.  Generally, upon the close of a three-year performance period, each recipient will receive a cash payment equal to (i) the applicable “performance percentage” (as defined in the award agreement) multiplied by (ii) the number of phantom units granted under the TEPPCO 2000 LTIP multiplied by (iii) the average of the closing prices of TEPPCO units over the ten consecutive days immediately preceding the last day of the specified performance period.  In addition, during the performance period, each participant is entitled to cash distributions equal to the product of the number of phantom units granted under the TEPPCO 2000 LTIP and the cash distribution per unit paid by TEPPCO on its units.  Grants under the TEPPCO 2000 LTIP are accounted for as liability awards and are subject to forfeiture if the recipient’s employment with EPCO is terminated, with customary exceptions for death, disability or retirement.

A participant’s “performance percentage” is based upon an improvement in Economic Value Added for TEPPCO during a given three-year performance period over the Economic Value Added for the three-year period immediately preceding the performance period.  The term “Economic Value Added” means TEPPCO’s average annual EBITDA for the performance period minus the product of TEPPCO’s average asset base and its cost of capital for the performance period.  In this context, EBITDA means TEPPCO’s earnings before net interest expense, other income, depreciation and amortization and TEPPCO’s proportional interest in the EBITDA of its joint ventures, except that the chief executive officer of TEPPCO may exclude gains or losses from extraordinary, unusual or non-recurring items. Average asset base means the quarterly average, during the performance period, of TEPPCO’s gross carrying value of property, plant and equipment, plus long-term inventory, and the gross carrying value of intangible assets and equity investments.  TEPPCO’s cost of capital is determined at the date each award was granted.

At December 31, 2008, a total of 11,300 phantom units were outstanding under the TEPPCO 2000 LTIP that cliff vested on December 31, 2008 and will be paid out to participants in the first quarter of 2009.  At December 31, 2008, we had an accrued liability balance of $0.2 million related to the TEPPCO 2000 LTIP.  After payout in the first quarter of 2009 on awards which vested on December 31, 2008, there will be no remaining phantom units outstanding under the TEPPCO 2000 LTIP.

TEPPCO 2005 Phantom Unit Plan

The TEPPCO 2005 Phantom Unit Plan (“TEPPCO 2005 Phantom Unit Plan”) provides key employees of EPCO working on behalf of TEPPCO incentives to achieve improvements in TEPPCO’s financial performance.  Generally, upon the close of a three-year performance period, the recipient will receive a cash payment equal to (i) the recipient’s vested percentage (as defined in the award agreement)

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multiplied by (ii) the number of phantom units granted under the TEPPCO 2005 Phantom Unit Plan multiplied by (iii) the average of the closing prices of TEPPCO units over the ten consecutive days immediately preceding the last day of the specified performance period.  In addition, during the performance period, each recipient is entitled to cash distributions equal to the product of the number of phantom units granted under the TEPPCO 2005 Phantom Unit Plan and the cash distribution per unit paid by TEPPCO on its units.  Grants under the TEPPCO 2005 Phantom Unit Plan are accounted for as liability awards and are subject to forfeiture if the recipient’s employment with EPCO is terminated, with customary exceptions for death, disability or retirement.

Generally, a participant’s vested percentage is based upon an improvement in TEPPCO’s EBITDA during a given three-year performance period over TEPPCO’s EBITDA for the three-year period preceding the performance period.  In this context, EBITDA means TEPPCO’s earnings before noncontrolling interest, net interest expense, other income, income taxes, depreciation and amortization and TEPPCO’s proportional interest in the EBITDA of its joint ventures, except that the chief executive officer of TEPPCO may exclude gains or losses from extraordinary, unusual or non-recurring items.

At December 31, 2008 a total of 36,600 phantom units were outstanding under the TEPPCO 2005 Phantom Unit Plan that cliff vested on December 31, 2008 and will be paid out to participants in the first quarter of 2009.  At December 31, 2008, we had an accrued liability balance of $0.6 million related to the TEPPCO 2005 Phantom Unit Plan.  After the payout in the first quarter of 2009 on awards which vested on December 31, 2008, there will be no remaining phantom units outstanding under the TEPPCO 2005 Phantom Unit Plan.

TEPPCO 2006 LTIP

The EPCO 2006 TPP Long-Term Incentive Plan (“TEPPCO 2006 LTIP”) provide for awards of TEPPCO units and other rights to its non-employee directors and to certain employees of EPCO working on behalf of TEPPCO.  Awards granted under the TEPPCO 2006 LTIP may be in the form of restricted units, phantom units, unit options, UARs and DERs.  The TEPPCO 2006 LTIP provides for the issuance of up to 5,000,000 units of TEPPCO in connection with these awards.  After giving effect to outstanding unit options and restricted units at December 31, 2008, and the forfeiture of restricted units through December 31, 2008, a total of 4,487,084 additional units of TEPPCO could be issued under the TEPPCO 2006 LTIP in the future.

Unit option awards.  The following table presents unit option activity under the TEPPCO 2006 LTIP for year ended December 31, 2008:

					Weighted-
			Weighted-		Average
			Average		Remaining
	Number of		Strike Price		Contractual
	Units		(dollars/unit)		Term (in years)
Outstanding at December 31, 2007		155,000	$	45.35
Granted (1)		200,000	$	35.86
Outstanding at December 31, 2008 (2)		355,000	$	40.00		4.57
(1)   The total grant date fair value of these unit options issued on May 19, 2008 was $0.3 million based on the following assumptions: (i) expected life of the option of 4.7 years; (ii) risk-free interest rate of 3.3%; (iii) expected distribution yield on TEPPCO units of 7.9%; (iv) estimated forfeiture rate of 17.0%; and (v) expected unit price volatility on TEPPCO’s units of 18.7%. (2)   No unit options were exercisable at December 31, 2008.

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Restricted unit awards. The following table presents restricted unit activity under the TEPPCO 2006 LTIP for the year ended December 31, 2008:

				Weighted-
				Average Grant
	Number of			Date Fair Value
	Units			per Unit (1)
Restricted units at December 31, 2007		62,400
Granted (2)		96,900		$	29.54
Vested		(1,000	)	$	40.61
Forfeited		(1,000	)	$	35.86
Restricted units at December 31, 2008		157,300
(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 unit awards issued during 2008 was $2.8 million based on grant date market prices of TEPPCO’s units ranging from $34.63 to $35.86 per unit and an estimated forfeiture rate of 17.0%.

The total fair value of restricted unit awards that vested during the year ended December 31, 2008 was $24 thousand.

UARs and phantom units.  At December 31, 2008, there were a total of 95,654 UARs outstanding that had been granted to non-employee directors of TEPPCO GP and 335,723 UARs outstanding that were granted to certain employees of EPCO who worked on behalf of TEPPCO.  These UAR awards are subject to five year cliff vesting.  If the non-employee director or employee resigns prior to vesting, their UAR awards are forfeited.  These UAR awards are accounted for similar to liability awards under SFAS 123(R) since they will be settled with cash.

As of December 31, 2008, there were a total of 1,647 phantom unit awards outstanding that had been granted to non-employee directors of TEPPCO GP.  Each phantom unit will be redeemed in cash the earlier of (i) April 2011 or (ii) when the director is no longer serving on the board of TEPPCO GP.  In addition, during the vesting period, each participant is entitled to cash distributions equal to the product of the number of phantom units outstanding for the participant and the cash distribution per unit paid by TEPPCO on its units.  Phantom units awarded to non-employee directors are accounted for similar to liability awards.

The TEPPCO 2006 LTIP provides for the award of DERs in tandem with its phantom unit and UAR awards.  With respect to DERs granted in connection with phantom units, the participant is entitled to cash distributions equal to the product of the number of phantom units outstanding for the participant and the cash distribution rate paid by TEPPCO to its unitholders. With respect to DERs granted in connection with UARs, the participant is entitled to the product of the number of UARs outstanding for the participant and the difference between the current declared cash distribution rate paid by TEPPCO and the declared cash distribution rate paid by TEPPCO at the time the UAR was granted.  Since phantom units and UARs do not represent issued securities, the cash payments with respect to DERs are expensed by TEPPCO as paid.

Note 5.  Employee Benefit Plans

Dixie

Dixie employs the personnel that operate its pipeline system and certain of these employees are eligible to participate in a defined contribution plan and pension and postretirement benefit plans.  Due to the immaterial nature of Dixie’s employee benefit plans to our consolidated financial position, our discussion is limited to the following:

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Defined Contribution Plan.  Dixie contributed $0.3 million to its company-sponsored defined contribution plan for the year ended December 31, 2008.

Pension and Postretirement Benefit Plans.  Dixie’s pension plan is a noncontributory defined benefit plan that provides for the payment of benefits to retirees based on their age at retirement, years of service and average compensation.  Dixie’s postretirement benefit plan also provides medical and life insurance to retired employees.  The medical plan is contributory and the life insurance plan is noncontributory.  Dixie employees hired after July 1, 2004 are not eligible for pension and other benefit plans after retirement.

The following table presents Dixie’s benefit obligations, fair value of plan assets and funded status at December 31, 2008:

	Pension			Postretirement
	Plan			Plan
Projected benefit obligation	$	7.7		$	5.0
Accumulated benefit obligation		5.7			--
Fair value of plan assets		4.0			--
Funded status		(3.7	)		(5.0	)

Projected benefit obligations and net periodic benefit costs are based on actuarial estimates and assumptions.  The weighted-average actuarial assumptions used in determining the projected benefit obligation at December 31, 2008 were as follows:  discount rate of 6.4%; rate of compensation increase of 4.0% for both the pension and postretirement plans; and a medical trend rate of 8.5% for 2009 grading to an ultimate trend of 5.0% for 2015 and later years.

Future benefits expected to be paid from Dixie’s pension and postretirement plans are as follows for the periods indicated:

	Pension		Postretirement
	Plan		Plan
2009	$	0.3	$	0.3
2010		0.3		0.4
2011		0.5		0.4
2012		0.4		0.4
2013		0.8		0.4
2014 through 2017		4.2		2.1
Total	$	6.5	$	4.0

Included in accumulated other comprehensive loss on the Supplemental Consolidated Balance Sheet at December 31, 2008 are the following amounts that have not been recognized in net periodic pension costs:

Unrecognized transition obligation	$	0.9
Net of tax		0.5
Unrecognized prior service cost credit		(1.0	)
Net of tax		(0.6	)
Unrecognized net actuarial loss		1.3
Net of tax		0.8

Note 6.  Derivative Instruments, Hedging Activities and Fair Value Measurements

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

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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 obligations and (iii) cash flows resulting from changes in applicable interest rates, commodity prices or exchange rates. See Note 12 for information regarding our consolidated debt obligations.

We routinely review our outstanding derivative instruments in light of current market conditions.  If market conditions warrant, some derivative 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 derivative instrument to reestablish the hedge to which the closed instrument relates.

The following table provides additional information regarding derivative assets and derivative liabilities included in our Supplemental Consolidated Balance Sheet at December 31, 2008:

Current assets:
Derivative assets:
Interest rate risk hedging portfolio	$	7.8
Commodity risk hedging portfolio		201.5
Foreign currency risk hedging portfolio		9.3
Total derivative assets – current	$	218.6
Other assets:
Interest rate risk hedging portfolio	$	38.9
Total derivative assets – long-term	$	38.9
Current liabilities:
Derivative liabilities:
Interest rate risk hedging portfolio	$	5.9
Commodity risk hedging portfolio		296.9
Foreign currency risk hedging portfolio		0.1
Total derivative liabilities – current	$	302.9
Other liabilities:
Interest rate risk hedging portfolio	$	3.9
Commodity risk hedging portfolio		0.2
Total derivative liabilities– long-term	$	4.1

The following information summarizes the principal elements of our interest rate risk, commodity risk and foreign currency risk hedging portfolios. For amounts recorded on our supplemental balance sheet related to our consolidated hedging activities, please refer to the preceding table.

Interest Rate Risk Hedging Portfolio

Our interest rate exposure results from variable and fixed rate borrowings under various debt agreements. The following information summarizes significant components of our interest rate risk hedging portfolio:

Fair value hedges – interest rate swaps

We manage a portion of our interest rate exposure 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. At December 31, 2008, we had four interest rate swap agreements outstanding having an aggregate notional value of $400.0 million that were accounted for as fair value hedges.  The aggregate fair value of these interest rate swaps at December 31, 2008, was $46.7 million (an asset), with an offsetting increase in the fair value of the underlying debt.

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The following table summarizes our interest rate swaps outstanding at December 31, 2008.

	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 5.015%	$100.0 million
Senior Notes G, 5.60% fixed rate, due Oct. 2014	3	4th Qtr. 2004 to Oct. 2014	Oct. 2014	5.60% to 5.297%	$300.0 million
(1)   The variable rate indicated is the all-in variable rate for the current settlement period.

We have designated these interest rate swaps as fair value hedges under SFAS 133 since they mitigate changes in the fair value of the underlying fixed rate debt.  As effective fair value hedges, an increase in the fair value of these interest rate swaps is equally offset by an increase in the fair value of the underlying hedged debt.

Cash flow hedges – Duncan Energy Partners’ interest rate swaps

At December 31, 2008, Duncan Energy Partners had interest rate swap agreements outstanding having an aggregate notional value of $175.0 million.  These swaps were accounted for as cash flow hedges.  The purpose of these derivative instruments is to reduce the sensitivity of Duncan Energy Partners’ earnings to the variable interest rates charged under its revolving credit facility.  The aggregate fair value of these interest rate swaps at December 31, 2008 was a liability of $9.8 million.  The following table summarizes Duncan Energy Partners’ interest rate swaps outstanding at December 31, 2008.

		Number	Period Covered	Termination	Variable to	Notional
Hedged Variable Rate Debt		of Swaps	by Swap	Date of Swap	Fixed Rate (1)	Value
DEP I Revolving Credit Facility, due Feb. 2011		3	Sep. 2007 to Sep. 2010	Sep. 2010	1.47%  to 4.62%	$175.0 million
	(1)   Amounts receivable from or payable to the swap counterparties are settled every three months (the “settlement period”).

Commodity Risk Hedging Portfolio

Our commodity risk hedging portfolio was impacted by a significant decline in natural gas and crude oil prices during the second half of 2008.   As a result of the global recession, commodity prices have continued to be volatile during the first quarter of 2009.  We may experience additional losses related to our commodity risk hedging portfolio in 2009.

The prices of natural gas, NGLs, crude oil 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 derivative 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 and crude oil 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, crude oil 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 its inventory positions.  The commodity derivative instruments we utilize are settled in cash.

We have segregated our commodity derivative instruments portfolio between those derivative instruments utilized in connection with our natural gas marketing activities, our crude oil marketing activities and our NGL and petrochemical operations.

A significant number of the derivative instruments in this portfolio hedge the purchase of physical natural gas.  If natural gas prices fall below the price stipulated in such derivative 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 December 31, 2008 was $203.8 million in order to meet commodity exchange deposit requirements and the negative change in the fair value of our natural gas hedge positions.

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Natural gas marketing activities

At December 31, 2008, the aggregate fair value of those derivative instruments utilized in connection with our natural gas marketing activities was an asset of $6.5 million.  Almost all of the derivative instruments within this portion of the commodity derivative instruments portfolio are accounted for using mark-to-market accounting, with a small number accounted for as cash flow hedges.  We did not have any cash flow hedges related to our natural gas marketing activities at December 31, 2008.

Crude oil marketing activities

The fair value of the open positions at December 31, 2008 was an asset of $3 thousand.  At December 31, 2008, we had no commodity derivative instruments that were accounted for as cash flow hedges.  We have some commodity derivative instruments that do not qualify for hedge accounting.

NGL and petrochemical operations

At December 31, 2008, the aggregate fair value of those derivative instruments utilized in connection with our NGL and petrochemical operations were liabilities of $102.1 million.  Almost all of the derivative instruments within this portion of the commodity derivative instruments portfolio are accounted for as cash flow hedges, with a small number accounted for using mark-to-market accounting.

We have employed a program to economically hedge a portion of our earnings from natural gas processing in the Rocky Mountain region.  This program consists of (i) the forward sale of a portion of our expected equity NGL production volumes at fixed prices through 2009 and (ii) the purchase, using commodity derivative 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 derivative instruments.  At December 31, 2008, this hedging program had hedged future expected gross margins (before plant operating expenses) of $483.9 million on 22.5 million barrels of forecasted NGL forward sales transactions extending through 2009.

Our NGL forward sales contracts are not accounted for as derivative instruments under SFAS 133 since they meet normal purchase and sale exception criteria; therefore, changes in the aggregate economic value of these sales contracts are not reflected in net income and other comprehensive income until the volumes are delivered to customers.  On the other hand, the commodity derivative 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.  Once the forecasted NGL forward sales transactions occur, any realized gains and losses on the cash flow hedges would be reclassified into net income in that period.

Prior to actual settlement, if the market price of natural gas is less than the price stipulated in a commodity derivative instrument, we recognize an unrealized loss in other comprehensive loss for the excess of the natural gas price stated in the 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 pay for PTR, which would then be based on the lower market price.  Conversely, if the market price of natural gas is greater than the price stipulated in such hedges, we recognize an unrealized gain in other comprehensive income for the excess of the market price over the natural gas price stated in the PTR hedge.   If realized, the gains on the derivative instrument would serve to reduce the actual cost paid for PTR, which would then be based on the higher market price.  The net effect of these hedging relationships is that our total cost of natural gas used for PTR approximates the amount it originally hedged under this program.

Foreign Currency Hedging Portfolio

We are exposed to foreign currency exchange rate risk primarily through a Canadian NGL marketing subsidiary.  As a result, we could be adversely affected by fluctuations in the foreign currency

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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.

In addition, we are exposed to foreign currency exchange rate risk through our Japanese Yen Term Loan Agreement (“Yen Term Loan”) that EPO entered into in November 2008.  As a result, we could be adversely affected by fluctuations in the foreign currency exchange rate between the U.S. dollar and the Japanese yen.  We hedged this risk by entering into a foreign exchange purchase contract to fix the exchange rate.  This purchase contract was designated as a cash flow hedge.  At December 31, 2008, the fair value of this contract was $9.3 million.  This contract will be settled in March 2009 upon repayment of the Yen Term Loan.

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 adopted 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 derivative 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.

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§   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 derivative instruments that are tailored to meet a customer’s specific needs.  At December 31, 2008, our Level 3 financial assets consisted of ethane based contracts with a range of two to twelve months in term.  This classification is primarily due to our reliance on broker quotes for this product due to the forward ethane markets being less than highly active.

The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities measured on a recurring basis at December 31, 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.

	Level 1		Level 2		Level 3		Total
Financial assets:
Commodity derivative instruments	$	4.0	$	164.7	$	32.8	$	201.5
Foreign currency derivative instruments		--		9.3		--		9.3
Interest rate derivative instruments		--		46.7		--		46.7
Total	$	4.0	$	220.7	$	32.8	$	257.5
Financial liabilities:
Commodity derivative l instruments	$	7.1	$	289.6	$	0.4	$	297.1
Foreign currency derivative instruments		--		0.1		--		0.1
Interest rate derivative instruments		--		9.8		--		9.8
Total	$	7.1	$	299.5	$	0.4	$	307.0
Net financial assets, Level 3					$	32.4

Fair values associated with our interest rate, commodity and foreign currency derivative 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 during the year ended December 31, 2008:

Balance, January 1, 2008	$	(5.0	)
Total gains (losses) included in:
Net income		(34.6	)
Other comprehensive loss		37.2
Purchases, issuances, settlements		34.8
Balance, December 31, 2008	$	32.4

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Fair Value Information

Cash and cash equivalents, accounts receivable, accounts payable and accrued expenses are carried at amounts which reasonably approximate their fair values due to their short-term nature.  The estimated fair values of our fixed rate debt are based on quoted market prices for such debt or debt of similar terms and maturities.  The carrying amounts of our variable rate debt obligations reasonably approximate their fair values due to their variable interest rates.  The fair values associated with our interest rate and commodity hedging portfolios were developed using available market information and appropriate valuation techniques.  The following table presents the estimated fair values of our derivative instruments at December 31, 2008:

	Carrying		Fair
Derivative Instruments	Value		Value
Financial assets:
Cash and cash equivalents, including restricted cash	$	265.6	$	265.6
Accounts receivable		2,063.8		2,063.8
Commodity derivative instruments (1)		201.5		201.5
Foreign currency hedging derivative instruments (2)		9.3		9.3
Interest rate hedging derivative instruments (3)		46.7		46.7
Financial liabilities:
Accounts payable and accrued expenses		2,506.0		2,506.0
Fixed-rate debt (principal amount) (4)		9,704.3		8,192.2
Variable-rate debt		1,858.5		1,858.5
Commodity derivative instruments (1)		297.1		297.1
Foreign currency hedging derivative instruments (2)		0.1		0.1
Interest rate hedging derivative instruments (3)		9.8		9.8
(1)   Represent commodity derivative instrument transactions that either have not settled or have settled and not been invoiced. Settled and invoiced transactions are reflected in either accounts receivable or accounts payable depending on the outcome of the transaction. (2)   Relates to the hedging of our exposure to fluctuations in the Canadian dollar and Japanese yen. (3)   Represent interest rate hedging derivative instrument transactions that have not settled. Settled transactions are reflected in either accounts receivable or accounts payable depending on the outcome of the transaction. (4)   Due to the distress in the capital markets following the collapse of several major financial entities and uncertainty in the credit markets during 2008, corporate debt securities were trading at significant discounts.

Note 7.  Inventories

Our inventory amounts were as follows at December 31, 2008:

Working inventory (1)	$	211.9
Forward sales inventory (2)		193.1
Total inventory	$	405.0
(1)   Working inventory is comprised of inventories of natural gas, crude oil, refined products, lubrication oils, NGLs and certain petrochemical products that are either available-for-sale or used in the provision for services. (2)   Forward sales inventory consists of identified natural gas, crude oil and NGL 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.

In those instances where we take ownership of inventory volumes through percent-of-liquids contracts and similar arrangements (as opposed to actually purchasing volumes for cash from third parties), these volumes are valued at market-related prices during the month in which they are acquired.  We

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capitalize as a component of inventory those ancillary costs (e.g. freight-in and other handling and processing charges) incurred in connection with volumes obtained through such contracts.

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

Note 8.  Property, Plant and Equipment

Our property, plant and equipment values and accumulated depreciation balances were as follows at December 31, 2008:

	Estimated
	Useful Life
	In Years
Plants and pipelines (1)	3-40 (6)	$	15,266.7
Underground and other storage facilities (2)	5-40 (7)		1,203.9
Platforms and facilities (3)	20-31		634.8
Transportation equipment (4)	3-10		50.9
Marine vessels (5)	20-30		453.0
Land			254.5
Construction in progress			2,015.4
Total			19,879.2
Less accumulated depreciation			3,146.4
Property, plant and equipment, net		$	16,732.8
(1)   Plants and pipelines include processing plants; NGL, petrochemical, crude 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; above ground 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)   See Note 10 for additional information regarding the acquisition of marine services businesses in February 2008. (6)   In general, the estimated useful lives of major components of this category are as follows: processing plants, 20-35 years; pipelines and related equipment, 5-40 years; terminal facilities, 10-35 years; delivery facilities, 20-40 years; office furniture and equipment, 3-20 years; buildings, 20-40 years; and laboratory and shop equipment, 5-35 years. (7)   In general, the estimated useful lives of major components of this category are as follows: underground storage facilities, 5-35 years; storage tanks, 10-40 years; and water wells, 5-35 years.

We recorded $90.7 million in capitalized interest during the year ended December 31, 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 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 as of January 1, 2008.

In August 2008, we, together with Oiltanking Holding Americas, Inc. (“Oiltanking”), announced the formation of the Texas Offshore Port System (or “TOPS”), which was a joint venture to design, construct, operate and own a Texas offshore crude oil port and related pipeline and storage system that would facilitate delivery of waterborne crude oil cargoes to refining centers located along the upper Texas Gulf Coast.   We owned a two-thirds interest in TOPS, with Oiltanking owning the remaining one-third interest.  Construction in progress amounts at December 31, 2008 included $90.6 million attributable to TOPS, which is a consolidated subsidiary of ours.   See Note 19 for subsequent event information regarding our dissociation from TOPS in April 2009.

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Asset retirement obligations

We have recorded AROs related to legal requirements to perform retirement activities as specified in contractual arrangements and/or governmental regulations.  In general, our AROs primarily result from (i) right-of-way agreements associated with our pipeline operations, (ii) leases of plant sites and (iii) regulatory requirements triggered by the abandonment or retirement of certain underground storage assets and offshore facilities.  In addition, our AROs may result from the renovation or demolition of certain assets containing hazardous substances such as asbestos.

The following table presents information regarding our AROs since December 31, 2007:

ARO liability balance, December 31, 2007	$	42.2
Liabilities incurred		1.1
Liabilities settled		(8.2	)
Revisions in estimated cash flows		4.7
Accretion expense		2.4
ARO liability balance, December 31, 2008	$	42.2

Property, plant and equipment at December 31, 2008 includes $11.7 of asset retirement costs capitalized as an increase in the associated long-lived asset.

Certain of our unconsolidated affiliates have AROs recorded at December 31, 2008 relating to contractual agreements and regulatory requirements.  These amounts are immaterial to our Supplemental Consolidated Balance Sheet.

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Note 9.  Investments in Unconsolidated Affiliates

We own interests in a number of related businesses that are accounted for using the equity method of accounting.  Our investments in unconsolidated affiliates are grouped according to the business segment to which they relate.  See Note 14 for a general discussion of our business segments.  The following table shows our investments in unconsolidated affiliates at December 31, 2008:

	Ownership
	Percentage
NGL Pipelines & Services:
Venice Energy Service Company, L.L.C. (“VESCO”)	13.1%	$	37.7
K/D/S Promix, L.L.C. (“Promix”)	50%		46.4
Baton Rouge Fractionators LLC (“BRF”)	32.2%		24.2
Skelly-Belvieu Pipeline Company, L.L.C. (“Skelly-Belvieu”) (1)	49%		36.0
Onshore Natural Gas Pipelines & Services:
Evangeline (2)	49.5%		4.5
White River Hub, LLC (“White River Hub”) (3)	50%		21.4
Onshore Crude Oil Pipelines & Services
Seaway Crude Pipeline Company (“Seaway”)	50%		186.2
Offshore Pipelines & Services:
Poseidon Oil Pipeline, L.L.C. (“Poseidon”)	36%		60.2
Cameron Highway Oil Pipeline Company (“Cameron Highway”)	50%		250.9
Deepwater Gateway, L.L.C. (“Deepwater Gateway”)	50%		104.8
Neptune	25.7%		52.7
Nemo	33.9%		0.4
Petrochemical & Refined Products Services:
Baton Rouge Propylene Concentrator, LLC (“BRPC”)	30%		12.6
La Porte (4)	50%		3.9
Centennial Pipeline LLC (“Centennial”)	50%		69.7
Other	25%		0.3
Total		$	911.9
(1)   In December 2008, we acquired a 49% ownership interest in Skelly-Belvieu. (2)   Refers to our ownership interests in Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp., collectively. (3)   In February 2008, we acquired a 50% ownership interest in White River Hub. (4)   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 an ownership interest in a company exceeds the underlying book value of the capital accounts we acquire.  Such excess cost amounts are included within the carrying values of our investments in and advances to unconsolidated affiliates.  At December 31, 2008, our investments in Promix, Skelly-Belvieu, La Porte, Neptune, Poseidon, Cameron Highway, Seaway and Centennial included excess cost amounts totaling $75.6 million, all of which were attributable to the fair value of the underlying tangible assets of these entities exceeding their book carrying values at the time of our acquisition of interests in these entities.

NGL Pipelines & Services

At December 31, 2008, our NGL Pipelines & Services segment included the following unconsolidated affiliates accounted for using the equity method:

VESCO. We own a 13.1% interest in VESCO, which owns a natural gas processing facility and related assets located in south Louisiana.

Promix.  We own a 50% interest in Promix, which owns an NGL fractionation facility and related storage and pipeline assets located in south Louisiana.

BRF.  We own an approximate 32.2% interest in BRF, which owns an NGL fractionation facility located in south Louisiana.

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Skelly-Belvieu.  In December 2008, we acquired a 49% interest in Skelly-Belvieu for $36.0 million.  Skelly-Belvieu owns a 570-mile pipeline that transports mixed NGLs to markets in southeast Texas.

The combined balance sheet information at December 31, 2008 of this segment’s current unconsolidated affiliates is summarized below.

Current assets	$	64.1
Property, plant and equipment, net		368.1
Other assets		2.0
Total assets	$	434.2
Current liabilities	$	50.2
Other liabilities		24.3
Combined equity		359.7
Total liabilities and combined equity	$	434.2

Onshore Natural Gas Pipelines & Services

At December 31, 2008, our Onshore Natural Gas Pipelines & Servicessegment included the following unconsolidated affiliates accounted for using the equity method:

Evangeline.  We own an approximate 49.5% aggregate interest in Evangeline, which owns a natural gas pipeline located in south Louisiana.  A subsidiary of Acadian Gas, LLC owns the Evangeline interests, which were contributed to Duncan Energy Partners in February 2007 in connection with its initial public offering (see Note 15).

Coyote. We owned a 50% interest in Coyote during 2005, which owns a natural gas treating facility located in the San Juan Basin of southwestern Colorado.

White River Hub. We own a 50% interest in White River Hub, which owns a natural gas hub located in northwest Colorado.  The hub was completed in December 2008.

The combined balance sheet information at December 31, 2008 of this segment’s current unconsolidated affiliates is summarized below.

Current assets	$	43.6
Property, plant and equipment, net		60.2
Other assets		17.5
Total assets	$	121.3
Current liabilities	$	33.9
Other liabilities		21.5
Combined equity		65.9
Total liabilities and combined equity	$	121.3

Onshore Crude Oil Pipelines & Services

At December 31, 2008, our Onshore Crude Oil Pipelines & Servicessegment included the following unconsolidated affiliate accounted for using the equity method:

Seaway.  We own a 50% interest in Seaway, which owns a pipeline that transports crude oil from a marine terminal located in Freeport, Texas, to Cushing, Oklahoma, and from a marine terminal located in Texas City, Texas, to refineries in the Texas City and Houston, Texas areas.

The balance sheet information at December 31, 2008 this segment’s current unconsolidated affiliate is summarized below.

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Current assets	$	31.3
Property, plant and equipment, net		248.0
Total assets	$	279.3
Current liabilities	$	6.1
Equity		273.2
Total liabilities and equity	$	279.3

Offshore Pipelines & Services

At December 31, 2008, our Offshore Pipelines & Services segment included the following unconsolidated affiliates accounted for using the equity method:

Poseidon.  We own a 36% interest in Poseidon, which owns a crude oil pipeline that gathers production from the outer continental shelf and deepwater areas of the Gulf of Mexico for delivery to onshore locations in south Louisiana.

Cameron Highway.  We own a 50% interest in Cameron Highway, which owns a crude oil pipeline that gathers production from deepwater areas of the Gulf of Mexico, primarily the South Green Canyon area, for delivery to refineries and terminals in southeast Texas.

Deepwater Gateway.  We own a 50% interest in Deepwater Gateway, which owns the Marco Polo platform located in the Gulf of Mexico.  The Marco Polo platform processes crude oil and natural gas production from the Marco Polo, K2, K2 North and Genghis Khan fields located in the South Green Canyon area of the Gulf of Mexico.

Neptune. We own a 25.7% interest in Neptune, which owns Manta Ray Offshore Gathering System (“Manta Ray”) and Nautilus Pipeline System (“Nautilus”), which are natural gas pipelines located in the Gulf of Mexico.

Nemo. We own a 33.9% interest in Nemo, which owns the Nemo Gathering System, which is a natural gas pipeline located in the Gulf of Mexico.

The combined balance sheet information at December 31, 2008 of this segment’s current unconsolidated affiliates is summarized below.

Current assets	$	85.3
Property, plant and equipment, net		1,093.9
Other assets		3.6
Total assets	$	1,182.8
Current liabilities	$	53.3
Other liabilities		116.7
Combined equity		1,012.8
Total liabilities and combined equity	$	1,182.8

Petrochemical & Refined Products Services

At December 31, 2008, our Petrochemical & Refined Products Services segment included the following unconsolidated affiliates accounted for using the equity method:

BRPC.  We own a 30% interest in BRPC, which owns a propylene fractionation facility located in south Louisiana.

La Porte. We own an aggregate 50% interest in La Porte, which owns a propylene pipeline extending from Mont Belvieu, Texas to La Porte, Texas.

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Centennial.  We own a 50% interest in Centennial, which owns an interstate refined petroleum products pipeline extending from the upper Texas Gulf Coast to central Illinois.  Prior to April 2002, our refined products pipeline system was bottlenecked between Beaumont, Texas and El Dorado, Arkansas, which limited our ability to transport refined products and NGLs during peak periods.  When the Centennial pipeline commenced operations in 2002, it effectively looped our refined products pipeline system, thus providing incremental transportation capacity into Mid-continent markets.

 The combined balance sheet information at December 31, 2009 of this segment’s current unconsolidated affiliates is summarized below.

Current assets	$	16.5
Property, plant and equipment, net		283.1
Total assets	$	299.6
Current liabilities	$	22.4
Other liabilities		120.3
Combined equity		156.9
Total liabilities and combined equity	$	299.6

Note 10. Business Combinations

Our expenditures for business combinations during the year ended December 31, 2008 were $553.4 million and primarily reflect the acquisitions described below.

Great Divide Gathering System Acquisition.  In December 2008, one of our subsidiaries, Enterprise Gas Processing, LLC, purchased a 100% membership interest in Great Divide Gathering, LLC (“Great Divide”) for cash consideration of $125.2 million.  Great Divide was wholly owned by EnCana Oil & Gas (“EnCana”).

The assets of Great Divide consist of a 31-mile natural gas gathering system, the Great Divide Gathering System, located in the Piceance Basin of northwestern Colorado.  The Great Divide Gathering System extends from the southern portion of the Piceance Basin, including production from EnCana’s Mamm Creek field, to a pipeline interconnection with our Piceance Basin Gathering System.  Volumes of natural gas originating on the Great Divide Gathering System are transported through our Piceance Creek Gathering System to our 1.4 Bcf/d Meeker natural gas treating and processing complex.  A significant portion of these volumes are produced by EnCana, one of the largest natural gas producers in the region, and are dedicated the Great Divide and Piceance Creek Gathering Systems for the life of the associated lease holdings.

Tri-States and Belle Rose Acquisitions.  In October 2008, we acquired additional 16.7% membership interests in both Tri-States NGL Pipeline, L.L.C. (“Tri-States”) and Belle Rose NGL Pipeline, L.L.C. (“Belle Rose”) for total cash consideration of $19.9 million.  As a result of this transaction, our ownership interest in Tri-States increased to 83.3%.  We now own 100% of the membership interests in Belle Rose. 

Tri-States owns a 194-mile NGL pipeline located along the Mississippi, Alabama and Louisiana Gulf Coast.  Belle Rose owns a 48-mile NGL pipeline located in Louisiana.  These systems, in conjunction with the Wilprise pipeline, transport mixed NGLs to the BRF, Norco and Promix NGL fractionators located in south Louisiana.

Acquisition of Remaining Interest in Dixie.  In August 2008, we acquired the remaining 25.8% ownership interests in Dixie for cash consideration of $57.1 million.  As a result of this transaction, we own 100% of Dixie, which owns a 1,371-mile pipeline system that delivers NGLs (primarily propane and other chemical feedstock) to customers along the U.S. Gulf Coast and southeastern United States.

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Cenac and Horizon Acquisitions.  In February 2008, TEPPCO entered the marine transportation business for refined products, crude oil and condensate through the purchase of assets from Cenac Towing Co., Inc., Cenac Offshore, L.L.C., and Mr. Arlen B. Cenac, Jr. (collectively “Cenac”). The aggregate value of total consideration TEPPCO paid or issued to complete this business combination was $444.7 million, which consisted of $258.1 million in cash and approximately 4.9 million newly issued TEPPCO units.  Additionally, TEPPCO assumed approximately $63.2 million of Cenac’s debt in the transaction.  TEPPCO acquired 42 tow boats, 89 tank barges and the economic benefit of certain related commercial agreements.  This business serves refineries and storage terminals along the Mississippi, Illinois and Ohio rivers and the Intracoastal Waterway between Texas and Florida.  These assets also gather crude oil from production facilities and platforms along the U.S. Gulf Coast.  TEPPCO used its Short-Term Credit Facility to finance the cash portion of the acquisition price and to repay the $63.2 million of debt assumed in this transaction.

Also in February 2008, TEPPCO purchased related marine assets from Horizon Maritime, L.L.C. (“Horizon”), a privately held Houston-based company and an affiliate of Mr. Cenac, for $80.8 million in cash. In this transaction, TEPPCO acquired 7 tow boats, 17 tank barges, rights to 2 tow boats under construction and the economic benefit of certain related commercial agreements.  In April 2008, TEPPCO paid an additional $3.0 million to Horizon pursuant to the purchase agreement upon delivery of one of the tow boats under construction, and in June 2008, TEPPCO paid an additional $3.8 million upon delivery of the second tow boat.  These vessels transport asphalt, heavy fuel oil and other heated oil products to storage facilities and refineries along the Mississippi, Illinois and Ohio Rivers and the Intracoastal Waterway.  TEPPCO used its Short-Term Credit Facility to finance this acquisition.

Purchase Price Allocations.  We accounted for our business combinations completed during 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.

	Cenac			Horizon		Great
	Acquisition			Acquisition		Divide			Dixie			Other (1)			Total
Assets acquired in business combination:
Current assets	$	--		$	--	$	--		$	4.0		$	2.6		$	6.6
Property, plant and equipment, net		362.9			72.2		70.6			33.7			10.1			549.5
Intangible assets		63.5			6.5		9.8			--			12.7			92.5
Other assets		--			--		--			0.4			--			0.4
Total assets acquired		426.4			78.7		80.4			38.1			25.4			649.0
Liabilities assumed in business combination:
Current liabilities		--			--		--			(2.6	)		(0.6	)		(3.2	)
Long-term debt		--			--		--			(2.6	)		--			(2.6	)
Other long-term liabilities		(63.2	)		--		(0.1	)		(46.2	)		--			(109.5	)
Total liabilities assumed		(63.2	)		--		(0.1	)		(51.4	)		(0.6	)		(115.3	)
Total assets acquired plus liabilities assumed		363.2			78.7		80.3			(13.3	)		24.8			533.7
Fair value of 4,854,899 TEPPCO units		186.6			--		--			--			--			186.6
Total cash used for business combinations		258.1			87.6		125.2			57.1			25.4			553.4
Goodwill	$	81.5		$	8.9	$	44.9		$	70.4		$	0.6		$	206.3
(1)   Primarily represents (i) non-cash reclassification adjustments to December 2007 preliminary fair value estimates for assets acquired in the South Monco natural gas pipeline acquisition, (ii) the purchase of lubrication and other fuel assets in August 2008 and (iii) the purchase of additional interests in Tri-States and Belle Rose in October 2008.

As a result of our 100% ownership interest in Dixie, we used push-down accounting to record this business combination.  In doing so, a temporary tax difference was created between the assets and liabilities of Dixie for financial reporting and tax purposes.  Dixie recorded a deferred income tax liability of $45.1 million attributable to the temporary tax difference.

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Note 11.  Intangible Assets and Goodwill

Identifiable Intangible Assets

The following table summarizes our intangible assets at December 31, 2008:

	Gross		Accum.			Carrying
	Value		Amort.			Value
NGL Pipelines & Services: (1)
Customer relationship intangibles	$	237.4	$	(68.7	)	$	168.7
Contract-based intangibles		320.3		(137.6	)		182.7
Segment total		557.7		(206.3	)		351.4
Onshore Natural Gas Pipelines & Services:
Customer relationship intangibles (2)		372.0		(103.2	)		268.8
Gas gathering agreements		464.0		(213.1	)		250.9
Other contract-based intangibles		101.3		(36.6	)		64.7
Segment total		937.3		(352.9	)		584.4
Onshore Crude Oil Pipelines & Services:
Contract-based intangibles		10.0		(3.1	)		6.9
Segment total		10.0		(3.1	)		6.9
Offshore Pipelines & Services:
Customer relationship intangibles		205.8		(90.7	)		115.1
Contract-based intangibles		1.2		(0.1	)		1.1
Segment total		207.0		(90.8	)		116.2
Petrochemical & Refined Products Services:
Customer relationship intangibles		104.9		(13.8	)		91.1
Contract-based intangibles		41.1		(8.2	)		32.9
Segment total		146.0		(22.0	)		124.0
Total all segments	$	1,858.0	$	(675.1	)	$	1,182.9
(1)   In 2008, we acquired $6.0 million of certain permits related to our Mont Belvieu complex and had $12.7 million of purchase price allocation adjustments related to San Felipe customer relationships from the December 2007 South Monco acquisition.     (2)   In 2008, we acquired $9.8 million of customer relationships due to the Great Divide business combination.

In general, our intangible assets fall within two categories – contract-based intangible assets and customer relationships. The values assigned to such intangible assets are amortized to earnings using either (i) a straight-line approach or (ii) other methods that closely resemble the pattern in which the economic benefits of associated resource bases are estimated to be consumed or otherwise used, as appropriate.

Customer relationship intangible assets.  Customer relationship intangible assets represent the estimated economic value assigned to certain relationships acquired in connection with business combinations and asset purchases whereby (i) we acquired information about or access to customers and now have regular contact with them and (ii) the customers now have the ability to make direct contact with us. Customer relationships may arise from contractual arrangements (such as supplier contracts and service contracts) and through means other than contracts, such as through regular contact by sales or service representatives.

At December 31, 2008, the carrying value of our customer relationship intangible assets was $643.7 million.  The following information summarizes the significant components of this category of intangible assets:

§   San Juan Gathering System customer relationships – We acquired these customer relationships in connection with the GulfTerra Merger, which was completed on September 30, 2004.  At December 31, 2008, the carrying value of this group of intangible assets was $238.8 million.  These intangible assets are being amortized to earnings over their estimated economic life of 35 years through 2039.  Amortization expense is recorded using a method that closely resembles the pattern in which the economic benefits of the underlying natural gas resource bases are expected to be consumed or otherwise used.

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§   Offshore Pipeline & Platform customer relationships – We acquired these customer relationships in connection with the GulfTerra Merger.  At December 31, 2008, the carrying value of this group of intangible assets was $115.2 million.  These intangible assets are being amortized to earnings over their estimated economic life of 33 years through 2037.  Amortization expense is recorded using a method that closely resembles the pattern in which the economic benefits of the underlying crude oil and natural gas resource bases are expected to be consumed or otherwise used.

§   Encinal natural gas processing customer relationship – We acquired this customer relationship in connection with our Encinal acquisition in 2006.  At December 31, 2008, the carrying value of this intangible asset was $99.1 million.  This intangible asset is being amortized to earnings over its estimated economic life of 20 years through 2026.  Amortization expense is recorded using a method that closely resembles the pattern in which the economic benefit of the underlying natural gas resource bases are expected to be consumed or otherwise used.

Contract-based intangible assets.  Contract-based intangible assets represent specific commercial rights we acquired in connection with business combinations or asset purchases.  At December 31, 2008, the carrying value of our contract-based intangible assets was $539.2 million.  The following information summarizes the significant components of this category of intangible assets:

§   Jonah natural gas gathering agreements – These intangible assets represent the value attributed to certain of Jonah’s natural gas gathering contracts that were originally acquired by TEPPCO in 2001.  At December 31, 2008, the carrying value of this group of intangible assets was $136.0 million.  These intangible assets are being amortized to earnings using a units-of-production method based on throughput volumes on the Jonah system.

§   Val Verde natural gas gathering agreements – These intangible assets represent the value attributed to certain natural gas gathering agreements associated with our Val Verde Gathering System that was originally acquired by TEPPCO in 2002.  At December 31, 2008, the carrying value of these intangible assets was $113.8 million.  These intangible assets are being amortized to earnings using a units-of-production method based on throughput volumes on the Val Verde Gathering System.

§   Shell Processing Agreement – This margin-band/keepwhole processing agreement grants us the right to process Shell Oil Company’s (or its assignee’s) current and future natural gas production of within the state and federal waters of the Gulf of Mexico.  We acquired the Shell Processing Agreement in connection with our 1999 purchase of certain of Shell’s midstream energy assets located along the U.S. Gulf Coast.  At December 31, 2008, the carrying value of this intangible asset was $116.9 million.  This intangible asset is being amortized to earnings on a straight-line basis over its estimated economic life of 20 years through 2019.

§   Mississippi natural gas storage contracts – These intangible assets represent the value assigned by us to certain natural gas storage contracts associated with our Petal and Hattiesburg, Mississippi storage facilities.   These facilities were acquired in connection with the GulfTerra Merger.  At December 31, 2008, the carrying value of these intangible assets was $64.0 million.  These intangible assets are being amortized to earnings on a straight-line basis over the remainder of their respective contract terms, which range from eight to 18 years (i.e. 2012 through 2022).

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Goodwill

Goodwill represents the excess of the purchase price of an acquired business over the amounts assigned to assets acquired and liabilities assumed in the transaction.  We do not amortize goodwill; however, we test goodwill for impairment annually, or more frequently if circumstances indicate that it is more likely than not that the fair value of goodwill is less than its carrying value.  The following table summarizes our goodwill amounts by business segment at December 31, 2008:

NGL Pipelines & Services
Acquisition of ownership interests in TEPPCO	$	72.2
GulfTerra Merger		23.8
Acquisition of Encinal		95.3
Acquisition of additional ownership interests in Dixie		80.3
Acquisition of Great Divide		44.9
Acquisition of Indian Springs natural gas processing business		13.2
Other		11.5
Onshore Natural Gas Pipelines & Services
GulfTerra Merger		279.9
Other		5.0
Onshore Crude Oil Pipeline & Services
Acquisition of ownership interests in TEPPCO		288.8
Acquisition of crude oil pipeline and services business		14.2
Offshore Pipelines & Services
GulfTerra Merger		82.1
Petrochemical & Refined Products Services
Acquisition of ownership interests in TEPPCO		842.3
Acquisition of Mont Belvieu propylene fractionation business		73.7
Acquisition of marine transportation businesses		90.4
Other		2.0
Total	$	2,019.6

Changes in goodwill amounts during 2008.  In 2008, our only significant changes to goodwill were the recording of $70.4 million in connection with our acquisition of the remaining third party interest in Dixie, $44.9 million in connection with the acquisition of Great Divide and $90.4 million in connection with our acquisitions of Cenac and Horizon.  The remaining ownership interests in Dixie were acquired from Amoco Pipeline Holding Company in August 2008.  Management attributes the goodwill to future earnings growth on the Dixie Pipeline.  Specifically, a 100% ownership interest in the Dixie Pipeline will increase our flexibility to pursue future opportunities.  Great Divide was acquired from EnCana in December 2008.  The Great Divide goodwill is attributable to management’s expectations of future economics benefits derived from incremental natural gas processing margins and other downstream activities.

The Dixie and Great Divide goodwill amounts are recorded as part of the NGL Pipelines & Services business segment due to management’s belief that such future benefits will accrue to businesses classified within this segment.  The marine services businesses goodwill amounts are recorded as part of the Petrochemical & Refined Products Services business segment due to management’s belief of potential future economic benefits we expect to realize as a result of acquiring these assets.  See Note 10 for additional information regarding our 2008 acquisitions that resulted in the recording of goodwill.

Goodwill attributable to the acquisition of ownership interests in TEPPCO.   As a result of our ownership of 100% of the limited and general partner interests of TEPPCO following the recently completed TEPPCO Merger, we applied push-down accounting to the $1.2 billion of goodwill recorded by affiliates of EPCO (which are under common control with us) when they acquired 100% of the membership interests of TEPPCO GP and 4.4 million TEPPCO limited partner units from a third party in February 2005.  The $1.2 billion in push down goodwill represents the excess of the purchase price paid by such affiliates to acquire ownership interests in TEPPCO in February 2005 over the respective fair value of assets acquired and liabilities assumed in the February 2005 transaction.  Management attributes the $1.2

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billion of goodwill to the future economic benefits we may realize from our ownership of TEPPCO, including anticipated commercial synergies and cost savings.

TEPPCO owns and operates an extensive network of assets that facilitate the movement, marketing, gathering and storage services of various commodities and energy-related products.  TEPPCO’s pipeline network is comprised of approximately 12,500 miles of pipelines that gather and transport refined petroleum products, crude oil, natural gas and NGLs, including one of the largest common carrier pipelines for refined products in the United States.  TEPPCO also owns a marine services business that transports refined petroleum products, crude oil, asphalt, condensate, heavy fuel oil and other heated oil products via tow boats and tank barges.  In addition, TEPPCO owns interests in the Seaway and Centennial pipeline systems.

Goodwill attributable to GulfTerra Merger.  Goodwill recorded in connection with the GulfTerra Merger can be attributed to our belief (at the time the merger was consummated) that the combined partnerships would benefit from the strategic location of each partnership’s assets and the industry relationships that each possessed.  In addition, we expected that various operating synergies could develop (such as reduced general and administrative costs and interest savings) that would result in improved financial results for the merged entity.  Based on miles of pipelines, GulfTerra was one of the largest natural gas gathering and transportation companies in the United States, serving producers in the central and western Gulf of Mexico and onshore in Texas and New Mexico.  These regions offer us significant growth potential through the acquisition and construction of additional pipelines, platforms, processing and storage facilities and other midstream energy infrastructure.

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

Other goodwill amounts.  The remainder of our goodwill amounts are associated with prior acquisitions, principally that of our crude oil pipeline and services business originally purchased by TEPPCO in 2001, our purchase of a propylene fractionation business in February 2002 and our acquisition of indirect ownership interests in the Indian Springs natural gas gathering and processing business in January 2005.

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Note 12.  Debt Obligations

Our consolidated debt obligations consisted of the following at December 31, 2008:

EPO senior debt obligations:
Multi-Year Revolving Credit Facility, variable rate, due November 2012	$	800.0
Pascagoula MBFC Loan, 8.70% fixed-rate, due March 2010		54.0
Petal GO Zone Bonds, variable rate, due August 2037		57.5
Yen Term Loan, 4.93% fixed-rate, due March 2009 (1)		217.6
Senior Notes B, 7.50% fixed-rate, due February 2011		450.0
Senior Notes C, 6.375% fixed-rate, due February 2013		350.0
Senior Notes D, 6.875% fixed-rate, due March 2033		500.0
Senior Notes F, 4.625% fixed-rate, due October 2009 (1)		500.0
Senior Notes G, 5.60% fixed-rate, due October 2014		650.0
Senior Notes H, 6.65% fixed-rate, due October 2034		350.0
Senior Notes I, 5.00% fixed-rate, due March 2015		250.0
Senior Notes J, 5.75% fixed-rate, due March 2035		250.0
Senior Notes K, 4.950% fixed-rate, due June 2010		500.0
Senior Notes L, 6.30% fixed-rate, due September 2017		800.0
Senior Notes M, 5.65% fixed-rate, due April 2013		400.0
Senior Notes N, 6.50% fixed-rate, due January 2019		700.0
Senior Notes O, 9.75% fixed-rate, due January 2014		500.0
TEPPCO senior debt obligations:
TEPPCO Revolving Credit Facility, variable rate, due December 2012		516.7
TEPPCO Senior Notes,7.625% fixed-rate, due February 2012		500.0
TEPPCO Senior Notes, 6.125% fixed-rate, due February 2013		200.0
TEPPCO Senior Notes, 5.90% fixed-rate, due April 2013		250.0
TEPPCO Senior Notes, 6.65% fixed-rate, due April 2018		350.0
TEPPCO Senior Notes, 7.55% fixed-rate, due April 2038		400.0
Duncan Energy Partners’ debt obligations:
DEP I Revolving Credit Facility, variable rate, due February 2011		202.0
DEP II Term Loan Agreement, variable rate, due December 2011		282.3
Total principal amount of senior debt obligations		10,030.1
EPO Junior Subordinated Notes A, fixed/variable rate, due August 2066		550.0
EPO Junior Subordinated Notes B, fixed/variable rate, due January 2068		682.7
TEPPCO Junior Subordinated Notes, fixed/variable rate, due June 2067		300.0
Total principal amount of senior and junior debt obligations		11,562.8
Other, non-principal amounts:
Change in fair value of debt-related derivative instruments (see Note 6)		51.9
Unamortized discounts, net of premiums		(12.6	)
Unamortized deferred net gains related to terminated interest rate swaps (see Note 6)		35.8
Total other, non-principal amounts		75.1
Total long-term debt	$	11,637.9
Standby letters of credit outstanding	$	1.0
(1)   In accordance with SFAS 6, Classification of Short-Term Obligations Expected to be Refinanced, long-term and current maturities of debt reflects the classification of such obligations at December 31, 2008. With respect to the Yen Term Loan and Senior Notes F due in October 2009, we have the ability to use available credit capacity under EPO’s Multi-Year Revolving Credit Facility to fund the repayment of this debt. (2)   The Dixie Revolving Credit Facility was terminated in January 2009.

Letters of credit

At December 31, 2008, we had $1.0 million in standby letters outstanding under Duncan Energy Partners’ DEP I Revolving Credit Facility.

Parent-Subsidiary guarantor relationships

Enterprise Products Partners L.P. acts as guarantor of the consolidated debt obligations of EPO with the exception of the DEP I Revolving Credit Facility and the DEP II Term Loan Agreement.  If EPO

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were to default on any of its guaranteed debt, Enterprise Products Partners L.P. would be responsible for full repayment of that obligation.

TE Products Pipeline Company, LLC (“TE Products”), TCTM, L.P., TEPPCO Midstream Companies, LLC, and Val Verde Gas Gathering Company, L.P. (collectively, the “Subsidiary Guarantors”) act as guarantors of TEPPCO’s senior notes and Revolving Credit Facility.  The Subsidiary Guarantors also act as guarantors, on a junior subordinated basis, of TEPPCO’s junior subordinated notes.  The guarantees are full, unconditional and joint and several.  If TEPPCO were to default on any of its guaranteed debt, the Subsidiary Guarantors would be responsible for full repayment of that obligation.  TEPPCO’s debt obligations are non-recourse to Enterprise Products Partners L.P.  As a result of the debt exchanges related to the TEPPCO Merger and the repayment and termination of the TEPPCO Revolving Credit Facility by EPO in October 2009, only $54.3 million of the TEPPCO senior and junior subordinated notes outstanding at December 31, 2008 (or 2.2%) remain guaranteed by the Guarantor Subsidiaries.  These subsidiary guarantees were terminated in November 2009.

EPO’s debt obligations

Multi-Year Revolving Credit Facility.  In November 2007, EPO executed an amended and restated Multi-Year Revolving Credit Facility totaling $1.75 billion, which replaced an existing $1.25 billion multi-year revolving credit agreement.  Amounts borrowed under the amended and restated credit agreement mature in November 2012, although EPO is permitted, 30 to 60 days before the maturity date in effect, to convert the principal balance of the revolving loans then outstanding into a non-revolving, one-year term loan (the “term-out option”).  There is no sublimit on the amount of standby letters of credit that can be outstanding under the amended facility. EPO’s borrowings under this agreement are unsecured general obligations that are non-recourse to EPGP.  We have guaranteed repayment of amounts due under this revolving credit agreement through an unsecured guarantee.

As defined by the credit agreement, variable interest rates charged under this facility bear interest at a Eurodollar rate plus an applicable margin.  In addition, EPO is required to pay a quarterly facility fee on each lender’s commitment irrespective of commitment usage.

The applicable margins will be increased by 0.10% per annum for each day that the total outstanding loans and letter of credit obligations under the facility exceeds 50% of the total lender commitments. Also, upon the conversion of the revolving loans to term loans pursuant to the term-out option described above, the applicable margin will increase by 0.125% per annum and, if immediately prior to such conversion, the total amount of outstanding loans and letter of credit obligations under the facility exceeds 50% of the total lender commitments, the applicable margin with respect to the term loans will increase by an additional 0.10% per annum.

EPO may increase the amount that may be borrowed under the facility, without the consent of the lenders, by an amount not exceeding $500.0 million by adding to the facility one or more new lenders and/or requesting that the commitments of existing lenders be increased, although none of the existing lenders has agreed to or is obligated to increase its existing commitment. EPO may request unlimited one-year extensions of the maturity date by delivering a written request to the administrative agent, but any such extension shall be effective only if consented to by the required lenders in their sole discretion.

The Multi-Year Revolving Credit Facility contains various covenants related to EPO’s ability to incur certain indebtedness; grant certain liens; enter into certain merger or consolidation transactions; and make certain investments. The loan agreement also requires EPO to satisfy certain financial covenants at the end of each fiscal quarter.  The credit agreement also restricts EPO’s ability to pay cash distributions to us if a default or an event of default (as defined in the credit agreement) has occurred and is continuing at the time such distribution is scheduled to be paid.

Pascagoula MBFC Loan.  In connection with the construction of our Pascagoula, Mississippi natural gas processing plant in 2000, EPO entered into a ten-year fixed-rate loan with the Mississippi Business Finance Corporation (“MBFC”).  This loan is subject to a make-whole redemption right and is

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guaranteed by us through an unsecured and unsubordinated guarantee.  The Pascagoula MBFC Loan contains certain covenants including the maintenance of appropriate levels of insurance on the Pascagoula facility.

The indenture agreement for this loan contains an acceleration clause whereby if EPO’s credit rating by Moody’s declines below Baa3 in combination with our credit rating at Standard & Poor’s declining below BBB-, the $54.0 million principal balance of this loan, together with all accrued and unpaid interest, would become immediately due and payable 120 days following such event.  If such an event occurred, we would have to either redeem the Pascagoula MBFC Loan or provide an alternative credit agreement to support our obligation under this loan.

Petal GO Zone Bonds.  In August 2007, Petal borrowed $57.5 million from the MBFC pursuant to a loan agreement and promissory note between Petal Gas Storage, L.L.C. (“Petal”) and the MBFC to pay a portion of the costs of certain natural gas storage facilities located in Petal, Mississippi.  The promissory note between Petal and MBFC is guaranteed by EPO and supported by a letter of credit issued by Petal.  On the same date, the MBFC issued $57.5 million in Gulf Opportunity Zone Tax-Exempt (“GO Zone”) bonds to various third parties.  A portion of the GO Zone bond proceeds were being held by a third party trustee and reflected as a component of other assets on our balance sheet.  During 2008, virtually all proceeds from the GO Zone bonds were released by the trustee to fund construction costs associated with the expansion of our Petal, Mississippi storage facility.  The promissory note and the GO Zone bonds have identical terms including floating interest rates and maturities of 30 years.  The bonds and the associated tax incentives are authorized under the Mississippi Business Finance Act and the Gulf Opportunity Zone Act of 2005. 

Petal MBFC Loan.  In August 2007, Petal, a wholly owned subsidiary of EPO, entered into a loan agreement and a promissory note with the MBFC under which Petal may borrow up to $29.5 million.  On the same date, the MBFC issued taxable bonds to EPO in the maximum amount of $29.5 million.  As of December 31, 2008, there was $8.9 million outstanding under the loan and the bonds.  EPO will make advances on the bonds to the MBFC and the MBFC will in turn make identical advances to Petal under the promissory note. The promissory note and the taxable bonds have identical terms including fixed interest rates of 5.90% and maturities of fifteen years.  The bonds and the associated tax incentives are authorized under the Mississippi Business Finance Act.  Petal may prepay on the promissory note without penalty, and thus cause the bonds to be redeemed, any time after one year from their date of issue.  The loan and bonds are netted in preparing our Supplemental Consolidated Balance Sheet.

Japanese Yen Term Loan.  In November 2008, EPO executed the Yen Term Loan in the amount of approximately 20.7 billion yen (approximately $217.6 million U.S. Dollar equivalent on the closing date).  EPO’s obligations under the Yen Term Loan are not secured by any collateral; however, the obligations are guaranteed by Enterprise Products Partners L.P. pursuant to a guaranty agreement.  The Yen Term Loan will mature on March 30, 2009.

Under the Yen Term Loan, interest accrues on the loan at the Tokyo Interbank Offered Rate (“TIBOR”) plus 2.0%.  EPO entered into foreign exchange currency swaps that effectively convert the TIBOR loan into a U.S. Dollar loan with a fixed interest rate (including the cost of the swaps) through maturity of approximately 4.93%.  As a result, EPO received US$217.6 million net from this transaction.  In addition, EPO executed a forward purchase exchange (yen principal and interest due) for March 30, 2009 at an exchange rate of 94.515 to eliminate foreign exchange risk, resulting in a payment of US$221.6 million on March 30, 2009.  For additional information see Note 6.

364-Day Revolving Credit Facility.  In November 2008, EPO executed a 364-Day Revolving Credit Agreement (“364-Day Revolving Credit Facility”) in the amount of $375.0 million.  EPO’s obligations under the 364-Day Revolving Credit Facility are not secured by any collateral; however, the obligations are guaranteed by Enterprise Products Partners L.P. pursuant to a guaranty agreement.  The 364-Day Revolving Credit Facility will mature on November 16, 2009.  As of December 31, 2008, there were no borrowings outstanding under this credit facility.

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The 364-Day Revolving Credit Facility offers the following loans, each having different interest requirements: (i) LIBOR loans bear interest at a rate per annum equal to LIBOR plus the applicable LIBOR margin and (ii) Base Rate loans bear interest each day at a rate per annum equal to the higher of (a) the rate of interest announced by the administrative agent as its prime rate, (b) 0.5% per annum above the Federal Funds Rate in effect on such date , and (c) 1.0% per annum above LIBOR in effect on such date plus, in each case, the applicable Base Rate margin.

The commitments may be increased by an amount not to exceed $1.0 billion by adding one or more new lenders to the facility or increasing the commitments of existing lenders, although none of the existing lenders has agreed to or is obligated to increase its existing commitment. With certain exceptions and after certain time periods, if EPO issues debt with a maturity of more than three years, the lenders’ commitments under the 364-Day Revolving Credit Facility will be reduced to the extent of any debt proceeds, and any outstanding loans in excess of such reduced commitments must be repaid.

Senior Notes B through L.  These fixed-rate notes are unsecured obligations of EPO and rank equally with its existing and future unsecured and unsubordinated indebtedness.  They are senior to any future subordinated indebtedness.  EPO’s borrowings under these notes are non-recourse to EPGP.  We have guaranteed repayment of amounts due under these notes through an unsecured and unsubordinated guarantee.  Our guarantee of such notes is non-recourse to EPGP.  The Senior Notes 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.

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.  EPO’s borrowings under these notes are non-recourse to EPGP.  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.

Senior Notes O. In December 2008, EPO sold $500.0 million in principal amount of 5-year senior unsecured notes (“Senior Notes O”) under its universal registration statement.  Senior Notes O were issued at 100% of their principal amount, have a fixed interest rate of 9.75% and mature in January 2014.

Senior Notes O pay interest semi-annually in arrears on January 31 and July 31 of each year, commencing January 31, 2009.  Net proceeds from the issuance of Senior Notes O were used to temporarily reduce indebtedness outstanding under the EPO Multi-Year Revolving Credit Facility.

Senior Notes O rank equal with EPO’s existing and future unsecured and unsubordinated indebtedness.  They are senior to any existing and future subordinated indebtedness of EPO.  EPO’s borrowings under these notes are non-recourse to EPGP.  Senior Notes O 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.

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Junior Notes A.  In the third quarter of 2006, EPO sold $550.0 million in principal amount of fixed/floating, unsecured, long-term subordinated notes due 2066 (“Junior Notes A”).  EPO used the proceeds from this subordinated debt to temporarily reduce borrowings outstanding under its Multi-Year Revolving Credit Facility and for general partnership purposes.  EPO’s payment obligations under Junior Notes A are subordinated to all of its current and future senior indebtedness (as defined in the related indenture agreement).  Enterprise Products Partners L.P. has guaranteed EPO’s repayment of amounts due under Junior Notes A through an unsecured and subordinated guarantee.

The indenture agreement governing Junior Notes A allows EPO to defer interest payments on one or more occasions for up to ten consecutive years, subject to certain conditions.  The indenture agreement also provides that, unless (i) all deferred interest on Junior Notes A has been paid in full as of the most recent interest payment date, (ii) no event of default under the indenture agreement has occurred and is continuing and (iii) we are not in default of our obligations under related guarantee agreements, neither we nor EPO cannot declare or make any distributions to any of our respective equity securities or make any payments on indebtedness or other obligations that rank pari passuwith or are subordinated to the Junior Notes A.

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

In connection with the issuance of Junior Notes A, EPO entered into a Replacement Capital Covenant in favor of the covered debt holders (as defined in the underlying documents) pursuant to which EPO agreed for the benefit of such debt holders that it would not redeem or repurchase such junior notes unless such redemption or repurchase is made using proceeds from the issuance of certain securities.

Junior Notes B.  EPO sold $700.0 million in principal amount of fixed/floating, unsecured, long-term subordinated notes due January 2068 (“Junior Notes B”) during the second quarter of 2007.  EPO used the proceeds from this subordinated debt to temporarily reduce borrowings outstanding under its Multi-Year Revolving Credit Facility and for general partnership purposes.  EPO’s payment obligations under Junior Notes B are subordinated to all of its current and future senior indebtedness (as defined in the Indenture Agreement).  Enterprise Products Partners L.P. has guaranteed repayment of amounts due under Junior Notes B through an unsecured and subordinated guarantee.

The indenture agreement governing Junior Notes B allows EPO to defer interest payments on one or more occasions for up to ten consecutive years subject to certain conditions.  During any period in which interest payments are deferred and subject to certain exceptions, neither we nor EPO can declare or make any distributions to any of our respective equity securities or make any payments on indebtedness or other obligations that rank pari passuwith or are subordinate to Junior Notes B.  Junior Notes B rank pari passu with Junior Notes A.

The Junior Notes B will bear interest at a fixed annual rate of 7.034% through January 15, 2018, payable semi-annually in arrears in January and July of each year, which commenced in January 2008.  After January 2018, the Junior Notes B will bear variable rate interest at the greater of (1) the sum of the 3-month LIBOR for the related interest period plus a spread of 268 basis points or (2) 7.034% per annum, payable quarterly in arrears in January, April, July and October of each year commencing in April 2018.  Interest payments may be deferred on a cumulative basis for up to ten consecutive years, subject to certain provisions.  The Junior Notes B mature in January 2068 and are not redeemable by EPO prior to January 2018 without payment of a make-whole premium.

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In connection with the issuance of Junior Notes B, we and EPO entered into a Replacement Capital Covenant in favor of the covered debt holders (as named therein) pursuant to which we and EPO agreed for the benefit of such debt holders that neither we nor EPO would redeem or repurchase such junior notes on or before January 15, 2038, unless such redemption or repurchase is made from the proceeds of issuance of certain securities.

During the fourth quarter of 2008, we retired $17.3 million of our Junior Notes B for $10.2 million.

TEPPCO’s debt obligations

TEPPCO Revolving Credit Facility.  This unsecured revolving credit facility has a borrowing capacity of $950.0 million.  In July 2008, commitments under this facility were increased from $700.0 million to $950.0 million.  This credit facility matures in December 2012, but we may request unlimited extensions of the maturity date subject to certain conditions.  There is no limit on the total amount of standby letters of credit that can be outstanding under this credit facility.

Variable interest rates charged under this facility generally bear interest, at our election at the time of each borrowing, at either (i) a LIBOR plus an applicable margin (as defined in the credit agreement) or (ii) the lender’s base rate as defined in the agreement.

The revolving credit agreement contains various covenants related to our ability to, among other things, incur certain indebtedness; grant certain liens; make certain distributions; engage in specified transactions with affiliates; and enter into certain merger or consolidation transactions.  We must also satisfy certain financial covenants at the end of each fiscal quarter.

TEPPCO Short-Term Credit Facility.  At December 31, 2007, we had in place an unsecured short term credit agreement (the “TEPPCO Short-Term Credit Facility”) with a borrowing capacity of $1.00 billion.  No amounts were borrowed under this agreement at December 31, 2007.  During the first quarter of 2008, we borrowed $1.00 billion under this credit agreement to finance the retirement of the TE Products’ senior notes, the acquisition of two marine service businesses and for other general partnership purposes.  In March 2008, we repaid amounts borrowed under this credit agreement, using proceeds from the TEPPCO Senior Notes offering, and terminated the facility.

The following table summarizes our borrowing and repayment activity under this credit agreement during the first quarter of 2008:

Borrowings, January 2008 (1)	$	355.0
Borrowings, February 2008 (2)		645.0
Repayments, March 2008		(1,000.0	)
Balance, March 27, 2008 (3)	$	--
(1)   Funds borrowed to finance the retirement of TE Products’ senior notes. (2)   Funds borrowed to finance the marine services acquisitions and for general partnership purposes. (3)   TEPPCO’s Short-Term Credit Facility was terminated on March 27, 2008 upon full repayment of borrowings thereunder.

TEPPCO Senior Notes.  In February 2002 and January 2003, TEPPCO issued 7.625% Senior Notes and 6.125% Senior Notes, respectively.  In March 2008, TEPPCO sold $250.0 million in principal amount of 5-year senior unsecured notes, $350.0 million in principal amount of 10-year senior unsecured notes and $400.0 million in principal amount of 30-year senior unsecured notes.  The 5-year senior notes were issued at 99.922% of their principal amount, have a fixed interest rate of 5.90%, and mature in April 2013.  The 10-year senior notes were issued at 99.640% of their principal amount, have a fixed interest rate of 6.65%, and mature in April 2018.  The 30-year senior notes were issued at 99.451% of their principal amount, have a fixed interest rate of 7.55%, and mature in April 2038.

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The senior notes issued in March 2008 pay interest semi-annually in arrears on April 15 and October 15 of each year, beginning October 15, 2008.  Net proceeds from the issuance of these notes were used to repay and terminate the TEPPCO Short-Term Credit Facility.  The notes issued in March 2008 rank pari passu with our existing and future unsecured and unsubordinated indebtedness.  They are senior to any future subordinated indebtedness.

The TEPPCO Senior Notes are subject to make-whole redemption rights and are redeemable at any time at our option. The indenture agreements governing these notes contain certain covenants, including, but not limited to the creation of liens securing indebtedness and sale and leaseback transactions.  However, the indentures do not limit our ability to incur additional indebtedness.

TEPPCO Junior Subordinated Notes.  In May 2007, TEPPCO sold $300.0 million in principal amount of fixed/floating, unsecured, long-term subordinated notes due June 1, 2067 (“TEPPCO Junior Subordinated Notes”).  We used the proceeds from this subordinated debt to temporarily reduce borrowings outstanding under the TEPPCO Revolving Credit Facility and for general partnership purposes.  The payment obligations under the TEPPCO Junior Subordinated Notes are subordinated to all of its current and future senior indebtedness (as defined in the related indenture).

The indenture governing the TEPPCO Junior Subordinated Notes does not limit our ability to incur additional debt, including debt that ranks senior to or equally with the TEPPCO Junior Subordinated Notes.  The indenture allows us to defer interest payments on one or more occasions for up to ten consecutive years, subject to certain conditions.  During any period in which interest payments are deferred and subject to certain exceptions, (i) we cannot declare or make any distributions to any of its respective equity securities and (ii) neither we nor the Subsidiary Guarantors can make any payments on indebtedness or other obligations that rank pari passu with or are subordinated to the TEPPCO Junior Subordinated Notes.

The TEPPCO Junior Subordinated Notes bear interest at a fixed annual rate of 7.0% from May 2007 to June 1, 2017, payable semi-annually in arrears.  After June 1, 2017, the TEPPCO Junior Subordinated Notes will bear interest at a variable annual rate equal to the 3-month LIBOR for the related interest period plus 2.7775%, payable quarterly in arrears.  The TEPPCO Junior Subordinated Notes mature in June 2067.  The TEPPCO Junior Subordinated Notes are redeemable in whole or in part prior to June 1, 2017 for a “make-whole” redemption price and thereafter at a redemption price equal to 100% of their principal amount plus accrued and unpaid interest.  The TEPPCO Junior Subordinated Notes are also redeemable prior to June 1, 2017 in whole (but not in part) upon the occurrence of certain tax or rating agency events at specified redemption prices.

In connection with the issuance of the TEPPCO Junior Subordinated Notes, we and the Subsidiary Guarantors entered into a Replacement Capital Covenant in favor of holders (as provided therein) pursuant to which we and the Subsidiary Guarantors agreed for the benefit of such debt holders that it would not redeem or repurchase the TEPPCO Junior Subordinated Notes on or before June 1, 2037, unless such redemption or repurchase is from proceeds of issuance of certain securities.

Duncan Energy Partners’ debt obligations

We consolidate the debt of Duncan Energy Partners with that of our own; however, we do not have the obligation to make interest payments or debt payments with respect to the debt of Duncan Energy Partners.

DEP I Revolving Credit Facility.  In February 2007, Duncan Energy Partners entered into a $300.0 million revolving credit facility, all of which may be used for letters of credit, with a $30.0 million sublimit for Swingline loans.  Letters of credit outstanding under this facility reduce the amount available for borrowings.  At the closing of its initial public offering, Duncan Energy Partners made its initial borrowing of $200.0 million under the facility to fund a $198.9 million cash distribution to EPO and the remainder to pay debt issuance costs.  At December 31, 2008, the principal balance outstanding under this facility was $202.0 million.

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This credit facility matures in February 2011 and will be used by Duncan Energy Partners in the future to fund working capital and other capital requirements and for general partnership purposes.  Duncan Energy Partners may make up to two requests for one-year extensions of the maturity date (subject to certain restrictions).  The revolving credit facility is available to pay distributions upon the initial contribution of assets to Duncan Energy Partners, fund working capital, make acquisitions and provide payment for general purposes.  Duncan Energy Partners can increase the revolving credit facility, without consent of the lenders, by an amount not to exceed $150.0 million by adding to the facility one or more new lenders and/or increasing the commitments of existing lenders.  No existing lender is required to increase its commitment, unless it agrees to do so in its sole discretion.

This revolving credit facility offers the following unsecured loans, each having different interest requirements: (i) a Eurodollar rate, plus the applicable Eurodollar margin (as defined in the credit agreement), (ii) Base Rate loans bear interest at a rate per annum equal to the higher of (a) the rate of interest publicly announced by the administrative agent, Wachovia Bank, National Association, as its Base Rate and (b) 0.5% per annum above the Federal Funds Rate in effect on such date and (iii) Swingline loans bear interest at a rate per annum equal to LIBOR plus an applicable LIBOR margin.

The Duncan Energy Partners’ credit facility contains certain financial and other customary covenants.  Also, if an event of default exists under the credit agreement, the lenders will be able to accelerate the maturity date of amounts borrowed under the credit agreement and exercise other rights and remedies.

DEP II Term Loan Agreement.  In April 2008, Duncan Energy Partners entered into a standby term loan agreement consisting of commitments for up to a $300.0 million senior unsecured term loan.  Subsequently, commitments under this agreement decreased to $282.3 million due to bankruptcy of one of the lenders. Duncan Energy Partners borrowed the full amount of $282.3 million on December 8, 2008 in connection with the acquisition of equity interests in the DEP II Midstream Businesses.  See “Relationship with Duncan Energy Partners” in Note 15 for additional information regarding the DEP II Midstream Businesses.

Loans under the term loan agreement are due and payable on December 8, 2011. Duncan Energy Partners may also prepay loans under the term loan agreement at any time, subject to prior notice in accordance with the credit agreement. Loans may also be payable earlier in connection with an event of default.

Loans under the term loan agreement bear interest of the type specified in the applicable borrowing request, and consist of either Alternate Base Rate (“ABR”) loans or Eurodollar loans.  The term loan agreement contains customary affirmative and negative covenants.

Dixie Revolving Credit Facility

Dixie’s debt obligation consisted of a senior, unsecured revolving credit facility having a borrowing capacity of $28.0 million.  As of December 31, 2008, there were no debt obligations outstanding under the Dixie Revolver.  This credit facility was terminated in January 2009.  EPO consolidated the debt of Dixie; however, EPO did not have the obligation to make interest or debt payments with respect to Dixie’s debt.

Variable interest rates charged under this facility generally bore interest, at Dixie’s election at the time of each borrowing, at either (i) a Eurodollar rate plus an applicable margin or (ii) the greater of (a) the prime rate or (b) the Federal Funds Effective Rate plus 0.5%.

Canadian Debt Obligation

In May 2007, Canadian Enterprise Gas Products, Ltd. (“Canadian Enterprise”), a wholly owned subsidiary of EPO, entered into a $30.0 million Canadian revolving credit facility with The Bank of Nova

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Scotia.  The credit facility, which includes the issuance of letters of credit, matures in October 2011.  Letters of credit outstanding under this facility reduce the amount available for borrowings.

Borrowings may be made in Canadian or U.S. dollars.  Canadian denominated borrowings may be comprised of Canadian Prime Rate (“CPR”) loans or Bankers’ Acceptances and U.S. denominated borrowings may be comprised of ABR or Eurodollar loans, each having different interest rate requirements.  CPR loans bear interest at a rate determined by reference to the Canadian Prime Rate.  ABR loans bear interest at a rate determined by reference to an alternative base rate as defined in the credit agreement.  Eurodollar loans bear interest at a rate determined by the LIBOR plus an applicable rate as defined in the credit agreement.  Bankers’ Acceptances carry interest at the rate for Canadian bankers’ acceptances plus an applicable rate as defined in the credit agreement.

The credit facility contains customary covenants and events of default.  The restrictive covenants limit Canadian Enterprise from materially changing the nature of its business or operations, dissolving, or completing mergers.  A continuing event of default would accelerate the maturity of amounts borrowed under the credit facility.  The obligations under the credit facility are guaranteed by EPO.  As of December 31, 2008, there were no debt obligations outstanding under this credit facility.

Covenants

We are in compliance with the covenants of our consolidated debt agreements at December 31, 2008.

Information regarding variable interest rates paid

The following table presents the range of interest rates and weighted-average interest rates paid on our consolidated variable-rate debt obligations during the year ended December 31, 2008.

	Range of	Weighted-Average
	Interest Rates	Interest Rate
	Paid	Paid
EPO’s Multi-Year Revolving Credit Facility	0.97% to 6.00%	3.54%
TEPPCO Revolving Credit Facility	1.06% to 2.24%	1.40%
TEPPCO Short-Term Credit Facility	3.59% to 4.96%	4.02%
DEP I Revolving Credit Facility	1.30% to 6.20%	4.25%
DEP II Term Loan Agreement	2.93% to 2.93%	2.93%
Dixie Revolving Credit Facility	0.81% to 5.50%	3.20%
Petal GO Zone Bonds	0.78% to 7.90%	2.24%

Consolidated debt maturity table

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

2009	$	--
2010		554.0
2011		934.3
2012		2,534.3
2013		1,200.0
Thereafter		6,340.2
Total scheduled principal payments	$	11,562.8

In accordance with SFAS 6, long-term and current maturities of debt reflect the classification of such obligations at December 31, 2008.

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Debt Obligations of Unconsolidated Affiliates

We have three unconsolidated affiliates with long-term debt obligations.  The following table shows (i) the ownership interest in each entity at December 31, 2008, (ii) total debt of each unconsolidated affiliate at December 31, 2008 (on a 100% basis to the unconsolidated affiliate) and (iii) the corresponding scheduled maturities of such debt.

				Scheduled Maturities of Debt
	Ownership													After
	Interest	Total		2009		2010		2011		2012		2013		2013
Poseidon	36%	$	109.0	$	--	$	--	$	109.0	$	--	$	--	$	--
Evangeline	49.5%		15.7		5.0		3.2		7.5		--		--		--
Centennial	50%		129.9		9.9		9.1		9.0		8.9		8.6		84.4
Total		$	254.6	$	14.9	$	12.3	$	125.5	$	8.9	$	8.6	$	84.4

The credit agreements of these unconsolidated affiliates include customary covenants, including financial covenants.  These businesses were in compliance with such covenants at December 31, 2008.  The credit agreements of these unconsolidated affiliates restrict their ability to pay cash dividends or distributions if a default or an event of default (as defined in each credit agreement) has occurred and is continuing at the time such dividend or distribution is scheduled to be paid.

The following information summarizes the significant terms of the debt obligations of these unconsolidated affiliates at December 31, 2008:

Poseidon.  Poseidon has a $150.0 million variable-rate revolving credit facility that matures in May 2011.  This credit agreement is secured by substantially all of Poseidon’s assets.  The variable interest rates charged on this debt at December 31, 2008 and December 31, 2007 were 4.31% and 6.62%, respectively.

Evangeline.   At December 31, 2008, Evangeline’s debt obligations consisted of (i) $8.2 million of 9.90% fixed-rate Series B senior secured notes due December 2010 and (ii) a $7.5 million subordinated note payable. The Series B senior secured notes are collateralized by Evangeline’s property, plant and equipment; proceeds from a gas sales contract and by a debt service reserve requirement.  Scheduled principal repayments on the Series B notes are $5.0 million in 2009 with a final repayment in 2010 of approximately $3.2 million.

Evangeline incurred the subordinated note payable as a result of its acquisition of a contract-based intangible asset in the early 1990s. This note is subject to a subordination agreement which prevents the repayment of principal and accrued interest on the subordinated note until such time as the Series B noteholders are either fully cash secured through debt service accounts or have been completely repaid.

Variable rate interest accrues on the subordinated note at a Eurodollar rate plus 0.5%.  The variable interest rates charged on this note at December 31, 2008 and December 31, 2007 were 3.20% and 5.88%, respectively.  Accrued interest payable related to the subordinated note was $9.8 million and $9.1 million at December 31, 2008 and December 31, 2007, respectively.

Centennial.   At December 31, 2008, Centennial’s debt obligations consisted of $129.9 million borrowed under a master shelf loan agreement.  Borrowings under the master shelf agreement mature in May 2024 and are collateralized by substantially all of Centennial’s assets and severally guaranteed by Centennial’s owners.

TEPPCO and its joint venture partner in Centennial have each guaranteed one-half of Centennial’s debt obligations.  If Centennial defaults on its debt obligations, the estimated payment obligation is $65.0 million.  At December 31, 2008, TEPPCO had recognized a liability of $9.0 million for its share of the Centennial debt guaranty.  A downgrade of our credit ratings could result in our being required to post financial collateral up to the amount of our guaranty of indebtedness.  Further, from time to time we enter

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into contracts in connection with our commodity and interest rate hedging activities and crude oil marketing business that require the posting of financial collateral, which may be substantial, if our credit were to be downgraded below investment grade.

Note 13.  Equity

At December 31, 2008, equity consisted of the capital account of Enterprise GP Holdings, accumulated other comprehensive loss and noncontrolling interest.  Enterprise GP Holdings is a publicly traded limited partnership that completed an initial public offering of its common units in August 2005 and trades on the NYSE under the ticker symbol “EPE.”

Accumulated Other Comprehensive Loss

The following table presents the components of accumulated other comprehensive loss at December 31, 2008:

Commodity financial instruments (1)	$	(114.1	)
Interest rate financial instruments (1)		(41.9	)
Foreign currency cash flow hedges (1)		10.6
Foreign currency translation adjustment (2)		(1.3	)
Pension and postretirement benefit plans (3)		(0.8	)
Subtotal		(147.5	)
Amount attributable to noncontrolling interest		145.5
Total accumulated other comprehensive loss
in member’s equity	$	(2.0	)
(1)   See Note 6 for additional information regarding these components of accumulated other comprehensive loss. (2)   Relates to transactions of our Canadian NGL marketing subsidiary. (3)   See Note 5 for additional information regarding pension and postretirement benefit plans.

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Noncontrolling Interest

Prior to the completion of the TEPPCO Merger, effective October 26, 2009, we accounted for our interest in TEPPCO and TEPPCO GP as noncontrolling interest.  Under this method of presentation our share of the net assets of TEPPCO and TEPPCO GP are presented as noncontrolling interest, a component of equity, on our Supplemental Consolidated Balance Sheet.  The following table shows the components of noncontrolling interest at December 31, 2008:

Former owners of TEPPCO (1)	$	2,827.6
Limited partners of Enterprise Products Partners:
Third-party owners of Enterprise Products Partners(2)		5,010.6
Related party owners of Enterprise Products Partners (3)		649.3
Limited partners of Duncan Energy Partners:
Third-party owners of Duncan Energy Partners(4)		281.1
Joint venture partners(5)		148.0
Accumulated other comprehensive loss attributable to
noncontrolling interest		(145.5	)
Total noncontrolling interest on Supplemental Consolidated Balance Sheet	$	8,771.1
(1)   Represents former ownership interests in TEPPCO and TEPPCO GP (see Note 1 “TEPPCO Merger and Basis of Presentation”). This amount excludes AOCI attributable to former owners of TEPPCO. (2)   Consists of non-affiliate public unitholders of Enterprise Products Partners. (3)   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. (4)   Consists of non-affiliate public unitholders of Duncan Energy Partners. (5)   Represents third-party ownership interests in joint ventures that we consolidate, including Seminole, Tri-States Pipeline, L.L.C. (“Tri-States”), Independence Hub, LLC and Wilprise Pipeline Company, L.L.C. (“Wilprise”).

Note 14.  Business Segments

As previously mentioned in Note 1, we revised our business segments and related disclosures as a result of the TEPPCO Merger.  We have five reportable business segments: NGL Pipelines & Services, Onshore Natural Gas Pipelines & Services, Onshore Crude Oil Pipelines & Services, Offshore Pipelines & Services and Petrochemical & Refined Products 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.  The following information summarizes the principal operations and activities of each of our new business segments:

§   NGL Pipelines & Services includes our (i) natural gas processing business and related NGL marketing activities; (ii) NGL pipelines, including our Mid-America Pipeline System; (iii) NGL and related product storage facilities; and (iv) NGL fractionation facilities.  This segment also includes our import and export terminal operations.

§   Onshore Natural Gas Pipelines & Services includes our onshore natural gas pipeline systems that provide for the gathering and transportation of natural gas in Alabama, Colorado, Louisiana, Mississippi, New Mexico, Texas and Wyoming.  We own two salt dome natural gas storage facilities located in Mississippi and lease natural gas storage facilities located in Texas and Louisiana.  This segment also includes our natural gas marketing activities.

§   Onshore Crude Oil Pipelines & Services business segment includes our onshore crude oil pipelines and related storage terminals.  This segment also includes our related crude oil marketing activities.

§   Offshore Pipelines & Services includes our (i) offshore natural gas pipelines strategically located to serve production areas including some of the most active drilling and development regions in

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the Gulf of Mexico, (ii) offshore Gulf of Mexico crude oil pipeline systems and (iii) six multi purpose offshore hub platforms located in the Gulf of Mexico with crude oil or natural gas processing capabilities.

§   Petrochemical & Refined Products Services includes our (i) propylene fractionation plants and related activities, (ii) butane isomerization facilities, (iii) octane enhancement facility, (iv) refined products pipelines, including our Products Pipeline System, and related activities and (v) marine transportation assets and other services.

The majority of our plant-based operations are located in Texas, Louisiana, Mississippi, New Mexico, Colorado and Wyoming.  Our natural gas, NGL, refined products and crude oil pipelines are located in a number of regions of the United States including (i) the Gulf of Mexico offshore Texas, Louisiana, and onshore in Colorado; (ii) the south and southeastern United States (primarily in Texas, Louisiana, Mississippi and Alabama); (iii) the Midwestern and northeastern United States; and (iv) certain regions of the central and western United States, including the Rocky Mountains.  Our marketing activities are headquartered in Houston, Texas and Oklahoma City, Oklahoma 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 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 at December 31, 2008:

	Reportable Segments
			Onshore		Onshore				Petrochemical
	NGL		Natural Gas		Crude Oil		Offshore		& Refined		Adjustments
	Pipelines		Pipelines		Pipelines		Pipelines		Products		and		Consolidated
	& Services		& Services		& Services		& Services		Services		Eliminations		Totals
Segment assets	$	5,622.4	$	5,223.6	$	386.9	$	1,394.5	$	2,090.0	$	2,015.4	$	16,732.8
Investments in unconsolidated affiliates (see Note 9)		144.3		25.9		186.2		469.0		86.5		--		911.9
Intangible assets, net (see Note 11)		351.4		584.4		6.9		116.2		124.0		--		1,182.9
Goodwill (see Note 11)		341.2		284.9		303.0		82.1		1,008.4		--		2,019.6

Note 15.  Related Party Transactions

The following table summarizes our related party receivable and payable amounts at December 31, 2008:

Accounts receivable - related parties:
EPCO and affiliates	$	0.2
Energy Transfer Equity and subsidiaries		35.0
Other		0.1
Total	$	35.3
Accounts payable - related parties:
EPCO and affiliates	$	14.1
Energy Transfer Equity and subsidiaries		0.1
Other		3.2
Total	$	17.4

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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 a part of our consolidated group of companies:

§   EPCO and its private company subsidiaries;

§   Enterprise GP Holdings, which owns and controls EPGP; and

§   the Employee Partnerships (see Note 4).

We also have an ongoing relationship with Duncan Energy Partners, the financial statements of which are consolidated with those 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 15.

EPCO is a private company controlled by Dan L. Duncan, who is also a Director and Chairman of EPGP, our general partner.  At December 31, 2008, EPCO and its affiliates beneficially owned 152,506,527 (or 34.5%) of Enterprise Products Partners’ outstanding common units, which includes 13,670,925 of Enterprise Products Partners’ common units owned by Enterprise GP Holdings.  At December 31, 2008, EPCO and affiliates beneficially owned 17,073,315 (or 16.3%) of TEPPCO’s units, including 4,400,000 units owned by Enterprise GP Holdings.  In addition, at December 31, 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 and TEPPCO GP.  The principal business activity of EPGP is to act as our managing partner.  The principal business activity of TEPPCO GP is to act as the sole general partner of TEPPCO.  The executive officers and certain of the directors of EPGP, TEPPCO GP and EPE Holdings are employees of EPCO.

As general partner of Enterprise Products Partners, EPGP received cash distributions of $144.1 million during the year ended December 31, 2008.  This amount includes incentive distributions of $125.9 million for the year ended December 31, 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 $439.8 million in cash distributions from Enterprise Products Partners and Enterprise GP Holdings during the years ended December 31, 2008.

The ownership interests in Enterprise Products Partners that are owned or controlled by Enterprise GP Holdings are pledged as security under a credit facility of Enterprise GP Holdings.  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 lease office space in various buildings from affiliates of EPCO.  The rental rates in these lease agreements approximate market rates.

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EPCO ASA

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 or by other service providers.  Enterprise Products Partners, Duncan Energy Partners, Enterprise GP Holdings and our respective general partners are parties to the ASA.  The significant terms of the ASA are as follows:

§   EPCO will provide selling, general and administrative services, and management and operating services, as may be necessary to manage and operate our businesses, properties and assets (all in accordance with prudent industry practices).  EPCO will employ or otherwise retain the services of such personnel as may be necessary to provide such services.

§   We are required to reimburse EPCO for its services in an amount equal to the sum of all costs and expenses incurred by EPCO which are directly or indirectly related to our business or activities (including expenses reasonably allocated to us by EPCO).  In addition, we have agreed to pay all sales, use, excise, value added or similar taxes, if any, that may be applicable from time to time in respect of the services provided to us by EPCO.

§   EPCO will allow us to participate as a named insured in its overall insurance program, with the associated premiums and other costs being allocated to us.

Under the ASA, EPCO subleases to us (for $1 per year) certain equipment which it holds pursuant to operating leases and has assigned to us its purchase option under such leases (the “retained leases”).  EPCO remains liable for the actual cash lease payments associated with these agreements.  We record the full value of these payments made by EPCO on our behalf as a non-cash related party operating lease expense, with the offset to equity accounted for as a general contribution to our partnership.  We exercised our election under the retained leases to purchase a cogeneration unit in December 2008 for $2.3 million.  Should we decide to exercise the purchase option associated with the remaining agreement, we would pay the original lessor $3.1 million in June 2016.

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 that may arise among Enterprise Products Partners (including EPGP), Enterprise GP Holdings (including EPE Holdings), Duncan Energy Partners (including DEP GP), and the EPCO Group with respect to business opportunities with third parties.  The EPCO Group includes EPCO and its other affiliates, but excludes Enterprise Products Partners, Enterprise GP Holdings, Duncan Energy Partners and their respective general partners.  With respect to potential conflicts with respect to third party business opportunities, the ASA provides, among other things, that:

§   If a business opportunity to acquire “equity securities” (as defined below)is presented to the EPCO Group, Enterprise Products Partners (including EPGP), Enterprise GP Holdings (including EPE Holdings), Duncan Energy Partners (including DEP GP), then Enterprise GP Holdings will have the first right to pursue such opportunity.  The term “equity securities” is defined to include:

§   general partner interests (or securities which have characteristics similar to general partner interests) or interests in “persons” that own or control such general partner or similar interests (collectively, “GP Interests”) and securities convertible, exercisable, exchangeable or otherwise representing ownership or control of such GP Interests; and

§   IDRs and limited partner interests (or securities which have characteristics similar to IDRs or limited partner interests) in publicly traded partnerships or interests in “persons” that own or control such limited partner or similar interests (collectively, “non-GP Interests”); provided

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that such non-GP Interests are associated with GP Interests and are owned by the owners of GP Interests or their respective affiliates.

Enterprise GP Holdings will be presumed to want to acquire the equity securities until such time as EPE Holdings advises the EPCO Group, EPGP and DEP GP that it has abandoned the pursuit of such business opportunity.  In the event that the purchase price of the equity securities is reasonably likely to equal or exceed $100.0 million, the decision to decline the acquisition will be made by the chief executive officer of EPE Holdings after consultation with and subject to the approval of the ACG Committee of EPE Holdings.  If the purchase price is reasonably likely to be less than $100.0 million, the chief executive officer of EPE Holdings may make the determination to decline the acquisition without consulting the ACG Committee of EPE Holdings.

In the event that Enterprise GP Holdings abandons the acquisition and so notifies the EPCO Group, EPGP and DEP GP, Enterprise Products Partners will have the second right to pursue such acquisition.  Enterprise Products Partners will be presumed to want to acquire the equity securities until such time as EPGP advises the EPCO Group and DEP GP that Enterprise Products Partners has abandoned the pursuit of such acquisition.  In determining whether or not to pursue the acquisition, Enterprise Products Partners will follow the same procedures applicable to Enterprise GP Holdings, as described above but utilizing EPGP’s chief executive officer and ACG Committee.

In its sole discretion, Enterprise Products Partners may affirmatively direct such acquisition opportunity to Duncan Energy Partners.  In the event this occurs, Duncan Energy Partners may pursue such acquisition.

§   If any business opportunity not covered by the preceding bullet point (i.e. not involving equity securities) is presented to the EPCO Group, Enterprise Products Partners (including EPGP), Enterprise GP Holdings (including EPE Holdings), or Duncan Energy Partners (including DEP GP), Enterprise Products Partners will have the first right to pursue such opportunity either for itself or, if desired by Enterprise Products Partners in its sole discretion, for the benefit of Duncan Energy Partners. It will be presumed that Enterprise Products Partners will pursue the business opportunity until such time as its general partner advises the EPCO Group, EPE Holdings and DEP GP that it has abandoned the pursuit of such business opportunity.   In the event the purchase price or cost associated with the business opportunity is reasonably likely to equal or exceed $100.0 million, any decision to decline the business opportunity will be made by the chief executive officer of EPGP after consultation with and subject to the approval of the ACG Committee of EPGP.  If the purchase price or cost is reasonably likely to be less than $100.0 million, the chief executive officer of EPGP may make the determination to decline the business opportunity without consulting EPGP’s ACG Committee.
In its sole discretion, Enterprise Products Partners may affirmatively direct such acquisition opportunity to Duncan Energy Partners.  In the event this occurs, Duncan Energy Partners may pursue such acquisition.
In the event that Enterprise Products Partners abandons the business opportunity for itself and Duncan Energy Partners and so notifies the EPCO Group, EPE Holdings and DEP GP, Enterprise GP Holdings will have the second right to pursue such business opportunity.  It will be presumed that Enterprise GP Holdings will pursue such acquisition until such time as its general partner declines such opportunity (in accordance with the procedures described above for Enterprise Products Partners) and advises the EPCO Group that it has abandoned the pursuit of such business opportunity.

The ASA was amended on January 30, 2009 to provide for the cash reimbursement by us and Enterprise GP Holdings to EPCO of distributions of cash or securities, if any, made by EPCO Unit to its Class B limited partners.  The ASA amendment also extended the term under which EPCO provides

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services to the partnership entities from December 2010 to December 2013 and made other updating and conforming changes.

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 such partnerships.  Certain EPCO employees who work on behalf of us and EPCO were issued Class B limited partner interests and admitted as Class B limited partners without any capital contribution.  The profits interest awards (i.e., the Class B limited partner interests) in the Employee Partnerships entitles each holder to participate in the appreciation in value of EPE common units, TEPPCO units and Enterprise Products Partners’ common units.  See Note 4 for additional information regarding the Employee Partnerships.

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.  The contract continues until March 31, 2010 and contains renewal and extension options.  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.

Relationship with Duncan Energy Partners

Duncan Energy Partners was formed in September 2006 and did not acquire any assets prior to February 5, 2007, which was the date it completed its initial public offering of 14,950,000 common units and acquired controlling interests in certain midstream energy businesses of EPO.  The business purpose of Duncan Energy Partners is to acquire, own and operate a diversified portfolio of midstream energy assets and to support the growth objectives of EPO and other affiliates under common control.   Duncan Energy Partners is engaged in (i) the gathering, transportation and storage of natural gas; (ii) NGL transportation and fractionation; (iii) the storage of NGL and petrochemical products; (iv) the transportation of petrochemical products; and (v) the marketing of NGLs and natural gas.

At December 31, 2008, Duncan Energy Partners is owned 99.3% by its limited partners and 0.7% by its general partner, DEP GP, which is a wholly owned subsidiary of EPO.  DEP GP is responsible for managing the business and operations of Duncan Energy Partners.  DEP OLP, a wholly owned subsidiary of Duncan Energy Partners, conducts substantially all of Duncan Energy Partners’ business.

At December 31, 2008, EPO owned approximately 74% of Duncan Energy Partners’ limited partner interests and 100% of its general partner.

DEP I Midstream Businesses

On February 5, 2007, EPO contributed a 66% controlling equity interest in each of the DEP I Midstream Businesses (defined below) to Duncan Energy Partners in a dropdown of assets (the “DEP I dropdown”).  EPO retained the remaining 34% equity interest in each of the DEP I Midstream Businesses.  The DEP I Midstream Businesses consist of (i) Mont Belvieu Caverns, LLC (“Mont Belvieu Caverns”); (ii) Acadian Gas, LLC (“Acadian Gas”); (iii) Enterprise Lou-Tex Propylene Pipeline L.P. (“Lou-Tex Propylene”), including its general partner; (iv) Sabine Propylene Pipeline L.P. (“Sabine Propylene’), including its general partner; and (v) South Texas NGL Pipelines, LLC (“South Texas NGL”).

As consideration for controlling equity interests in the DEP I Midstream Businesses and reimbursement for capital expenditures related to these businesses, Duncan Energy Partners distributed to

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EPO (i) $260.6 million of the $290.5 million of net proceeds from its initial public offering, (ii) $198.9 million in borrowings under its DEP I Revolving Credit Facility and (iii) a net 5,351,571 common units of Duncan Energy Partners.  See Note 12 for information regarding the debt obligations of Duncan Energy Partners.

DEP II Midstream Businesses

On December 8, 2008, Duncan Energy Partners entered into the DEP II Purchase Agreement with EPO and Enterprise GTM, a wholly owned subsidiary of EPO.  Pursuant to the DEP II Purchase Agreement, DEP OLP acquired 100% of the membership interests in Enterprise III from Enterprise GTM, thereby acquiring a 66% general partner interest in Enterprise GC, a 51% general partner interest in Enterprise Intrastate and a 51% membership interest in Enterprise Texas.  Collectively, we refer to Enterprise GC, Enterprise Intrastate and Enterprise Texas as the “DEP II Midstream Businesses.”  EPO was the sponsor of this second dropdown transaction (the “DEP II dropdown”).  Enterprise GTM retained the remaining limited partner and member interests in the DEP II Midstream Businesses.

As consideration for controlling equity interests in the DEP II Midstream Businesses, EPO received $280.5 million in cash and 37,333,887 Class B limited partner units having a market value of $449.5 million from Duncan Energy Partners.  The Class B limited partner units automatically converted to common units of Duncan Energy Partners on February 1, 2009.  The total value of the consideration provided to EPO and Enterprise GTM was $730.0 million.  The cash portion of the consideration provided by Duncan Energy Partners in this dropdown transaction was derived from borrowings under the DEP II Term Loan Agreement.  See Note 12 for information regarding the debt obligations of Duncan Energy Partners.

Generally, the DEP II dropdown transaction documents provide that to the extent that the DEP II Midstream Businesses generate cash sufficient to pay distributions to their partners or members, such cash will be distributed to Enterprise III (a wholly owned subsidiary of Duncan Energy Partners) and Enterprise GTM (our wholly owned subsidiary) in an amount sufficient to generate an aggregate annualized return on their respective investments of 11.85%.  Distributions in excess of this amount will be distributed 98% to Enterprise GTM and 2% to Enterprise III.   The initial annual fixed return amount of 11.85% will be increased by 2% each calendar year beginning January 1, 2010. For example, the fixed return in 2010, assuming no other adjustments, would be 102% of 11.85%, or 12.087%.

Duncan Energy Partners paid a pro rated cash distribution of $0.1115 per unit on the Class B units with respect to the fourth quarter of 2008.

The borrowings of Duncan Energy Partners are presented as part of our consolidated debt; however, we do not have any obligation for the payment of interest or repayment of borrowings incurred by Duncan Energy Partners.

We may contribute other equity interests in our subsidiaries to Duncan Energy Partners and use the proceeds we receive from Duncan Energy Partners to fund our capital spending program.

Omnibus Agreement

On December 8, 2008, we entered into an amended and restated Omnibus Agreement with Duncan Energy Partners.  The key provisions of this agreement are summarized as follows:

§   indemnification for certain environmental liabilities, tax liabilities and right-of-way defects with respect to the DEP I and DEP II Midstream Businesses we contributed to Duncan Energy Partners  in connection with the respective dropdown transactions;

§   funding by EPO of 100% of post-February 5, 2007 capital expenditures incurred by South Texas NGL and Mont Belvieu Caverns with respect to certain expansion projects under construction at the time of Duncan Energy Partners’ initial public offering;

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§   funding by EPO of 100% of post-December 8, 2008 capital expenditures (estimated at $1.4 million) to complete the Sherman Extension natural gas pipeline;

§   a right of first refusal to EPO in our 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 our subsidiaries, other than as consideration in an acquisition or in connection with a loan or debt financing.

We and Duncan Energy Partners have also agreed to negotiate in good faith any necessary amendments to the partnership or company agreements of the DEP II Midstream Businesses when either party believes that business circumstances have changed.

Our general partner’s ACG Committee must approve amendments to the Omnibus Agreement when such amendments would adversely affect our unitholders.

EPO has indemnified Duncan Energy Partners against certain environmental liabilities, tax liabilities and right-of-way defects associated with the assets EPO contributed to Duncan Energy Partners  in connection with the DEP I and DEP II dropdown transactions.  These liabilities include both known and unknown environmental and related liabilities.  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.  In addition, EPO has indemnified Duncan Energy Partners for liabilities related to:

§   certain defects in the easement rights or fee ownership interests in and to the lands on which any assets contributed to Duncan Energy Partners in connection with its initial public offering are located and failure to obtain certain consents and permits necessary to conduct its business that arise through February 5, 2010; and

§   certain income tax liabilities attributable to the operation of the assets contributed to Duncan Energy Partners in connection with its initial public offering prior to February 5, 2007.

The Omnibus Agreement may not be amended without the prior approval of the ACG Committee if the proposed amendment will, in the reasonable discretion of DEP GP, adversely affect holders of its common units.

Neither we, nor EPO and any of its affiliates are restricted under the Omnibus Agreement from competing with Duncan Energy Partners.  Except as otherwise expressly agreed in the ASA, EPO and any of 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 purchase or construct those assets.  These agreements are in addition to other agreements relating to business opportunities and potential conflicts of interest set forth in the ASA with EPO, EPCO and other affiliates of EPCO.

Under the Omnibus Agreement, EPO agreed to make additional contributions to Duncan Energy Partners as reimbursement for Duncan Energy Partners’ 66% share of any excess construction costs above the (i) $28.6 million of estimated capital expenditures to complete Phase II expansions of the DEP South Texas NGL Pipeline System and (ii) $14.1 million of estimated construction costs for additional brine production capacity and above-ground storage reservoir projects at Mont Belvieu, Texas.  Both projects were underway at the time of Duncan Energy Partners’ initial public offering.  EPO made cash contributions to Duncan Energy Partners of $32.5 million in connection with the Omnibus Agreement during the year ended December 31, 2008.  The majority of these contributions related to funding the Phase II expansion costs of the DEP South Texas NGL Pipeline System.  EPO will not receive an increased

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allocation of earnings or cash flows as a result of these contributions to South Texas NGL and Mont Belvieu Caverns.

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.

EPO made cash contributions of $99.5 million under the Caverns LLC Agreement during the year ended December 31, 2008 to fund 100% of certain storage-related projects for the benefit of EPO’s NGL marketing activities.  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 sharing ratio of 66% for Duncan Energy Partners and 34% for EPO.  EPO expects to make additional contributions of approximately $27.5 million to fund such projects in 2009.  The constructed assets will be the property of Mont Belvieu Caverns.

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.

The Caverns LLC Agreement also requires the allocation to EPO of operational measurement gains and losses.  Operational measurement gains and losses are created when product is moved between storage wells and are attributable to pipeline and well connection measurement variances.

Company and Limited Partnership Agreements – DEP II Midstream Businesses

On December 8, 2007, the DEP II Midstream Businesses amended and restated their governing documents in connection with the DEP II dropdown transaction.  Collectively, these amended and restated agreements provide for the following:

§   the acquisition by Enterprise III (a wholly owned subsidiary of Duncan Energy Partners) from Enterprise GTM (our wholly owned subsidiary) of a 66% general partner interest in Enterprise GC, a 51% general partner interest in Enterprise Intrastate and a 51% member interest in Enterprise Texas;

§   the payment of distributions in accordance with an overall “waterfall” approach that stipulates that to the extent that the DEP II Midstream Businesses collectively generate cash sufficient to pay distributions to their partners or members, such cash will be distributed first to Enterprise III (based on an initial defined investment of $730.0 million, the “Enterprise III Distribution Base”) and then to Enterprise GTM (based on an initial defined investment of $452.1 million, the “Enterprise GTM Distribution Base”) in amounts sufficient to generate an aggregate annualized fixed return on their respective investments of 11.85%.  Distributions in excess of these amounts will be distributed 98% to Enterprise GTM and 2.0% to Enterprise III.  The initial annual fixed return amount of 11.85% will be increased by 2.0% each calendar year beginning January 1, 2010. For example, the fixed return in 2010, assuming no other adjustments, would be 102% of 11.85%, or 12.087%;

§   the funding of operating cash flow deficits in accordance with each owner’s respective partner or member interest; and

§   the election by either owner to fund cash calls associated with expansion capital projects.  Since

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December 8, 2008, Enterprise III has elected to not participate in such cash calls and, as a result, Enterprise GTM has funded 100% of the expansion project costs of the DEP II Midstream Businesses.  If Enterprise III later elects to participate in an expansion projects, then Enterprise III will be required to make a capital contribution for its share of the project costs.

Any capital contributions to fund expansion projects made by either Enterprise III or Enterprise GTM will increase such partner’s Distribution Base (and hence future priority return amounts) under the Company Agreement of Enterprise Texas.  As noted, Enterprise III has declined participation in expansion project spending since December 8, 2008. As a result, Enterprise GTM has funded 100% of such growth capital spending and its Distribution Base has increased from $452.1 million at December 8, 2008 to $473.4 million at December 31, 2008.  The Enterprise III Distribution Base was unchanged at $730.0 million at December 31, 2008.

Relationships with Unconsolidated Affiliates

Many of our unconsolidated affiliates perform supporting or complementary roles to our other business operations.  Since we and our affiliates hold ownership interests in these entities and directly or indirectly benefit from our related party transactions with such entities, they are presented here.

The following information summarizes significant related party transactions with our current unconsolidated affiliates:

§   We sell natural gas to Evangeline, which, in turn, uses the natural gas to satisfy supply commitments it has with a major Louisiana utility.  In addition, Duncan Energy Partners furnished $1.0 million in letters of credit on behalf of Evangeline at December 31, 2008.

§   We pay Promix for the transportation, storage and fractionation of NGLs.  In addition, we sell natural gas to Promix for its plant fuel requirements.

§   We pay Centennial in connection with a pipeline capacity lease.  In addition, we pay Centennial for other pipeline transportation services.

§   We paid Seaway for transportation and tank rentals in connection with our crude oil marketing activities.

§   We perform management services for certain of our unconsolidated affiliates.

Relationship with Cenac

In connection with our marine services acquisition in February 2008, Cenac and affiliates became a related party of ours due to its ownership of TEPPCO units through October 26, 2009, which then converted to common units of Enterprise Products Partners, and other considerations.  We entered into a transitional operating agreement with Cenac in which our fleet of acquired tow boats and tank barges will continue to be operated by employees of Cenac for a period of up to two years following the acquisition.  Under this agreement, we pay Cenac a monthly operating fee and reimburse Cenac for personnel salaries and related employee benefit expenses, certain repairs and maintenance expenses and insurance premiums on the equipment.

Note 16.  Provision for Income Taxes

Our provision for income taxes relates primarily to federal and state income taxes of Seminole and Dixie, our two largest corporations subject to such income taxes.  In addition, with the amendment of the Texas Franchise Tax in 2006, we have become a taxable entity in the state of Texas.

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Significant components of deferred tax assets and deferred tax liabilities as of December 31, 2008 are as follows:

Deferred tax assets:
Net operating loss carryovers	$	26.3
Property, plant and equipment		0.8
Employee benefit plans		2.6
Deferred revenue		1.0
Reserve for legal fees and damages		0.3
Equity investment in partnerships		0.6
AROs		0.1
Accruals		0.9
Total deferred tax assets		32.6
Valuation  allowance		3.9
Net deferred tax assets		28.7
Deferred tax liabilities:
Property, plant and equipment		92.9
Other		0.1
Total deferred tax liabilities		93.0
Total net deferred tax liabilities		(64.3	)
Current portion of total net deferred tax assets		1.4
Long-term portion of total net deferred tax liabilities	$	(65.7	)

We had net operating loss carryovers of $26.3 million at December 31, 2008.  These losses expire in various years between 2009 and 2028 and are subject to limitations on their utilization.  We record a valuation allowance to reduce our deferred tax assets to the amount of future tax benefit that is more likely than not to be realized.  The valuation allowance was $3.9 million at December 31, 2008 and serves to reduce the recognized tax benefit associated with carryovers of our corporate entities to an amount that will, more likely than not, be realized.  

We have deferred tax liabilities on property plant and equipment of $92.9 million at December 31, 2008.  The 2008 balance includes $45.1 million related to the difference in book and tax basis of property, plant and equipment resulting from the acquisition of the remaining equity interest of Dixie Pipeline.  See Note 10 for additional information.

On May 18, 2006, the State of Texas enacted House Bill 3 which revised the pre-existing state franchise tax.  In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax, including previously non-taxable entities such as limited liability companies, limited partnerships and limited liability partnerships.  The tax is assessed on Texas sourced taxable margin which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits.

Although the bill states that the Revised Texas Franchise Tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses.  Due to the enactment of the Revised Texas Franchise Tax, we recorded a net deferred tax liability of $0.9 million during the years ended December 31, 2008.

Note 17.  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

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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 its affiliates.  Mr. Brinkerhoff filed an amended complaint on July 12, 2007. The amended complaint names as defendants (i) TEPPCO, its current and certain former directors, and certain of its affiliates; (ii) Enterprise Products Partners and certain of its 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 IDRs in exchange for TEPPCO 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.

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 (“MTBE”).  In general, such suits have not named manufacturers of MTBE as defendants, and there have been no such lawsuits filed against our subsidiary that owns an octane-additive production facility.  It is possible, however, that former MTBE manufacturers such as our subsidiary could ultimately be added as defendants in such lawsuits or in new lawsuits.

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

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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.

In January 2009, the State of New Mexico filed suit in District Court in Santa Fe County, New Mexico, under the New Mexico Air Quality Control Act.  The lawsuit arose out of a February 27, 2008 Notice Of Violation issued to Marathon as operator of the Indian Basin natural gas processing facility located in Eddy County, New Mexico.  We own a 40.0% undivided interest in the assets comprising the Indian Basin facility.  The State alleges violations of its air laws, and Marathon believes there has been no adverse impact to public health or the environment, having implemented voluntary emission reduction measures over the years.  The State seeks penalties above $100,000.  Marathon continues to work with the State to determine if resolution of the case is possible.

Contractual Obligations

The following table summarizes our various contractual obligations at December 31, 2008.  A description of each type of contractual obligation follows.

	Payment or Settlement due by Period
Contractual Obligations	Total		2009		2010		2011		2012		2013		Thereafter
Scheduled maturities of long-term debt	$	11,562.8	$	--	$	554.0	$	934.3	$	2,534.3	$	1,200.0	$	6,340.2
Estimated cash interest payments	$	11,976.0	$	691.5	$	669.5	$	618.1	$	578.9	$	457.6	$	8,960.4
Operating lease obligations	$	388.3	$	44.9	$	38.2	$	37.6	$	36.2	$	30.7	$	200.7
Purchase obligations:
Product purchase commitments:
Estimated payment obligations:
Crude oil	$	161.2	$	161.2	$	--	$	--	$	--	$	--	$	--
Refined products	$	1.6	$	1.6	$	--	$	--	$	--	$	--	$	--
Natural gas	$	5,225.1	$	323.3	$	515.1	$	635.0	$	660.6	$	488.0	$	2,603.1
NGLs	$	1,923.8	$	969.9	$	136.4	$	136.2	$	136.2	$	136.3	$	408.8
Petrochemicals	$	1,746.2	$	685.6	$	376.6	$	247.8	$	181.7	$	86.8	$	167.7
Other	$	66.7	$	24.2	$	7.6	$	7.0	$	6.3	$	6.2	$	15.4
Underlying major volume commitments:
Crude oil (in MBbls)		3,404		3,404		--		--		--		--		--
Refined products (in MBbls)		28		28		--		--		--		--		--
Natural gas (in BBtus)		981,955		56,650		93,150		115,925		120,780		93,950		501,500
NGLs (in MBbls)		56,622		23,576		4,726		4,720		4,720		4,720		14,160
Petrochemicals (in MBbls)		67,696		24,949		13,420		10,428		7,906		3,759		7,234
Service payment commitments	$	534.4	$	57.3	$	51.3	$	49.5	$	47.0	$	46.1	$	283.2
Capital expenditure commitments	$	786.7	$	786.7	$	--	$	--	$	--	$	--	$	--

Scheduled Maturities of Long-Term Debt.  We have long-term and short-term payment obligations under debt agreements.  Amounts shown in the preceding table represent our scheduled future maturities of debt principal for the periods indicated.  See Note 12 for additional information regarding our consolidated debt obligations.

Operating Lease Obligations.  We lease certain property, plant and equipment under noncancelable and cancelable operating leases.  Amounts shown in the preceding table represent minimum cash lease payment obligations under our operating leases with terms in excess of one year.

Our significant lease agreements involve (i) the lease of underground caverns for the storage of natural gas and NGLs, (ii) leased office space with an affiliate of EPCO, (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 2 to 28 years and include renewal options that could extend the agreements for up to an additional 20 years.

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ENTERPRISE PRODUCTS GP, LLC

NOTES TO SUPPLEMENTAL CONSOLIDATED BALANCE SHEET

The operating lease commitments shown in the preceding table exclude the non-cash, related party expense associated with retained leases contributed to Enterprise Products Partners by EPCO at its formation.  EPCO remains liable for the actual cash lease payments associated with these agreements, which it accounts for as operating leases.  At December 31, 2008, the retained leases were for approximately 100 railcars.  EPCO’s minimum future rental payments under these leases are $0.7 million for each of the years 2009 through 2015 and $0.3 million for 2016.  Enterprise Products Partners records the full value of these payments made by EPCO on our behalf as a non-cash related party operating lease expense, with the offset to equity accounted for as a general contribution to the partnership.

The retained lease agreements contain lessee purchase options, which are at prices that approximate fair value of the underlying leased assets.  EPCO has assigned these purchase options to us.    We have exercised our election under the retained leases to purchase a cogeneration unit in December 2008 for $2.3 million.  Should we decide to exercise the purchase option associated with the remaining agreement, we would pay the original lessor $3.1 million in June 2016.

Purchase Obligations. We define a purchase obligation as an agreement to purchase goods or services that is enforceable and legally binding (unconditional) on us that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transactions.  We have classified our unconditional purchase obligations into the following categories:

§   We have long and short-term product purchase obligations for natural gas, NGLs, crude oil, refined products and certain petrochemicals with third-party suppliers.  The prices that we are obligated to pay under these contracts approximate market prices at the time we take delivery of the volumes.  The preceding table shows our volume commitments and estimated payment obligations under these contracts for the periods indicated.  Our estimated future payment obligations are based on the contractual price under each contract for purchases made at December 31, 2008 applied to all future volume commitments.  Actual future payment obligations may vary depending on market prices at the time of delivery.  At December 31, 2008, we do not have any significant product purchase commitments with fixed or minimum pricing provisions with remaining terms in excess of one year.

§   We have long and short-term commitments to pay third-party providers for services such as equipment maintenance agreements.  Our contractual payment obligations vary by contract.  The preceding table shows our future payment obligations under these service contracts.

§   We have short-term payment obligations relating to our capital projects and those of our unconsolidated affiliates.  These commitments represent unconditional payment obligations to vendors for services rendered or products purchased.  The preceding table presents our share of such commitments for the periods indicated.

Commitments under equity compensation plans of EPCO

In accordance with our agreements with EPCO, we reimburse EPCO for our share of its compensation expense associated with certain employees who perform management, administrative and operating functions for us (see Note 15).  This includes costs associated with unit option awards granted to these employees to purchase Enterprise Products Partners’ common units.  At December 31, 2008, there were 2,168,500 and 795,000 unit options outstanding under the EPCO 1998 Plan and EPD 2008 LTIP, respectively, for which we were responsible for reimbursing EPCO for the costs of such awards.

The weighted-average strike price of unit option awards outstanding at December 31, 2008 was $26.32 and $30.93 per common unit under the EPCO 1998 Plan and EPD 2008 LTIP, respectively.  At December 31, 2008, 548,500 of these unit options were exercisable under the EPCO 1998 Plan.  An additional 365,000, 480,000 and 775,000 of these unit options will be exercisable in 2009, 2010 and 2012, respectively under the EPCO 1998 Plan.  The 795,000 unit options outstanding under the EPD 2008 LTIP will become exercisable in 2013.  As these options are exercised, we will reimburse EPCO in the form of a

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ENTERPRISE PRODUCTS GP, LLC

NOTES TO SUPPLEMENTAL CONSOLIDATED BALANCE SHEET

special cash distribution for the difference between the strike price paid by the employee and the actual purchase price paid for the units awarded to the employee.  See Note 4 for additional information regarding our accounting for equity awards.

In order to fund obligations under the TEPPCO 2006 LTIP, EPCO may purchase common units of TEPPCO at fair value either in the open market or directly from TEPPCO.  When EPCO employees exercise options awarded under the TEPPCO 2006 LTIP, TEPPCO will reimburse EPCO for the cash difference between the strike price paid by the employee and the actual purchase price paid by EPCO for the common units.  TEPPCO was committed to issue 355,000 of its common units at December 31, 2008, respectively, if all outstanding options awarded under the 2006 LTIP (as of this date) were exercised.  The weighted-average strike price of option awards outstanding at December 31, 2008 was $40.00 per common unit.   There were no options immediately exercisable under the 2006 LTIP at December 31, 2008.  See Note 4 for additional information regarding the TEPPCO 2006 LTIP.

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 December 31, 2008, claims against us totaled approximately $15.4 million.  These matters are in various stages of assessment and the ultimate outcome of such disputes cannot be reasonably estimated.  However, in our opinion, the likelihood of a material adverse outcome related to disputes against us is remote.  Accordingly, accruals for loss contingencies related to these matters, if any, that might result from the resolution of such disputes have not been reflected in our Supplemental Consolidated Balance Sheet.

Other Commitments

We transport and store natural gas, NGLs, crude oil, refined products and petrochemicals for third parties under various processing, storage, transportation and similar agreements.  These volumes are (i) accrued as product payables on our Supplemental Consolidated Balance Sheet, (ii) in transit for delivery to our customers or (iii) held at our storage facilities for redelivery to our customers.  We are insured against any physical loss of such volumes due to catastrophic events.  Under the terms of our natural gas, NGL and petrochemical storage agreements, we are generally required to redeliver volumes to the owner on demand.  At December 31, 2008, NGL, refined products and petrochemical products aggregating 40.9 million barrels were due to be redelivered to their owners along with 18.5 BBtus of natural gas and 5.2 million barrels of crude oil.  See Note 2 for more information regarding accrued product payables.

Centennial Guarantees

We have certain guarantee obligations in connection with our ownership interest in Centennial.  We have guaranteed one-half of Centennial’s debt obligations, which obligates us to an estimated payment of $65.0 million in the event of default by Centennial.  At December 31, 2008, we had a liability of $9.0 million representing the estimated fair value of our share of the Centennial debt guaranty.  See Note 12 for additional information regarding Centennial’s debt obligations.

In lieu of Centennial procuring insurance to satisfy third-party liabilities arising from a catastrophic event, our and Centennial’s other joint venture partner has entered a limited cash call agreement.  We are obligated to contribute up to a maximum of $50.0 million in proportion to our ownership interest in Centennial in the event of a catastrophic event.  At December 31, 2008, we had a liability of $3.9 million representing the estimated fair value of our cash call guaranty.  We insure against catastrophic events.  Cash contributions to Centennial under the limited cash call agreement may be covered by our insurance depending on the nature of the catastrophic event.

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ENTERPRISE PRODUCTS GP, LLC

NOTES TO SUPPLEMENTAL CONSOLIDATED BALANCE SHEET

Note 18.   Significant Risks and Uncertainties

Nature of Operations in Midstream Energy Industry

Our operations are within the midstream energy industry, which includes gathering, transporting, processing, fractionating and storing natural gas, NGLs, crude oil, refined products and certain petrochemicals.  We also market natural gas, NGLs, crude oil and other hydrocarbon products.  As such, our financial position may be affected by changes in the commodity prices of these hydrocarbon products, including changes in the relative price levels among these products (e.g., natural gas processing margins are influenced by the ratio of natural gas prices to crude oil prices).  The prices of hydrocarbon products are subject to fluctuation in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control.

Our profitability could be impacted by a decline in the volume of hydrocarbon products transported, gathered, processed or stored at our facilities.  A material decrease in natural gas or crude oil production or crude oil refining, for reasons such as depressed commodity prices or a decrease in exploration and development activities, could result in a decline in the volume of natural gas, NGLs, refined products and crude oil handled by our facilities.

A reduction in demand for natural gas, crude oil, NGL and other hydrocarbon products by the petrochemical, refining or heating industries, whether because of (i) general economic conditions, (ii) reduced demand by consumers for the end products made using such products, (iii) increased competition from other products due to pricing differences, (iv) adverse weather conditions, (v) government regulations affecting energy commodity prices, production levels of hydrocarbons or the content of motor gasoline or (vi) other reasons, could adversely affect our financial position.

Credit Risk due to Industry Concentrations

A substantial portion of our revenues are derived from companies in the domestic natural gas, NGL and petrochemical industries.  This concentration could affect our overall exposure to credit risk since these customers may be affected by similar economic or other conditions.  We generally do not require collateral for our accounts receivable; however, we do attempt to negotiate offset, prepayment, or automatic debit agreements with customers that are deemed to be credit risks in order to minimize our potential exposure to any defaults.

On January 6, 2009, LyondellBasell Industries (“LBI”) announced that its U.S. operations had voluntarily filed to reorganize under Chapter 11 of the U.S. Bankruptcy Code.  For 2008, LBI accounted for 5.9% of consolidated revenues.  At the time of the bankruptcy filing, we had approximately $17.3 million of credit exposure to LBI, which was reduced to approximately $10.0 million through remedies provided under certain pipeline tariffs.  In addition, we are seeking to have LBI accept certain contracts and have filed claims pursuant to current Bankruptcy Court Orders that we expect will allow us to recover the majority of the remaining credit exposure.

Counterparty Risk with Respect to Derivative Instruments

In those situations where we are exposed to credit risk in our derivative instrument transactions, we analyze the counterparty’s financial condition prior to entering into an agreement, establish credit and/or margin limits and monitor the appropriateness of these limits on an ongoing basis.  Generally, we do not require collateral nor do we anticipate nonperformance by our counterparties.

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 damage or interruption that might

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ENTERPRISE PRODUCTS GP, LLC

NOTES TO SUPPLEMENTAL CONSOLIDATED BALANCE SHEET

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 us.  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.

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

Hurricane Ivan insurance claims.   During the year ended December 31, 2008, we did not receive any reimbursements from insurance carriers related to property damage claims associated with this storm.  We have submitted business interruption insurance claims for our estimated losses caused by Hurricane Ivan, which struck the eastern U.S. Gulf Coast region in September 2004.  During the year ended December 31, 2008, we did not receive any proceeds from these claims. We are continuing our efforts to collect residual balances from this storm.

Hurricanes Katrina and Rita insurance claims.  Hurricanes Katrina and Rita, both significant storms, affected certain of our Gulf Coast assets in August and September of 2005, respectively.  With respect to these storms, we have $30.5 million of estimated property damage claims outstanding at December 31, 2008, that we believe are probable of collection during the period 2009.  We continue to pursue collection of our property damage claims related to these named storms.  As of December 31, 2008, we had received all proceeds from our business interruption claims related to these storm events.

Hurricanes Gustav and Ike insurance claims.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, which, in turn, caused a decrease in gross operating margin from these operations.  We expect to file property damage insurance claims to the extent repair costs exceed deductible amounts.  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.

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ENTERPRISE PRODUCTS GP, LLC

NOTES TO SUPPLEMENTAL CONSOLIDATED BALANCE SHEET

Proceeds from Business Interruption and Property Damage Claims

The following table summarizes proceeds we received during the year ended December 31, 2008 from business interruption and property damage insurance claims with respect to certain named storms:

Business interruption proceeds:
Hurricane Katrina	$	0.5
Hurricane Rita		0.6
Total proceeds		1.1
Property damage proceeds:
Hurricane Katrina		9.4
Hurricane Rita		2.7
Total proceeds		12.1
Total	$	13.2

At December 31, 2008, we have $39.0 million of estimated property damage claims outstanding related to these storms that we believe are probable of collection through 2009.  In February 2009, we collected $20.8 million of the amounts outstanding.  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.

During 2008, we collected $0.2 million of business interruption proceeds that were not related to storm events.

Note 19.  Subsequent Events

We have evaluated subsequent events through December 18, 2009, which is the date we filed this Exhibit 99.1 to Current Report on Form 8-K with the SEC.

TOPS Matters - April and September 2009

In April 2009, we dissociated (or exited) from TOPS (see Note 8).  As a result, we recorded a non-cash charge of $68.4 million, which represented our cumulative investment in TOPS through the date of dissociation.  In addition, in September 2009, we entered into a settlement agreement with certain affiliates of Oiltanking that resolved all disputes between the parties related to the business and affairs of TOPS. We recorded a charge of $67.0 million during the third quarter of 2009 in connection with this cash settlement.

River Terminal Charges in September 2009

In September 2009, TEPPCO determined that its Aberdeen and Boligee river terminals were impaired due to the current level of throughput volumes at the terminals and the indefinite suspension of construction projects for three new proposed river terminals.  As a result, TEPPCO recorded a $17.6 million non-cash asset impairment charge during the third quarter of 2009.  The assets and operations related to TEPPCO’s river terminals are part of our Petrochemical & Refined Products Services business segment.

Also, TEPPCO is party to a 10-year throughput and deficiency agreement with Colonial Pipeline Company (“Colonial”) whereby Colonial agreed to provide transportation services to TEPPCO’s Boligee river terminal.  The agreement provided for minimum annual throughput commitments.   As a result of TEPPCO’s decision to indefinitely suspend the three new proposed river terminal construction projects, TEPPCO accrued a liability of $28.7 million for deficiency fees that it reasonably estimated would be incurred over the term of the Colonial contract since the minimum throughput volumes were no longer expected to be achieved.

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EX-99.2

EXHIBIT 99.2

ENTERPRISE PRODUCTS GP, LLC

RECAST OF EXHIBIT 99.1 FROM CURRENT REPORT

ON FORM 8-K DATED NOVEMBER, 16, 2009

TABLE OF CONTENTS

Unaudited Supplemental Condensed Consolidated Balance Sheet at September 30, 2009	2
Notes to Unaudited Supplemental Condensed Consolidated Balance Sheet:
1.  Company Organization and Basis of Presentation	3
2.  General Accounting Matters	5
3.  Accounting for Equity Awards	7
4.  Derivative Instruments, Hedging Activities and Fair Value Measurements	11
5.  Inventories	18
6.  Property, Plant and Equipment	19
7.  Investments in Unconsolidated Affiliates	20
8.  Business Combinations	20
9.  Intangible Assets and Goodwill	21
10.  Debt Obligations	22
11.  Equity	25
12.  Business Segments	26
13.  Related Party Transactions	26
14.  Commitments and Contingencies	29
15.  Significant Risks and Uncertainties	33
16.  Subsequent Events	34

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ENTERPRISE PRODUCTS GP, LLC

UNAUDITED SUPPLEMENTAL CONDENSED CONSOLIDATED BALANCE SHEET

AT SEPTEMBER 30, 2009

(Dollars in millions)

ASSETS
Current assets:
Cash and cash equivalents	$	77.4
Restricted cash		102.8
Accounts and notes receivable – trade, net of allowance for doubtful accounts  of $17.0		2,579.6
Accounts receivable – related parties		9.6
Inventories (see Note 5)		1,220.6
Derivative assets (see Note 4)		199.5
Prepaid and other current assets		168.0
Total current assets		4,357.5
Property, plant and equipment, net		17,297.0
Investments in unconsolidated affiliates		899.3
Intangible assets, net of accumulated amortization of $765.6		1,093.2
Goodwill		2,018.3
Deferred tax asset		1.1
Other assets		264.9
Total assets	$	25,931.3
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable – trade	$	399.7
Accounts payable – related parties		44.2
Accrued product payables		2,657.4
Accrued interest payable		163.1
Other accrued expenses		55.1
Derivative liabilities (see Note 4)		264.6
Other current liabilities		263.5
Total current liabilities		3,847.6
Long-term debt: (see Note 10)
Senior debt obligations – principal		10,404.0
Junior subordinated notes – principal		1,532.7
Other		62.5
Total long-term debt		11,999.2
Deferred tax liabilities		69.6
Other long-term liabilities		151.2
Commitments and contingencies
Equity: (see Note 11)
Member’s interest		540.0
Accumulated other comprehensive loss		(1.4	)
Total member’s equity		538.6
Noncontrolling interest		9,325.1
Total equity		9,863.7
Total liabilities and equity	$	25,931.3

See Notes to Unaudited Supplemental Condensed Consolidated Balance Sheet.

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ENTERPRISE PRODUCTS GP, LLC

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED BALANCE SHEET

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

Note 1.  Company Organization and Basis of Presentation

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, 2009, 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, which now includes TEPPCO Partners, L.P. and its general partner.  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” and “TEPPCO GP” mean TEPPCO Partners, L.P. and Texas Eastern Products Pipeline Company, LLC (which is the general partner of TEPPCO), respectively, prior to their mergers with subsidiaries of Enterprise Products Partners.  On October 26, 2009, Enterprise Products Partners completed its mergers with TEPPCO and TEPPCO GP (such related mergers referred to herein individually and together as the “TEPPCO Merger”).  See Note 16 for additional information regarding the TEPPCO Merger.

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.  Enterprise GP Holdings owns noncontrolling 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 II, L.P., EPE Unit III, L.P., Enterprise Unit L.P., EPCO Unit L.P., TEPPCO Unit L.P., and TEPPCO Unit II L.P., collectively, all of which are privately held affiliates of EPCO, Inc.

References to “EPCO” mean EPCO, Inc. and its wholly-owned privately held 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.

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ENTERPRISE PRODUCTS GP, LLC

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED BALANCE SHEET

For financial reporting purposes, Enterprise Products Partners consolidates the balance sheet of Duncan Energy Partners L.P. (“Duncan Energy Partners”) with that of its own.  Enterprise Products Partners controls Duncan Energy Partners through the ownership of its general partner, DEP Holdings, LLC (“DEP GP”).  Public ownership of Duncan Energy Partners’ net assets is presented as a component of noncontrolling interest in our Unaudited Supplemental Condensed Consolidated Balance Sheet.  The borrowings of Duncan Energy Partners are presented as part of our consolidated debt; however, neither Enterprise Products Partners nor EPGP have any obligation for the payment of interest or repayment of borrowings incurred by Duncan Energy Partners.

Basis of Presentation

General.  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 noncontrolling 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 capital account in Enterprise Products Partners.

Noncontrolling Interests.  Effective January 1, 2009, we adopted new accounting guidance that has been codified under Accounting Standards Codification (“ASC”) 810, Consolidation, which established accounting and reporting standards for noncontrolling interests, which were previously identified as minority interest in our Unaudited Condensed Consolidated Balance Sheet.  The new guidance requires, among other things, that noncontrolling interests be presented as a component of equity on our Unaudited Condensed Consolidated Balance Sheet (i.e., elimination of the “mezzanine” presentation previously used for minority interest).

The Unaudited Supplemental Condensed Consolidated Balance Sheet included in this Exhibit 99.2 reflects the changes required under ASC 810.  This Unaudited Supplemental Condensed Consolidated Balance Sheet and Notes thereto should be read in conjunction with the Audited Supplemental Consolidated Balance Sheet and Notes thereto included in Exhibit 99.1 of this Current Report on Form 8-K.

TEPPCO Merger.  Since Enterprise Products Partners, TEPPCO and TEPPCO GP are under common control of Mr. Duncan, the TEPPCO Merger was accounted for at historical costs as a reorganization of entities under common control in a manner similar to a pooling of interests.  The inclusion of TEPPCO and TEPPCO GP in our Unaudited Supplemental Condensed Consolidated Balance Sheet was effective January 1, 2005 because an affiliate of EPCO under common control with Enterprise Products Partners originally acquired ownership interests in TEPPCO GP in February 2005.

Our Unaudited Supplemental Condensed Consolidated Balance Sheetprior to the TEPPCO Merger reflects the combined financial information of Enterprise Products Partners, TEPPCO and TEPPCO GP on a 100% basis.  Third party and related party ownership interests in TEPPCO and TEPPCO GP prior to the merger have been reflected as “Former owners of TEPPCO” a component of noncontrolling interest.

Our Unaudited Supplemental Condensed Consolidated Balance Sheet has been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”).  The balance sheets of TEPPCO and TEPPCO GP were prepared from the separate accounting records maintained by TEPPCO and TEPPCO GP.  All intercompany balances and transactions were eliminated in consolidation.

We revised our business segments and related disclosures to reflect the TEPPCO Merger.  Our reorganized business segments reflect the manner in which these businesses are managed and reviewed by the chief executive officer of EPGP.  Under our new business segment structure, we have five reportable business segments:  (i) NGL Pipelines & Services; (ii) Onshore Natural Gas Pipelines & Services; (iii)

4

ENTERPRISE PRODUCTS GP, LLC

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED BALANCE SHEET

Onshore Crude Oil Pipelines & Services; (iv) Offshore Pipelines & Services; and (v) Petrochemical & Refined Products Services.

Note 2.  General Accounting Matters

Estimates

Preparing our supplemental balance sheet in conformity with GAAP requires management to make estimates and assumptions that affect amounts presented in the supplemental balance sheet (e.g. assets and liabilities) 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.

Fair Value Information

Cash and cash equivalents and restricted cash, accounts receivable, accounts payable and accrued expenses, and other current liabilities are carried at amounts which reasonably approximate their fair values due to their short-term nature.  The estimated fair values of our fixed rate debt are based on quoted market prices for such debt or debt of similar terms and maturities.  The carrying amounts of our variable rate debt obligations reasonably approximate their fair values due to their variable interest rates.  See Note 4 for fair value information associated with our derivative instruments.  The following table presents the estimated fair values of our financial instruments at September 30, 2009:

	Carrying		Fair
Financial Instruments	Value		Value
Financial assets:
Cash and cash equivalents and restricted cash	$	180.2	$	180.2
Accounts receivable		2,589.2		2,589.2
Financial liabilities:
Accounts payable and accrued expenses		3,319.5		3,319.5
Other current liabilities		263.5		263.5
Fixed-rate debt (principal amount)		9,986.7		10,450.6
Variable-rate debt		1,950.0		1,950.0

Recent Accounting Developments

The following information summarizes recently issued accounting guidance that will or may affect our future balance sheets.

Generally Accepted Accounting Principles.  In June 2009, the FASB published ASC 105, Generally Accepted Accounting Principles, as the source of authoritative GAAP for U.S. companies.  The ASC reorganized GAAP into a topical format and significantly changes the way users research accounting issues.  For SEC registrants, the rules and interpretive releases of the SEC under federal securities laws are also sources of authoritative GAAP.  References to specific GAAP now refer exclusively to the ASC.  We adopted the new codification on September 30, 2009.

Fair Value Measurements.  In April 2009, the FASB issued ASC 820, Fair Value Measurements and Disclosures, to clarify fair value accounting rules.  This new accounting guidance establishes a process to determine whether a market is active and a transaction is consummated under distress.  Companies should review several factors and use professional judgment to ascertain if a formerly active market has become inactive.  When estimating fair value, companies are required to place more weight on observable transactions in orderly markets.  Our adoption of this new guidance on June 30, 2009 did not have any impact on our supplemental consolidated balance sheet or related disclosures.

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ENTERPRISE PRODUCTS GP, LLC

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED BALANCE SHEET

In August 2009, the FASB issued Accounting Standards Update 2009-05, Measuring Liabilities at Fair Value, to clarify how an entity should estimate the fair value of liabilities.  If a quoted price in an active market for an identical liability is not available, a company must measure the fair value of the liability using one of several valuation techniques (e.g., quoted prices for similar liabilities or present value of cash flows).  Our adoption of this new guidance on October 1, 2009 did not have any impact on our supplemental consolidated balance sheet or related disclosures.

Financial Instruments.  In April 2009, the FASB issued ASC 825, Financial Instruments, which requires companies to provide in each interim report both qualitative and quantitative information regarding fair value estimates for financial instruments not recorded on the balance sheet at fair value.  Previously, this was only an annual requirement.  Apart from adding the required fair value disclosures within this Note 2, our adoption of this new guidance on June 30, 2009 did not have a material impact on our supplemental consolidated balance sheet or related disclosures.

Subsequent Events.  In May 2009, the FASB issued ASC 855, Subsequent Events, which governs the accounting for, and disclosure of, events that occur after the balance sheet date but before financial statements are issued or are available to be issued.  The date through which an entity has evaluated subsequent events is now a required disclosure.  Our adoption of this guidance on June 30, 2009 did not have any impact on our supplemental consolidated balance sheet.

Consolidation of Variable Interest Entities.  In June 2009, the FASB amended consolidation guidance for variable interest entities (“VIEs”) under ASC 810.  VIEs are entities whose equity investors do not have sufficient equity capital at risk such that the entity cannot finance its own activities.  When a business has a “controlling financial interest” in a VIE, the assets, liabilities and profit or loss of that entity must be consolidated.  A business must also consolidate a VIE when that business has a “variable interest” that (i) provides the business with the power to direct the activities that most significantly impact the economic performance of the VIE and (ii) funds most of the entity’s expected losses and/or receives most of the entity’s anticipated residual returns.  The amended guidance:

§   eliminates the scope exception for qualifying special-purpose entities;

§   amends certain guidance for determining whether an entity is a VIE;

§   expands the list of events that trigger reconsideration of whether an entity is a VIE;

§   requires a qualitative rather than a quantitative analysis to determine the primary beneficiary of a VIE;

§   requires continuous assessments of whether a company is the primary beneficiary of a VIE; and

§   requires enhanced disclosures about a company’s involvement with a VIE.

The amended guidance is effective for us on January 1, 2010.  At September 30, 2009, we did not have any VIEs based on prior guidance.  We are in the process of evaluating the amended guidance; however, our adoption and implementation of this guidance is not expected to have an impact on our consolidated balance sheet.

Restricted Cash

Restricted cash represents amounts held in connection with our commodity derivative instruments portfolio and related physical natural gas and NGL purchases.  Additional cash may be restricted to maintain this portfolio as commodity prices fluctuate or deposit requirements change.  At September 30, 2009, our restricted cash amounts were $102.8 million.  See Note 4 for additional information regarding derivative instruments and hedging activities.

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ENTERPRISE PRODUCTS GP, LLC

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CONDENSED CONSOLIDATED BALANCE SHEET

Subsequent Events

We have evaluated subsequent events through December 18, 2009, which is the date of we filed this Exhibit 99.2 to Current Report on Form 8-K.

Note 3.  Accounting for Equity Awards

Certain key employees of EPCO participate in long-term incentive compensation plans managed by EPCO.  We record our pro rata share of such costs based on the percentage of time each employee spends on our consolidated business activities.  Such awards were not material to our consolidated financial position.

EPCO 1998 Long-Term Incentive Plan

The EPCO 1998 Long-Term Incentive Plan (“EPCO 1998 Plan”) provides for the issuance of up to 7,000,000 of Enterprise Products Partners’ common units.  After giving effect to the issuance or forfeiture of option awards and restricted unit awards through September 30, 2009, a total of 428,847 additional common units could be issued under the EPCO 1998 Plan.

Unit Option Awards.  The following table presents option activity under the EPCO 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, 2008		2,168,500		$	26.32
Granted (2)		30,000		$	20.08
Exercised		(56,000	)	$	15.66
Forfeited		(365,000	)	$	26.38
Outstanding at September 30, 2009		1,777,500		$	26.54		4.6	$	3.0
Options exercisable at
September 30, 2009		652,500		$	23.71		4.7	$	3.0
(1)   Aggregate intrinsic value reflects fully vested unit options at September 30, 2009. (2)   Aggregate grant date fair value of these unit options issued during 2009 was $0.2 million based on the following assumptions: (i) a grant date market price of Enterprise Products Partners’ common units of $20.08 per unit; (ii) expected life of options of 5.0 years; (iii) risk-free interest rate of 1.81%; (iv) expected distribution yield on Enterprise Products Partners’ common units of 10%; and (v) expected unit price volatility on Enterprise Products Partners’ common units of 72.76%.

The total intrinsic value of option awards exercised during the three months ended September 30, 2009 was $0.3 million.  For the nine months ended September 30, 2009, the total intrinsic value of option awards exercised was $0.6 million.

During the nine months ended September 30, 2009, we received cash of $0.5 million, from the exercise of option awards granted under the EPCO 1998 Plan.  Conversely, our option-related reimbursements to EPCO during this period were $0.5 million.

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ENTERPRISE PRODUCTS GP, LLC

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CONDENSED CONSOLIDATED BALANCE SHEET

Restricted Unit Awards.  The following table summarizes information regarding our restricted unit awards under the EPCO 1998 Plan for the periods indicated:

				Weighted-
				Average Grant
	Number of			Date Fair Value
	Units			per Unit (1)
Restricted units at December 31, 2008		2,080,600
Granted (2)		1,016,950		$	20.65
Vested		(244,300	)	$	26.66
Forfeited		(194,400	)	$	28.92
Restricted units at September 30, 2009		2,658,850
(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)   Net of forfeitures, aggregate grant date fair value of restricted unit awards issued during 2009 was $21.0 million based on grant date market prices of Enterprise Products Partners’ common units ranging from $20.08 to $27.66 per unit. Estimated forfeiture rates ranged between 4.6% and 17%.

The total fair value of restricted unit awards that vested during the three and nine months ended September 30, 2009 was $6.2 million and $6.5 million, respectively.

Phantom Unit Awards and Distribution Equivalent Rights.  No phantom unit awards or distribution equivalent rights have been issued as of September 30, 2009 under the EPCO 1998 Plan.

Enterprise Products 2008 Long-Term Incentive Plan

The Enterprise Products 2008 Long-Term Incentive Plan (“EPD 2008 LTIP”) provides for the issuance of up to 10,000,000 of Enterprise Products Partners’ common units.  After giving effect to the issuance or forfeiture of option awards through September 30, 2009, a total of 7,865,000 additional common units could be issued under the EPD 2008 LTIP.

Unit Option Awards.  The following table presents unit option activity under the EPD 2008 LTIP for the periods indicated:

						Weighted-
				Weighted-		Average
				Average		Remaining
	Number of			Strike Price		Contractual
	Units			(dollars/unit)		Term (in years)
Outstanding at December 31, 2008		795,000		$	30.93
Granted (1)		1,430,000		$	23.53
Forfeited		(90,000	)	$	30.93
Outstanding at September 30, 2009 (2)		2,135,000		$	25.97		4.9
(1)   Net of forfeitures, aggregate grant date fair value of these unit options issued during 2009 was $6.5 million based on the following assumptions: (i) a weighted-average grant date market price of Enterprise Products Partners’ common units of $23.53 per unit; (ii) weighted-average expected life of options of 4.9 years; (iii) weighted-average risk-free interest rate of 2.14%; (iv) expected weighted-average distribution yield on Enterprise Products Partners’ common units of 9.37%; (v) expected weighted-average unit price volatility on Enterprise Products Partners’ common units of 57.11%. An estimated forfeiture rate of 17% was applied to awards granted during 2009. (2)   No unit options were exercisable as of September 30, 2009.

Phantom Unit Awards.  There were a total of 10,600 phantom units outstanding at September 30, 2009 under the EPD 2008 LTIP.  These awards cliff vest in 2011 and 2012.  At September 30, 2009, we had accrued an immaterial liability for compensation related to these phantom unit awards.

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ENTERPRISE PRODUCTS GP, LLC

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CONDENSED CONSOLIDATED BALANCE SHEET

DEP GP Unit Appreciation Rights

At September 30, 2009, we had a total of 90,000 outstanding unit appreciation rights (“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.  At September 30, 2009, we had accrued an immaterial liability for compensation related to these UARs.

TEPPCO 1999 Phantom Unit Retention Plan

There were a total of 2,800 phantom units outstanding under the TEPPCO 1999 Phantom Unit Retention Plan (“TEPPCO 1999 Plan”) at September 30, 2009, which cliff vest in January 2010.  During the first quarter of 2009, 2,800 phantom units that were outstanding at December 31, 2008 under the TEPPCO 1999 Plan were forfeited.  Additionally, in April 2009, 13,000 phantom units vested, resulting in a cash payment of $0.3 million.  At September 30, 2009, TEPPCO had accrued a liability balance of $0.1 million, for compensation related to the TEPPCO 1999 Plan.

Effective upon the consummation of the TEPPCO Merger (see Note 16), we assumed the unvested phantom units outstanding on October 26, 2009 under the TEPPCO 1999 Plan and, based on the TEPPCO Merger exchange ratio, converted them into an equivalent number of Enterprise Products Partners’ phantom units.  The vesting terms and other provisions remain unchanged.

TEPPCO 2000 Long-Term Incentive Plan

On December 31, 2008, 11,300 phantom units vested and $0.2 million was paid out to participants in the first quarter of 2009.  There are no remaining phantom units outstanding under the TEPPCO 2000 Long-Term Incentive Plan.

TEPPCO 2005 Phantom Unit Plan

On December 31, 2008, 36,600 phantom units vested and $0.6 million was paid out to participants in the first quarter of 2009. There are no remaining phantom units outstanding under the TEPPCO 2005 Phantom Unit Plan.

EPCO 2006 TPP Long-Term Incentive Plan

The EPCO 2006 TPP Long-Term Incentive Plan (“TEPPCO 2006 LTIP”) provides for the issuance of up to 5,000,000 of TEPPCO’s units.  After giving effect to the issuance or forfeiture of unit options and restricted units through September 30, 2009, a total of 4,268,546 additional units of TEPPCO could be issued under the TEPPCO 2006 LTIP.  However, after giving effect to the TEPPCO Merger, no additional units will be issued under the TEPPCO 2006 LTIP other than our common units pursuant to awards we assumed under this plan in accordance with the TEPPCO Merger agreements.

Effective upon the consummation of the TEPPCO Merger (see Note 16), we assumed the unvested awards outstanding on October 26, 2009 under the TEPPCO 2006 LTIP and, based on the TEPPCO Merger exchange ratio, converted them into an equivalent number of Enterprise Products Partners’ awards except for UARs and phantom unit awards held by non-employee directors of TEPPCO GP which were settled in cash.  The vesting terms and other provisions remain unchanged.

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ENTERPRISE PRODUCTS GP, LLC

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED BALANCE SHEET

TEPPCO Unit Options.  The following table presents unit option activity under the TEPPCO 2006 LTIP for the periods indicated:

						Weighted-
				Weighted-		Average
				Average		Remaining
	Number			Strike Price		Contractual
	of Units			(dollars/unit)		Term (in years)
Outstanding at December 31, 2008		355,000		$	40.00
Granted (1)		329,000		$	24.84
Forfeited		(205,000	)	$	33.45
Outstanding at September 30, 2009 (2)		479,000		$	32.39		4.5
(1)   Net of forfeitures, aggregate grant date fair value of these awards granted during 2009 was $1.4 million based on the following assumptions: (i) weighted-average expected life of the options of 4.8 years; (ii) weighted-average risk-free interest rate of 2.1%; (iii) weighted-average expected distribution yield on TEPPCO’s units of 11.3% and (iv) weighted-average expected unit price volatility on TEPPCO’s units of 59.3%. An estimated forfeiture rate of 17% was applied to awards granted during 2009. (2)   No unit options were exercisable as of September 30, 2009.

TEPPCO Restricted Units. The following table summarizes information regarding TEPPCO’s restricted unit awards under the TEPPCO 2006 LTIP for the periods indicated:

				Weighted-
				Average Grant
	Number of			Date Fair Value
	Units			per Unit (1)
Restricted units at December 31, 2008		157,300
Granted (2)		141,950		$	23.98
Vested		(5,000	)	$	34.63
Forfeited		(45,850	)	$	35.25
Restricted units at September 30, 2009		248,400
(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 awards is determined before an allowance for forfeitures. (2)   Net of forfeitures, aggregate grant date fair value of restricted unit awards issued during 2009 was $3.4 million based on grant date market prices of TEPPCO’s units ranging from $28.81 to $34.40 per unit. An estimated forfeiture rate of 17% was applied to awards granted during 2009.

The total fair value of TEPPCO’s restricted unit awards that vested during the nine months ended September 30, 2009 was $0.1 million.

TEPPCO UARs and Phantom Units.  At September 30, 2009, there were a total of 95,654 UARs outstanding that had been granted under the TEPPCO 2006 LTIP to non-employee directors of TEPPCO GP and 265,160 UARs outstanding that were granted to certain employees of EPCO who work on behalf of TEPPCO.  These UAR awards to employees are subject to five year cliff vesting.  If the employee resigns prior to vesting, their UAR awards are forfeited.  The UAR awards held by non-employee directors of TEPPGO GP were settled in cash on the effective date of the TEPPCO Merger.

As of September 30, 2009, there were a total of 1,647 phantom unit awards outstanding that had been granted under the TEPPCO 2006 LTIP to non-employee directors of TEPPCO GP.  The phantom unit awards were settled in cash on the effective date of the TEPPCO Merger.

Employee Partnerships

On October 26, 2009, TEPPCO Unit was dissolved and its assets distributed to its partners.  Also on October 26, 2009, the 123,185 TEPPCO units held by TEPPCO Unit II were exchanged for 152,749 of

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ENTERPRISE PRODUCTS GP, LLC

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CONDENSED CONSOLIDATED BALANCE SHEET

Enterprise Products Partners’ common units in connection with the TEPPCO Merger.  See Note 16 for additional information regarding the TEPPCO Merger.

Note 4.  Derivative Instruments, Hedging Activities and Fair Value Measurements

In the course of our normal business operations, we are exposed to certain risks, including changes in interest rates, commodity prices and, to a limited extent, foreign exchange rates.  In order to manage risks associated with certain identifiable and anticipated transactions, we use derivative instruments.  Derivatives are financial instruments whose fair value is determined by changes in a specified benchmark such as interest rates, commodity prices or currency values.  Typical derivative instruments include futures, forward contracts, swaps and other instruments with similar characteristics.  Substantially all of our derivatives are used for non-trading activities.

We are required to recognize derivative instruments at fair value as either assets or liabilities on the balance sheet.  While all derivatives are required to be reported at fair value on the balance sheet, changes in fair value of the derivative instruments will be reported in different ways depending on the nature and effectiveness of the hedging activities to which they are related.  After meeting specified conditions, a qualified derivative may be specifically designated as a total or partial hedge of:

§   Changes in the fair value of a recognized asset or liability, or an unrecognized firm commitment.

§   Variable cash flows of a forecasted transaction.

§   Foreign currency exposure, such as through an unrecognized firm commitment.

An effective hedge is one in which the change in fair value of a derivative instrument can be expected to offset 80% to 125% of changes in the fair value of a hedged item at inception and throughout the life of the hedging relationship.  The effective portion of a hedge is the amount by which the derivative instrument exactly offsets the change in fair value of the hedged item during the reporting period.  Conversely, ineffectiveness represents the change in the fair value of the derivative instrument that does not exactly offset the change in the fair value of the hedged item.  Any ineffectiveness associated with a hedge is recognized in earnings immediately.  Ineffectiveness can be caused by, among other things, changes in the timing of forecasted transactions or a mismatch of terms between the derivative instrument and the hedged item.

Interest Rate Derivative Instruments

We utilize interest rate swaps, treasury locks and similar derivative instruments to manage our exposure to changes in the interest rates of certain consolidated debt agreements.  This strategy is a component in controlling our cost of capital associated with such borrowings.

The following table summarizes our interest rate derivative instruments outstanding at September 30, 2009, all of which weredesignated as hedging instruments under ASC 815-20, Hedging - General:

	Number and Type of	Notional		Period of	Rate	Accounting
Hedged Transaction	Derivative Employed	Amount		Hedge	Swap	Treatment
Enterprise Products Partners:
Senior Notes C	1 fixed-to-floating swap	$	100.0	1/04 to 2/13	6.4% to 2.8%	Fair value hedge
Senior Notes G	3 fixed-to-floating swaps	$	300.0	10/04 to 10/14	5.6% to 2.6%	Fair value hedge
Senior Notes P	7 fixed-to-floating swaps	$	400.0	6/09 to 8/12	4.6% to 2.7%	Fair value hedge
Duncan Energy Partners:
Variable-interest rate borrowings	3 floating-to-fixed swaps	$	175.0	9/07 to 9/10	0.3% to 4.6%	Cash flow hedge

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ENTERPRISE PRODUCTS GP, LLC

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CONDENSED CONSOLIDATED BALANCE SHEET

At times, we may use treasury lock derivative instruments to hedge the underlying U.S. treasury rates related to forecasted issuances of debt.

During the nine months ended September 30, 2009, we entered into three forward starting interest rate swaps to hedge the underlying benchmark interest payments related to the forecasted issuances of debt.

	Number and Type of	Notional		Period of	Average Rate	Accounting
Hedged Transaction	Derivative Employed	Amount		Hedge	Locked	Treatment
Future debt offering	1 forward starting swap	$	50.0	6/10 to 6/20	3.3%	Cash flow hedge
Future debt offering	2 forward starting swaps	$	200.0	2/11 to 2/21	3.6%	Cash flow hedge

The fair market value of the forward starting swaps was $8.1 million at September 30, 2009.  We entered into one additional forward starting swap for $50.0 million in October 2009 to hedge the February 2011 to February 2021 future debt offering.

For information regarding consolidated fair value amounts of interest rate derivative instruments and related hedged items, see “Tabular Presentation of Fair Value Amounts on Derivative Instruments and Related Hedged Items” within this Note 4.

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ENTERPRISE PRODUCTS GP, LLC

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CONDENSED CONSOLIDATED BALANCE SHEET

Commodity Derivative Instruments

The prices of natural gas, NGLs and certain petrochemical products are subject to fluctuations in response to changes in supply, demand, general market uncertainty and a variety of additional factors that are beyond our control. In order to manage the price risk associated with such products, we enter into commodity derivative instruments such as forwards, basis swaps and futures contracts.  The following table summarizes our commodity derivative instruments outstanding at September 30, 2009:

	Volume (1)		Accounting
Derivative Purpose	Current	Long-Term (2)	Treatment
Derivatives designated as hedging instruments:
Enterprise Products Partners:
Natural gas processing:
Forecasted natural gas purchases for plant thermal reduction (“PTR”) (3)	16.6 Bcf	n/a	Cash flow hedge
Forecasted NGL sales	1.0 MMBbls	n/a	Cash flow hedge
Octane enhancement:
Forecasted purchases of NGLs	0.1 MMBbls	n/a	Cash flow hedge
Forecasted sales of NGLs	n/a	0.1 MMBbls	Cash flow hedge
Forecasted sales of octane enhancement products	1.0 MMBbls	n/a	Cash flow hedge
Natural gas marketing:
Natural gas storage inventory management activities	7.2 Bcf	n/a	Fair value hedge
Forecasted purchases of natural gas	n/a	3.0 Bcf	Cash flow hedge
Forecasted sales of natural gas	4.2 Bcf	0.9 Bcf	Cash flow hedge
NGL marketing:
Forecasted purchases of NGLs and related hydrocarbon products	2.7 MMBbls	0.1 MMBbls	Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products	7.0 MMBbls	0.4 MMBbls	Cash flow hedge
Derivatives not designated as hedging instruments:
Enterprise Products Partners:
Natural gas risk management activities (4) (5)	313.3 Bcf	34.4 Bcf	Mark-to-market
Crude oil risk management activities (6)	4.7 MMBbls	n/a	Mark-to-market
Duncan Energy Partners:
Natural gas risk management activities (5)	1.7 Bcf	n/a	Mark-to-market
(1)   Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes. (2)   The maximum term for derivatives included in the long-term column is December 2012. (3)   PTR represents the British thermal unit equivalent of the NGLs extracted from natural gas by a processing plant, and includes the natural gas used as plant fuel to extract those liquids, plant flare and other shortages.  See the discussion below for the primary objective of this strategy. (4)   Volume includes approximately 61.8 billion cubic feet (“Bcf”) of physical derivative instruments that are predominantly priced as an index plus a premium or minus a discount. (5)   Reflects the use of derivative instruments to manage risks associated with natural gas transportation, processing and storage assets. (6)   Reflects the use of derivative instruments to manage risks associated with our portfolio of crude oil storage assets.

The table above does not include additional hedges of forecasted NGL sales executed under contracts that have been designated as normal purchase and sale agreements.   At September 30, 2009, the volume hedged under these contracts was 4.6 million barrels (“MMBbls”).

Certain of our derivative instruments do not meet hedge accounting requirements; therefore, they are accounted for as economic hedges using mark-to-market accounting.

Our three predominant hedging strategies are hedging natural gas processing margins, hedging anticipated future sales of NGLs associated with volumes held in inventory and hedging the fair value of natural gas in inventory.

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ENTERPRISE PRODUCTS GP, LLC

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED BALANCE SHEET

The objective of our natural gas processing strategy is to hedge a level of gross margins associated with the NGL forward sales contracts (i.e., NGL sales revenues less actual costs for PTR and the gain or loss on the PTR hedge) by locking in the cost of natural gas used for PTR through the use of commodity derivative instruments.  This program consists of:

§   the forward sale of a portion of our expected equity NGL production at fixed prices through December 2009, and

§   the purchase, using commodity derivative instruments, of the amount of natural gas expected to be consumed as PTR in the production of such equity NGL production.

The objective of our NGL sales hedging program is to hedge future sales of NGL inventory by locking in the sales price through the use of commodity derivative instruments.

The objective of our natural gas inventory hedging program is to hedge the fair value of natural gas currently held in inventory by locking in the sales price of the inventory through the use of commodity derivative instruments.

For information regarding consolidated fair value amounts of commodity derivative instruments and related hedged items, see “Tabular Presentation of Fair Value Amounts on Derivative Instruments and Related Hedged Items” within this Note 4.

Foreign Currency Derivative Instruments

We are exposed to foreign currency exchange risk in connection with our NGL and natural gas marketing activities in Canada.  As a result, we could be adversely affected by fluctuations in currency rates between the U.S. dollar and Canadian dollar.  In order to manage this risk, we may enter into foreign exchange purchase contracts to lock in the exchange rate.  Prior to 2009, these derivative instruments were accounted for using mark-to-market accounting.  Beginning with the first quarter of 2009, the long-term transactions (more than two months) are accounted for as cash flow hedges.  Shorter term transactions are accounted for using mark-to-market accounting.

In addition, we were exposed to foreign currency exchange risk in connection with a term loan denominated in Japanese yen (see Note 10).  We entered into this loan agreement in November 2008 and the loan matured in March 2009.  The derivative instrument used to hedge this risk was accounted for as a cash flow hedge and settled upon repayment of the loan.

At September 30, 2009, we had foreign currency derivative instruments outstanding with a notional amount of $5.5 million Canadian.  The fair market value of these instruments was an asset of $0.3 million at September 30, 2009.

For information regarding consolidated fair value amounts of foreign currency derivative instruments and related hedged items, see “Tabular Presentation of Fair Value Amounts on Derivative Instruments and Related Hedged Items” within this Note 4.

Credit-Risk Related Contingent Features in Derivative Instruments

                      A limited number of our commodity derivative instruments include provisions related to credit ratings and/or adequate assurance clauses.  A credit rating provision provides for a counterparty to demand immediate full or partial payment to cover a net liability position upon the loss of a stipulated credit rating. An adequate assurance clause provides for a counterparty to demand immediate full or partial payment to cover a net liability position should reasonable grounds for insecurity arise with respect to contractual performance by either party.  At September 30, 2009, the aggregate fair value of our over-the-counter derivative instruments in a net liability position was $5.7 million, the total of which was subject to a credit

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ENTERPRISE PRODUCTS GP, LLC

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CONDENSED CONSOLIDATED BALANCE SHEET

rating contingent feature.  If our credit ratings were downgraded to Ba2/BB, approximately $5.0 million would be payable as a margin deposit to the counterparties, and if our credit ratings were downgraded to Ba3/BB- or below, approximately $5.7 million would be payable as a margin deposit to the counterparties.  Currently, no margin is required to be deposited.  The potential for derivatives with contingent features to enter a net liability position may change in the future as positions and prices fluctuate. 

Tabular Presentation of Fair Value Amounts on Derivative Instruments and Related Hedged Items

The following table provides a balance sheet overview of our derivative assets and liabilities at September 30, 2009:

	Asset Derivatives			Liability Derivatives
	Balance Sheet	Fair		Balance Sheet	Fair
	Location	Value		Location	Value
Derivatives designated as hedging instruments:
Interest rate derivatives	Derivative assets	$	23.2	Derivative liabilities	$	6.0
Interest rate derivatives	Other assets		33.4	Other liabilities		2.0
Total interest rate derivatives			56.6			8.0
Commodity derivatives	Derivative assets		51.9	Derivative liabilities		133.2
Commodity derivatives	Other assets		0.2	Other liabilities		2.1
Total commodity derivatives (1)			52.1			135.3
Foreign currency derivatives (2)	Derivative assets		0.3	Derivative liabilities		--
Total derivatives designated as
hedging instruments		$	109.0		$	143.3
Derivatives not designated as hedging instruments:
Commodity derivatives	Derivative assets	$	124.1	Derivative liabilities	$	125.4
Commodity derivatives	Other assets		1.1	Other liabilities		2.4
Total commodity derivatives			125.2			127.8
Total derivatives not designated as
hedging instruments		$	125.2		$	127.8
(1)   Represent commodity derivative instrument transactions that either have not settled or have settled and not been invoiced. Settled and invoiced transactions are reflected in either accounts receivable or accounts payable depending on the outcome of the transaction. (2)   Relates to the hedging of our exposure to fluctuations in the foreign currency exchange rate related to our Canadian NGL marketing subsidiary.

Fair Value Measurements

Fair value is defined 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, including 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.

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ENTERPRISE PRODUCTS GP, LLC

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CONDENSED CONSOLIDATED BALANCE SHEET

A three-tier hierarchy has been established 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 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 with sufficient frequency so as to provide pricing information on an ongoing basis (e.g., the New York Mercantile Exchange).  Our Level 1 fair values primarily consist of financial assets and liabilities such as exchange-traded commodity financial instruments.

§   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, the time value of money, volatility factors, current market and contractual prices for the underlying instruments and 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).  Our Level 2 fair values primarily consist of commodity financial instruments such as forwards, swaps and other instruments transacted on an exchange or over the counter.  The fair values of these derivatives are based on observable price quotes for similar products and locations.  The value of our interest rate derivatives are valued by using appropriate financial models with the implied forward London  Interbank Offered Rate yield curve for the same period as the future interest swap settlements.

§   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.  Our Level 3 fair values largely consist of ethane and normal butane-based contracts with a range of two to twelve months in term.  We rely on broker quotes for these products.

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ENTERPRISE PRODUCTS GP, LLC

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CONDENSED CONSOLIDATED BALANCE SHEET

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, 2009.  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, in addition to their placement within the fair value hierarchy levels.

	Level 1		Level 2		Level 3		Total
Financial assets:
Interest rate derivative instruments	$	--	$	56.6	$	--	$	56.6
Commodity derivative instruments		10.9		153.3		13.1		177.3
Foreign currency derivative instruments		--		0.3		--		0.3
Total	$	10.9	$	210.2	$	13.1	$	234.2
Financial liabilities:
Interest rate derivative instruments	$	--	$	8.0	$	--	$	8.0
Commodity derivative instruments		36.7		212.6		13.8		263.1
Total	$	36.7	$	220.6	$	13.8	$	271.1

The following table sets forth a reconciliation of changes in the fair value of our Level 3 financial assets and liabilities since December 31, 2008:

Balance, January 1	$	32.4
Total gains (losses) included in:
Net income		12.9
Other comprehensive income (loss)		1.5
Purchases, issuances, settlements		(12.3	)
Balance, March 31		34.5
Total gains (losses) included in:
Net income		7.7
Other comprehensive income		(23.1	)
Purchases, issuances, settlements		(8.1	)
Transfer in/out of Level 3		(0.2	)
Balance, June 30		10.8
Total gains (losses) included in:
Net income		7.6
Other comprehensive income		(10.1	)
Purchases, issuances, settlements		(6.7	)
Transfer in/out of Level 3		(2.3	)
Balance, September 30	$	(0.7	)

Nonfinancial Assets and Liabilities

Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis and are subject to fair value adjustments in certain circumstances (e.g., when there is evidence of impairment). The following table presents the estimated fair value of certain assets carried on our Unaudited Supplemental Condensed Consolidated Balance Sheet by caption for which a nonrecurring change in fair value has been recorded during the nine months ended September 30, 2009:

	Level 3		Impairment Charges
Property, plant and equipment (see Note 6)	$	21.9	$	20.6
Intangible assets (see Note 9)		0.6		0.6
Goodwill (see Note 9)		--		1.3
Other current assets		1.0		2.1
Total	$	23.5	$	24.6

Using appropriate valuation techniques, we adjusted the carrying value of certain river terminal and marine barge assets to $20.5 million and recorded a non-cash impairment charge of $21.0 million

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ENTERPRISE PRODUCTS GP, LLC

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED BALANCE SHEET

during the third quarter of 2009.  In addition, we recorded an impairment charge of $1.3 million related to goodwill.  The fair value adjustment was allocated to property, plant and equipment, intangible assets and other current assets.  The current level of throughput volumes at certain river terminals and the suspension of three new proposed river terminals were contributing factors that led to the impairment charges associated with the terminal assets.  A determination that certain marine barges were obsolete resulted in the remaining impairment charges.  Our fair value estimates for the terminal and marine assets were based primarily on an evaluation of the future cash flows associated with each asset.  See Note 14 for information regarding a related $28.7 million charge for contractual obligations associated with the terminal assets.

Using appropriate valuation techniques, we adjusted the carrying value of an idle river terminal to $3.0 million and recorded a non-cash impairment charge of $2.3 million during the second quarter of 2009.   The fair value adjustment was allocated to plant, property and equipment.

Note 5.  Inventories

Our inventory amounts were as follows at September 30, 2009:

Working inventory (1)	$	533.3
Forward sales inventory (2)		687.3
Total inventory	$	1,220.6
(1)   Working inventory is comprised of inventories of natural gas, crude oil, refined products, lubrication oils, NGLs and certain petrochemical products that are either available-for-sale or used in the provision for services. (2)   Forward sales inventory consists of identified natural gas, crude oil and NGL volumes dedicated to the fulfillment of forward sales contracts. As a result of energy market conditions, we significantly increased our physical inventory purchases and related forward physical sales commitments during 2009. In general, the significant increase in volumes dedicated to forward physical sales contracts improves the overall utilization and profitability of our fee-based assets.

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.  Inventories are valued at the lower of average cost or market.

Due to fluctuating commodity prices, we recognize lower of average cost or market (“LCM”) adjustments when the carrying value of our available-for-sale inventories exceed their net realizable value.  LCM adjustments may be mitigated or offset through the use of commodity hedging instruments to the extent such instruments affect net realizable value.  See Note 4 for a description of our commodity hedging activities.

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ENTERPRISE PRODUCTS GP, LLC

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED BALANCE SHEET

Note 6.  Property, Plant and Equipment

Our property, plant and equipment values and accumulated depreciation balances were as follows at September 30, 2009:

	Estimated
	Useful Life
	in Years
Plants and pipelines (1)	3-45 (5)	$	16,958.5
Underground and other storage facilities (2)	5-40 (6)		1,254.9
Platforms and facilities (3)	20-31		637.6
Transportation equipment (4)	3-10		56.3
Marine vessels	20-30		527.0
Land			260.2
Construction in progress			1,226.8
Total			20,921.3
Less accumulated depreciation			3,624.3
Property, plant and equipment, net		$	17,297.0
(1)   Plants and pipelines include processing plants; NGL, petrochemical, crude 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 and related equipment, 18-45 years (with some equipment at 5 years); terminal facilities, 10-35 years; delivery facilities, 20-40 years; office furniture and equipment, 3-20 years; buildings, 20-40 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, 10-40 years; and water wells, 25-35 years (with some components at 5 years).

We recorded $11.4 million and $39.5 million in capitalized interest during the three and nine months ended September 30, 2009.

In August 2008, our wholly owned subsidiaries, together with Oiltanking Holding Americas, Inc. (“Oiltanking”) formed the Texas Offshore Port System partnership (“TOPS”).  Effective April 16, 2009, our wholly owned subsidiaries dissociated from TOPS.

TOPS was a consolidated subsidiary of ours prior to the dissociation. The effect of deconsolidation was to remove the accounts of TOPS, including Oiltanking’s noncontrolling interest of $33.4 million, from our books and records, after reflecting the $68.4 million aggregate write-off of the investment.

Asset Retirement Obligations

Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of certain tangible long-lived assets that result from acquisitions, construction, development and/or normal operations.  The following table presents information regarding our AROs since December 31, 2008.

ARO liability balance, December 31, 2008	$	42.2
Liabilities incurred		0.4
Liabilities settled		(15.2	)
Revisions in estimated cash flows		23.6
Accretion expense		2.1
ARO liability balance, September 30, 2009	$	53.1

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ENTERPRISE PRODUCTS GP, LLC

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED BALANCE SHEET

The increase in our ARO liability balance during 2009 primarily reflects revised estimates of the cost to comply with regulatory abandonment obligations associated with our offshore facilities in the Gulf of Mexico.  Our consolidated property, plant and equipment at September 30, 2009 includes $26.3 million, of asset retirement costs capitalized as an increase in the associated long-lived asset.

Note 7.  Investments in Unconsolidated Affiliates

We own interests in a number of related businesses that are accounted for using the equity method of accounting.  Our investments in 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 shows our investments in unconsolidated affiliates at September 30, 2009.

	Ownership
	Percentage
NGL Pipelines & Services:
Venice Energy Service Company, L.L.C.	13.1%	$	33.1
K/D/S Promix, L.L.C. (“Promix”)	50%		47.8
Baton Rouge Fractionators LLC	32.2%		23.6
Skelly-Belvieu Pipeline Company, L.L.C. (“Skelly-Belvieu”)	49%		37.4
Onshore Natural Gas Pipelines & Services:
Evangeline (1)	49.5%		5.4
White River Hub, LLC	50%		27.1
Onshore Crude Oil Pipelines & Services:
Seaway Crude Pipeline Company (“Seaway”)	50%		181.0
Offshore Pipelines & Services:
Poseidon Oil Pipeline, L.L.C. (“Poseidon”)	36%		61.3
Cameron Highway Oil Pipeline Company (“Cameron Highway”)	50%		243.2
Deepwater Gateway, L.L.C.	50%		102.8
Neptune Pipeline Company, L.L.C. (“Neptune”)	25.7%		54.4
Nemo Gathering Company, LLC	33.9%		--
Petrochemical & Refined Products Services:
Baton Rouge Propylene Concentrator, LLC	30%		11.4
La Porte (2)	50%		3.5
Centennial Pipeline LLC (“Centennial”)	50%		66.8
Other	25%		0.5
Total		$	899.3
(1)   Refers to our ownership interests in Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp., collectively. (2)   Refers to our ownership interests in La Porte Pipeline Company, L.P. and La Porte GP, LLC, collectively.

At September 30, 2009, our investments in Promix, Skelly-Belvieu, La Porte, Neptune, Poseidon, Cameron Highway, Seaway and Centennial included excess cost amounts totaling $70.5 million, all of which were attributable to the fair value of the underlying tangible assets of these entities exceeding their book carrying values at the time of our acquisition of interests in these entities.

Note 8. Business Combinations

In May 2009, we acquired certain rail and truck terminal facilities located in Mont Belvieu, Texas from Martin Midstream Partners L.P (“Martin”).  Cash consideration paid for this business combination was $23.7 million, all of which was recorded as additions to property, plant and equipment.  We used our revolving credit facility to finance this acquisition.

In June 2009, TEPPCO expanded its marine transportation business with the acquisition of 19 tow boats and 28 tank barges from TransMontaigne Product Services Inc. for $50.0 million in cash.  The

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ENTERPRISE PRODUCTS GP, LLC

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED BALANCE SHEET

acquired vessels provide marine vessel fueling services for cruise liners and cargo ships, referred to as bunkering, and other ship-assist services and transport fuel oil for electric generation plants.  The newly acquired assets are generally supported by contracts that have a three to five year term and are based primarily in Miami, Florida, with additional assets located in Mobile, Alabama, and Houston, Texas.  The cost of the acquisition has been recorded as property, plant and equipment based on estimated fair values.  We used TEPPCO's revolving credit facility to finance this acquisition.

These acquisitions were accounted for as business combinations using the acquisition method of accounting.  All of the assets acquired in these transactions were recognized at their acquisition-date fair values.  Such fair values have been developed using recognized business valuation techniques.

Note 9.  Intangible Assets and Goodwill

Identifiable Intangible Assets

The following table summarizes our intangible assets by segment at September 30, 2009:

	Gross		Accum.			Carrying
	Value		Amort.			Value
NGL Pipelines & Services:
Customer relationship intangibles	$	237.4	$	(82.2	)	$	155.2
Contract-based intangibles		320.5		(151.7	)		168.8
Subtotal		557.9		(233.9	)		324.0
Onshore Natural Gas Pipelines & Services:
Customer relationship intangibles		372.0		(119.1	)		252.9
Gas gathering agreements		464.0		(234.1	)		229.9
Contract-based intangibles		101.3		(43.1	)		58.2
Subtotal		937.3		(396.3	)		541.0
Onshore Crude Oil Pipelines & Services:
Contract-based intangibles		10.0		(3.4	)		6.6
Subtotal		10.0		(3.4	)		6.6
Offshore Pipelines & Services:
Customer relationship intangibles		205.8		(101.8	)		104.0
Contract-based intangibles		1.2		(0.2	)		1.0
Subtotal		207.0		(102.0	)		105.0
Petrochemical & Refined Products Services:
Customer relationship intangibles		104.6		(17.6	)		87.0
Contract-based intangibles		42.0		(12.4	)		29.6
Subtotal		146.6		(30.0	)		116.6
Total	$	1,858.8	$	(765.6	)	$	1,093.2

Goodwill

Goodwill represents the excess of the purchase price of an acquired business over the amounts assigned to assets acquired and liabilities assumed in the transaction.  We do not amortize goodwill; however, we test goodwill for impairment annually, or more frequently if circumstances indicate that it is more likely than not that the fair value of goodwill is less than its carrying value. The following table summarizes our goodwill amounts by business segment at September 30, 2009:

NGL Pipelines & Services	$	341.2
Onshore Natural Gas Pipelines & Services		284.9
Onshore Crude Oil Pipelines & Services		303.0
Offshore Pipelines & Services		82.1
Petrochemical & Refined Products Services		1,007.1
Total	$	2,018.3

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ENTERPRISE PRODUCTS GP, LLC

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED BALANCE SHEET

Note 10.  Debt Obligations

Our consolidated debt obligations consisted of the following at September 30, 2009:

EPO senior debt obligations:
Multi-Year Revolving Credit Facility, variable rate, due November 2012	$	638.0
Pascagoula MBFC Loan, 8.70% fixed-rate, due March 2010 (1)		54.0
Petal GO Zone Bonds, variable rate, due August 2037		57.5
Yen Term Loan, 4.93% fixed-rate, due March 2009 (2)		--
Senior Notes B, 7.50% fixed-rate, due February 2011		450.0
Senior Notes C, 6.375% fixed-rate, due February 2013		350.0
Senior Notes D, 6.875% fixed-rate, due March 2033		500.0
Senior Notes F, 4.625% fixed-rate, due October 2009 (1)		500.0
Senior Notes G, 5.60% fixed-rate, due October 2014		650.0
Senior Notes H, 6.65% fixed-rate, due October 2034		350.0
Senior Notes I, 5.00% fixed-rate, due March 2015		250.0
Senior Notes J, 5.75% fixed-rate, due March 2035		250.0
Senior Notes K, 4.950% fixed-rate, due June 2010 (1)		500.0
Senior Notes L, 6.30% fixed-rate, due September 2017		800.0
Senior Notes M, 5.65% fixed-rate, due April 2013		400.0
Senior Notes N, 6.50% fixed-rate, due January 2019		700.0
Senior Notes O, 9.75% fixed-rate, due January 2014		500.0
Senior Notes P, 4.60% fixed-rate, due August 2012		500.0
TEPPCO senior debt obligations: (3)
TEPPCO Revolving Credit Facility, variable rate, due December 2012		791.7
TEPPCO Senior Notes, 7.625% fixed-rate, due February 2012		500.0
TEPPCO Senior Notes, 6.125% fixed-rate, due February 2013		200.0
TEPPCO Senior Notes, 5.90% fixed-rate, due April 2013		250.0
TEPPCO Senior Notes, 6.65% fixed-rate, due April 2018		350.0
TEPPCO Senior Notes, 7.55% fixed-rate, due April 2038		400.0
Duncan Energy Partners’ debt obligations:
DEP Revolving Credit Facility, variable rate, due February 2011		180.5
DEP Term Loan, variable rate, due December 2011		282.3
Total principal amount of senior debt obligations		10,404.0
EPO Junior Subordinated Notes A, fixed/variable rate, due August 2066		550.0
EPO Junior Subordinated Notes B, fixed/variable rate, due January 2068		682.7
TEPPCO Junior Subordinated Notes, fixed/variable rate, due June 2067		300.0
Total principal amount of senior and junior debt obligations		11.936.7
Other, non-principal amounts:
Change in fair value of debt-related derivative instruments		47.6
Unamortized discounts, net of premiums		(12.1	)
Unamortized deferred net gains related to terminated interest rate swaps		27.0
Total other, non-principal amounts		62.5
Total long-term debt	$	11,999.2
Letters of credit outstanding	$	109.3
(1)   In accordance with ASC 470, Debt, long-term and current maturities of debt reflect the classification of such obligations at September 30, 2009 after taking into consideration EPO’s (i) $1.1 billion issuance of Senior Notes in October 2009 and (ii) ability to use available borrowing capacity under its Multi-Year Revolving Credit Facility. (2)   The Yen Term Loan matured on March 30, 2009. (3)   In October 2009, EPO completed an exchange offer for TEPPCO notes (see below).

Parent-Subsidiary Guarantor Relationships

Enterprise Products Partners L.P. acts as guarantor of the consolidated debt obligations of EPO with the exception of the DEP Revolving Credit Facility and the DEP Term Loan.  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.

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ENTERPRISE PRODUCTS GP, LLC

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED BALANCE SHEET

Letters of Credit

At September 30, 2009, EPO had an outstanding $50.0 million letter of credit relating to its commodity derivative instruments and a $58.3 million letter of credit related to its Petal GO Zone Bonds.  These letter of credit facilities do not reduce the amount available for borrowing under EPO’s credit facilities.  In addition, at September 30, 2009, Duncan Energy Partners had an outstanding letter of credit in the amount of $1.0 million which reduces the amount available for borrowing under its credit facility.

EPO’s Debt Obligations

Apart from that discussed below, there have been no significant changes in the terms of our debt obligations since those reported in this Current Report on Form 8-K under Exhibit 99.1.

$200.0 Million Term Loan.  In April 2009, EPO entered into a $200.0 Million Term Loan, which was subsequently repaid and terminated in June 2009 using funds from the issuance of Senior Notes P (see below).

Senior Notes P.  In June 2009, EPO issued $500.0 million in principal amount of 3-year senior unsecured notes (“Senior Notes P”).  Senior Notes P were issued at 99.95% of their principal amount, have a fixed interest rate of 4.60% and mature on August 1, 2012.  Net proceeds from the issuance of Senior Notes P were used (i) to repay amounts borrowed under the $200 Million Term Loan, (ii) to temporarily reduce borrowings outstanding under EPO’s Multi-Year Revolving Credit Facility and (iii) for general partnership purposes.

Senior Notes P 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 P 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.

364-Day Revolving Credit Facility.  In November 2008, EPO executed a standby 364-Day Revolving Credit Agreement (the “364-Day Facility”) that had a borrowing capacity of $375.0 million.  The 364-Day Facility was terminated in June 2009 under its terms as a result of the issuance of Senior Notes P.  No amounts were borrowed under this standby facility through its termination date.

Senior Notes Q and R.  In October 2009, EPO issued $500.0 million in principal amount of 10-year senior unsecured notes (“Senior Notes Q”) and $600.0 million in principal amount of 30-year senior unsecured notes (“Senior Notes R”).  EPO used a portion of the net proceeds it received from the issuance of Senior Notes Q and R to repay its $500.0 million in principal amount unsecured notes (“Senior Notes F”) that matured in October 2009.  See Note 16 for additional information regarding these debt issuances.

TEPPCO’s Debt Obligations

Exchange Offers for TEPPCO Notes.  In September 2009, EPO commenced offers to exchange all outstanding notes issued by TEPPCO for a corresponding series of new notes to be issued by EPO and guaranteed by Enterprise Products Partners L.P.  The aggregate principal amount of the TEPPCO notes subject to the exchange was $2 billion.  The exchange offer was completed on October 27, 2009, resulting in the exchange of approximately $1.95 billion of new EPO notes for existing TEPPCO notes.  See Note 16 for additional information regarding this exchange offer.

Upon the consummation of the TEPPCO Merger, EPO repaid and terminated indebtedness under the TEPPCO Revolving Credit Facility.

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ENTERPRISE PRODUCTS GP, LLC

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CONDENSED CONSOLIDATED BALANCE SHEET

Dixie Revolving Credit Facility

The Dixie Revolving Credit Facility was terminated in January 2009.

Covenants

We were in compliance with the covenants of our consolidated debt agreements at September 30, 2009.

Information Regarding Variable Interest Rates Paid

The following table shows the weighted-average interest rate paid on our consolidated variable-rate debt obligations during the nine months ended September 30, 2009.

	Weighted-Average
	Interest Rate
	Paid
EPO’s Multi-Year Revolving Credit Facility	0.97%
DEP Revolving Credit Facility	1.64%
DEP Term Loan	1.20%
Petal GO Zone Bonds	0.76%
TEPPCO Revolving Credit Facility	0.86%

Consolidated Debt Maturity Table

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

2009 (1)	$	500.0
2010 (1)		554.0
2011		912.8
2012		2,429.7
2013		1,200.0
Thereafter		6,340.2
Total scheduled principal payments	$	11,936.7
(1)   Long-term and current maturities of debt reflect the classification of such obligations on our Unaudited Supplemental Condensed Consolidated Balance Sheet at September 30, 2009 after taking into consideration EPO’s   (i) $1.1 billion issuance of Senior Notes in October 2009 and (ii) ability to use available borrowing capacity under its Multi-Year Revolving Credit Facility.

Debt Obligations of Unconsolidated Affiliates

We have three unconsolidated affiliates with long-term debt obligations.  The following table shows (i) the ownership interest in each entity at September 30, 2009, (ii) total debt of each unconsolidated affiliate at September 30, 2009 (on a 100% basis to the unconsolidated affiliate) and (iii) the corresponding scheduled maturities of such debt:

				Scheduled Maturities of Debt
	Ownership													After
	Interest	Total		2009		2010		2011		2012		2013		2013
Poseidon	36%	$	92.0	$	--	$	--	$	92.0	$	--	$	--	$	--
Evangeline	49.5%		15.7		5.0		3.2		7.5		--		--		--
Centennial	50%		122.4		2.4		9.1		9.0		8.9		8.6		84.4
Total		$	230.1	$	7.4	$	12.3	$	108.5	$	8.9	$	8.6	$	84.4

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ENTERPRISE PRODUCTS GP, LLC

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED BALANCE SHEET

The credit agreements of these unconsolidated affiliates contain various affirmative and negative covenants, including financial covenants.  These businesses were in compliance with such covenants at September 30, 2009.  The credit agreements of these unconsolidated affiliates also restrict their ability to pay cash dividends or distributions if a default or an event of default (as defined in each credit agreement) has occurred and is continuing at the time such dividend or distribution 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 this Current Report on Form 8-K under Exhibit 99.1.

Note 11.  Equity

At September 30, 2009, equity consisted of the capital account of Enterprise GP Holdings, accumulated other comprehensive loss and noncontrolling interest.

Accumulated Other Comprehensive Loss

The following table summarizes transactions affecting our accumulated other comprehensive loss:

Balance, December 31, 2008	$	(2.0	)
Net commodity financial instrument gains during period		0.6
Net interest rate financial instrument gains during period		0.2
Net foreign currency financial instrument gains during  period		(0.2	)
Balance, September 30, 2009	$	(1.4	)

Noncontrolling Interest

The following table shows the components of noncontrolling interest at September 30, 2009:

Limited partners of Enterprise Products Partners:
Third-party owners of Enterprise Products Partners(1)	$	5,379.7
Related party owners of Enterprise Products Partners (2)		922.0
Former owners of TEPPCO (3)		2,608.7
Limited partners of Duncan Energy Partners:
Third-party owners of Duncan Energy Partners(4)		416.9
Joint venture partners(5)		108.6
Accumulated other comprehensive loss attributable to noncontrolling interest		(110.8	)
Total noncontrolling interest on Unaudited Supplemental Condensed Consolidated Balance Sheet	$	9,325.1
(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)   Represents former ownership interests in TEPPCO and TEPPCO GP (see Note 1 - “Basis of Presentation”). (4)   Consists of non-affiliate public unitholders of Duncan Energy Partners. (5)   Represents third-party ownership interests in joint ventures that we consolidate, including Seminole Pipeline Company, Tri-States Pipeline, L.L.C., Independence Hub, LLC and Wilprise Pipeline Company, L.L.C.

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Note 12.  Business Segments

As previously mentioned in Note 1, we revised our business segments as a result of the TEPPCO Merger.  We have five reportable business segments: NGL Pipelines & Services, Onshore Natural Gas Pipelines & Services, Onshore Crude Oil Pipelines & Services, Offshore Pipelines & Services and Petrochemical & Refined Products 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.

Information by segment, together with reconciliations to our consolidated totals, is presented in the following table at September 30, 2009:

	Reportable Segments
			Onshore		Onshore				Petrochemical
	NGL		Natural Gas		Crude Oil		Offshore		& Refined		Adjustments
	Pipelines		Pipelines		Pipelines		Pipelines		Products		and		Consolidated
	& Services		& Services		& Services		& Services		Services		Eliminations		Totals
Segment assets	$	6,280.3	$	5,761.5	$	391.6	$	1,488.4	$	2,148.4	$	1,226.8	$	17,297.0
Investments in unconsolidated affiliates (see Note 7)		141.9		32.5		181.0		461.7		82.2		--		899.3
Intangible assets, net: (see Note 9)		324.0		541.0		6.6		105.0		116.6		--		1,093.2
Goodwill (see Note 9)		341.2		284.9		303.0		82.1		1,007.1		--		2,018.3

Note 13.  Related Party Transactions

The following table summarizes our related party receivable and payable amounts at September 30, 2009:

Accounts receivable - related parties:
EPCO and affiliates	$	--
Energy Transfer Equity and subsidiaries		6.4
Other		3.2
Total	$	9.6
Accounts payable - related parties:
EPCO and affiliates	$	12.0
Energy Transfer Equity and subsidiaries		27.2
Other		5.0
Total	$	44.2

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.

Significant Relationships and Agreements 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 a part of our consolidated group of companies:

§   EPCO and its privately held affiliates;

§   Enterprise GP Holdings, which owns and controls EPGP; and

§   the Employee Partnerships.

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We also have an ongoing relationship with Duncan Energy Partners, the financial statements of which are consolidated with our own financial statements.  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 privately held company controlled by Dan L. Duncan, who is also a director and Chairman of EPGP, our general partner.  At September 30, 2009, EPCO and its affiliates beneficially owned 168,005,206 (or 35.2%) of Enterprise Products Partners’ outstanding common units, which includes 13,952,402 of Enterprise Products Partners’ common units owned by Enterprise GP Holdings.  In addition, at September 30, 2009, 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 $124.9 million from Enterprise Products Partners during the nine months ended September 30, 2009.  This amount includes incentive distributions of $109.9 million for the nine months ended September 30, 2009.

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 privately held 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 privately held affiliates received from Enterprise Products Partners and Enterprise GP Holdings $354.9 million in cash distributions during the nine months ended September 30, 2009.

EPCO ASA.  We have no employees.  Substantially all of our operating functions and general and administrative support services are provided by employees of EPCO pursuant to the ASA.  We, Duncan Energy Partners, Enterprise GP Holdings and our respective general partners are among the parties to the ASA.

Relationship with Energy Transfer Equity

In May 2007, Enterprise GP Holdings acquired equity method investments in Energy Transfer Equity and its general partner.  As a result of common control of us and Enterprise GP Holdings, Energy Transfer Equity and its consolidated subsidiaries are 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.  The contract continues until March 31, 2010 and contains renewal and extension options.  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.

Relationship with Duncan Energy Partners

Duncan Energy Partners was formed in September 2006 and did not acquire any assets prior to February 5, 2007, which was the date it completed its initial public offering and acquired controlling interests in five midstream energy businesses from EPO in a dropdown transaction (the “DEP I Midstream Businesses”).  On December 8, 2008, through a second dropdown transaction, Duncan Energy Partners acquired controlling interests in three additional midstream energy businesses from EPO (the “DEP II Midstream Businesses”).  The business purpose of Duncan Energy Partners is to acquire, own and operate a diversified portfolio of midstream energy assets and to support the growth objectives of EPO and other

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affiliates under common control. Duncan Energy Partners is engaged in (i) the gathering, transportation and storage of natural gas; (ii) NGL transportation and fractionation; (iii) the storage of NGL and petrochemical products; (iv) the transportation of petrochemical products; and (v) the marketing of NGLs and natural gas.

At September 30, 2009, Duncan Energy Partners was owned 99.3% by its limited partners and 0.7% by its general partner, DEP GP, which is a wholly owned subsidiary of EPO.  DEP GP is responsible for managing the business and operations of Duncan Energy Partners.  DEP Operating Partnership, L.P., a wholly owned subsidiary of Duncan Energy Partners, conducts substantially all of Duncan Energy Partners’ business.  At September 30, 2009, EPO beneficially owned approximately 58% of Duncan Energy Partners’ limited partner interests and 100% of its general partner.

Enterprise Products Partners has continued involvement with all of the subsidiaries of Duncan Energy Partners, including the following types of transactions: (i)it utilizes Duncan Energy Partners’ storage services to support its Mont Belvieu fractionation and other businesses; (ii) it buys from, and sells to, Duncan Energy Partners natural gas in connection with its normal business activities; and (iii) it is currently the sole shipper on an NGL pipeline system located in South Texas that is owned by Duncan Energy Partners.

Duncan Energy Partners issued an aggregate 8,943,400 of its common units in June and July 2009, which generated net proceeds of approximately $137.4 million.  Duncan Energy Partners used the net proceeds from its issuance of these units to repurchase and cancel an equal number of its common units beneficially owned by EPO.  The repurchase of Duncan Energy Partners’ common units beneficially owned by EPO was reviewed and approved by the ACG Committees of EPGP and DEP GP.

Omnibus Agreement.  Under the Omnibus Agreement, EPO agreed to make additional contributions to Duncan Energy Partners as reimbursement for Duncan Energy Partners’ 66% share of any excess construction costs above the (i) $28.6 million of estimated capital expenditures to complete Phase II expansions of the DEP South Texas NGL Pipeline System and (ii) $14.1 million of estimated construction costs for additional brine production capacity and above-ground storage reservoir projects at Mont Belvieu, Texas.  Both projects were underway at the time of Duncan Energy Partners’ initial public offering.  EPO made cash contributions to Duncan Energy Partners of $1.4 million in connection with the Omnibus Agreement during the nine months ended September 30, 2009.  The majority of these contributions related to funding the Phase II expansion costs of the DEP South Texas NGL Pipeline System.  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.

Mont Belvieu Caverns’ LLC Agreement.  EPO made cash contributions of $14.1 million under the Mont Belvieu Caverns limited liability company agreement during the nine months ended September 30, 2009, to fund 100% of certain storage-related projects for the benefit of EPO’s NGL marketing activities.  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 sharing ratio of 66% for Duncan Energy Partners and 34% for EPO.  EPO expects to make additional contributions of approximately $9.1 million to fund such projects during the fourth quarter of 2009.  The constructed assets will be the property of Mont Belvieu Caverns.

Company and Limited Partnership Agreements – DEP II Midstream Businesses.  Enterprise Holdings III, LLC (“Enterprise III”) has not yet participated in expansion project spending with respect to the DEP II Midstream Businesses, although it may elect to invest in existing or future expansion projects at a later date.  As a result, Enterprise GTM Holdings L.P. has funded 100% of such growth capital spending and its Distribution Base has increased from $473.4 million at December 31, 2008 to $745.7 million at September 30, 2009.  The Enterprise III Distribution Base was unchanged at $730.0 million at September 30, 2009.

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Relationships with Unconsolidated Affiliates

Our significant related party transactions with unconsolidated affiliates consist of the sale of natural gas to Evangeline and Promix.  In addition, we purchase NGL storage, transportation and fractionation services from Promix.  For additional information regarding our unconsolidated affiliates, see Note 7.

Relationship with Cenac

In connection with our marine services acquisition in February 2008, Cenac and affiliates became a related party of ours due to their ownership of TEPPCO units through October 26, 2009, which converted to common units of Enterprise Products Partners, and other considerations.  We entered into a transitional operating agreement with Cenac in which our fleet of tow boats and tank barges (acquired from Cenac) continued to be operated by employees of Cenac for a period of up to two years following the acquisition.  Under this agreement, we paid Cenac a monthly operating fee and reimbursed Cenac for personnel salaries and related employee benefit expenses, certain repairs and maintenance expenses and insurance premiums on the equipment.  Effective August 1, 2009, the transitional operating agreement was terminated.  Personnel providing services pursuant to the agreement became employees of EPCO and will continue to provide services under the ASA.  Concurrently with the termination of the transitional operating agreement, we entered into a two-year consulting agreement with Mr. Cenac and Cenac Marine Services, L.L.C. under which Mr. Cenac has agreed to supervise the day-to-day operations of our marine services business on a part-time basis and, at our request, provide related management and transitional services.

Note 14.  Commitments and Contingencies

Litigation

On occasion, we or our unconsolidated affiliates are named as a defendant in litigation and legal proceedings, including regulatory and environmental matters.  Although we are insured against various 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.  We are unaware of any litigation, pending or threatened, that we believe is reasonably likely to have a significant adverse effect on our financial position.

We evaluate our ongoing litigation based upon a combination of litigation and settlement alternatives.  These reviews are updated as the facts and combinations of the cases develop or change.  Assessing and predicting the outcome of these matters involves substantial uncertainties.  In the event that the assumptions we used to evaluate these matters change in future periods or new information becomes available, we may be required to record a liability for an adverse outcome.  In an effort to mitigate potential adverse consequences of litigation, we could also seek to settle legal proceedings brought against us.  We have not recorded any significant reserves for any litigation in our supplementalbalance sheet.

On September 18, 2006, Peter Brinckerhoff, a purported unitholder of TEPPCO, filed a complaint in the Court of Chancery of the State of Delaware (the “Delaware Court”), in his individual capacity, as a putative class action on behalf of other unitholders of TEPPCO and derivatively on behalf of TEPPCO, concerning, among other things, certain transactions involving TEPPCO and Enterprise Products Partners or its affiliates.  Mr. Brinckerhoff filed an amended complaint on July 12, 2007.  The amended 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 its affiliates, (iii) EPCO and (iv) Dan L. Duncan.

The amended complaint alleges, among other things, that the defendants caused TEPPCO to enter into specified 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

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(the plaintiff alleges that TEPPCO did not receive fair value for allowing Enterprise Products Partners to participate in the joint venture); (ii) the sale by TEPPCO of its Pioneer natural gas processing plant and certain gas processing rights to Enterprise Products Partners in March 2006 (the plaintiff alleges that the purchase price we paid did not provide fair value to TEPPCO); 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 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) an award to plaintiff of the costs of the action, including fees and expenses of his attorneys and experts.  By its Opinion and Order dated November 25, 2008, the Delaware Court dismissed Mr. Brinckerhoff’s individual and putative class action claims with respect to the amendments to TEPPCO’s partnership agreement.  We refer to this action and the remaining claims in this action as the “Derivative Action.”

On April 29, 2009, Peter Brinckerhoff and Renee Horowitz, as Attorney in Fact for Rae Kenrow, purported unitholders of TEPPCO, filed separate complaints in the Delaware Court as putative class actions on behalf of other unitholders of TEPPCO, concerning the TEPPCO Merger.  On May 11, 2009, these actions were consolidated under the caption Texas Eastern Products Pipeline Company, LLC Merger Litigation, C.A. No. 4548-VCL (“Merger Action”). The complaints name as defendants Enterprise Products Partners, EPGP, TEPPCO GP, the directors of TEPPCO GP, EPCO and Dan L. Duncan.

The Merger Action complaints allege, among other things, that the terms of the merger (as proposed as of the time the Merger Action complaints were filed) are grossly unfair to TEPPCO’s unitholders and that the TEPPCO Merger is an attempt to extinguish the Derivative Action without consideration.  The complaints further allege that the process through which the Special Committee of the ACG Committee of TEPPCO GP was appointed to consider the TEPPCO Merger is contrary to the spirit and intent of TEPPCO’s partnership agreement and constitutes a breach of the implied covenant of fair dealing.

The complaints seek relief (i) enjoining the defendants and all persons acting in concert with them from pursuing the TEPPCO Merger, (ii) rescinding the TEPPCO Merger to the extent it is consummated, or awarding rescissory damages in respect thereof, (iii) directing the defendants to account for all damages suffered or to be suffered by the plaintiffs and the purported class as a result of the defendants’ alleged wrongful conduct, and (iv) awarding plaintiffs’ costs of the actions, including fees and expenses of their attorneys and experts.

On June 28, 2009, the parties entered into a Memorandum of Understanding pursuant to which Enterprise Products Partners, TEPPCO, EPCO, TEPPCO GP, all other individual defendants and the plaintiffs have proposed to settle the Merger Action and the Derivative Action.  The Memorandum of Understanding contemplated that the parties would enter into a stipulation of settlement within 30 days from the date of the Memorandum of Understanding.  On August 5, 2009, the parties entered into a Stipulation and Agreement of Compromise, Settlement and Release (the “Settlement Agreement”) contemplated by the Memorandum of Understanding.  Pursuant to the Settlement Agreement, the board of directors of TEPPCO GP recommended to TEPPCO’s unitholders that they approve the adoption of the merger agreement and took all necessary steps to seek unitholder approval for the merger as soon as practicable.  Pursuant to the Settlement Agreement, approval of the merger required, in addition to votes required under TEPPCO’s partnership agreement, that the actual votes cast in favor of the proposal by holders of TEPPCO’s outstanding units, excluding those held by defendants to the Derivative Action, exceed the actual votes cast against the proposal by those holders.  The Settlement Agreement further provides that the Derivative Action was considered by TEPPCO GP’s Special Committee to be a significant TEPPCO benefit for which fair value was obtained in the merger consideration.

The Settlement Agreement is subject to customary conditions, including Delaware Court approval.  A hearing regarding approval of the Settlement Agreement by the Delaware Court was held on October 12, 2009, but the Delaware Court has yet to rule on the settlement.  There can be no assurance that the Delaware Court will approve the settlement in the Settlement Agreement.  In such event, the proposed

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settlement as contemplated by the Settlement Agreement may be terminated.  Among other things, the plaintiffs’ agreement to settle the Derivative Action and Merger Action litigation, including their agreement to the fairness of the terms and process of the merger negotiations, is subject to (i) the drafting and execution of other such documentation as may be required to obtain final Delaware Court approval and dismissal of the actions, (ii) Delaware Court approval and the mailing of the notice of settlement which sets forth the terms of settlement to TEPPCO’s unitholders, (iii) consummation of the TEPPCO Merger and (iv) final Delaware Court certification and approval of the settlement and dismissal of the actions.  See Notes 1 and 16 for additional information regarding our relationship with TEPPCO, including information related to the TEPPCO Merger.

Additionally, on June 29 and 30, 2009, respectively, M. Lee Arnold and Sharon Olesky, purported unitholders of TEPPCO, filed separate complaints in the District Courts of Harris County, Texas, as putative class actions on behalf of other unitholders of TEPPCO, concerning the TEPPCO Merger (the “Texas Actions”).  The complaints name as defendants us, TEPPCO, TEPPCO GP, EPGP, EPCO, Dan L. Duncan, Jerry Thompson, and the board of directors of TEPPCO GP.  The allegations in the complaints are similar to the complaints filed in Delaware on April 29, 2009 and seek similar relief.  The named plaintiffs in the two Texas Actions (the “Texas Plaintiffs/Objectors”) have also appeared in the Delaware proceedings as objectors to the settlement of those cases which are awaiting court approval.  On October 7, 2009, the Texas Plaintiffs/Objectors and the parties to the Settlement Agreement entered into a Stipulation to Withdraw Objection (the “Stipulation”).  In accordance with the Stipulation, TEPPCO made certain supplemental disclosures and, if the Settlement Agreement obtains Final Court Approval (as defined in the Settlement Agreement), the Texas Plaintiffs/Objectors have agreed to dismiss the Texas Actions with prejudice and, pending such Final Court Approval, will take no action to prosecute the Texas Actions.

In February 2007, EPO received a letter from the Environment and Natural Resources Division of the U.S. Department of Justice 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.  This matter was settled in September 2009, and Magellan has agreed to pay all assessed penalties.

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. We have entered into a settlement agreement with the State that dismisses the suit and assesses a fine of approximately $0.2 million.

In January 2009, the State of New Mexico filed suit in District Court in Santa Fe County, New Mexico, under the New Mexico Air Quality Control Act.  The lawsuit arose out of a February 27, 2008 Notice Of Violation issued to Marathon Oil Corp. (“Marathon”) as operator of the Indian Basin natural gas processing facility located in Eddy County, New Mexico.  We own a 42.4% undivided interest in the assets comprising the Indian Basin facility.  The State alleges violations of its air laws, and Marathon is attempting to negotiate an acceptable resolution with the state.  The State seeks penalties and remedial projects above $0.1 million.  Marathon continues to work with the State to determine if resolution of the case is possible.  We believe that any potential penalties will not have a material impact on our consolidated financial position.

In connection with our dissociation from TOPS (see Note 6), Oiltanking filed an original petition against Enterprise Offshore Port System, LLC, EPO, TEPPCO O/S Port System, LLC, TEPPCO and TEPPCO GP in the District Court of Harris County, Texas, 61st Judicial District (Cause No. 2009-31367), asserting, among other things, that the dissociation was wrongful and in breach of the TOPS partnership agreement, citing provisions of the agreement that, if applicable, would continue to obligate Enterprise Products Partners and TEPPCO to make capital contributions to fund the project and impose liabilities on

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Enterprise Products Partners and TEPPCO.  On September 17, 2009, Enterprise Products Partners and TEPPCO entered into a settlement agreement with certain affiliates of Oiltanking and TOPS that resolved all disputes between the parties related to the business and affairs of the TOPS project (including the litigation described above).

Regulatory Matters

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” or “GHGs” and including carbon dioxide and methane, may be contributing to climate change.  On April 17, 2009, the U.S. Environmental Protection Agency (“EPA”) issued a notice of its proposed finding and determination that emission of carbon dioxide, methane, and other GHGs present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere.  The EPA’s finding and determination would allow it to begin regulating emissions of GHGs under existing provisions of the federal Clean Air Act.  Although it may take the EPA several years to adopt and impose regulations limiting emissions of GHGs, any such regulation could require us to incur costs to reduce emissions of GHGs associated with our operations.  In addition, on June 26, 2009, the U.S. House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” or “ACESA.”  ACESA would establish an economy-wide cap on emissions of GHGs in the United States and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs.  The U.S. Senate has also begun work on its own legislation for controlling and reducing emissions of GHGs in the United States.  Any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased operating costs, and may have an adverse effect on our business and financial position.

Contractual Obligations

Scheduled maturities of long-term debt. See Notes 10 and 16 for information regarding changes in our consolidated debt obligations.

Operating lease obligations.  During the second quarter of 2009, we entered into a 20-year right-of-way agreement with the Jicarilla Apache Nation in support of continued natural gas gathering activities on our San Juan gathering system in Northwest New Mexico.  Pending approval of this agreement by the U.S. Department of the Interior, our minimum lease obligations will be $3.0 million for the first year and $2.0 million per year for each of the next succeeding four years.  Aggregate minimum lease commitments are $43.3 million over the 20-year contractual term.  The agreement also provides for contingent rentals that are calculated annually based on actual throughput volumes and then current natural gas and NGL prices.  Our agreement with the Jicarilla Apache Nation does not provide for renewal options beyond the 20-year lease term.

Prior to May 2009, we leased rail and truck terminal facilities in Mont Belvieu, Texas from Martin.  At December 31, 2008, our remaining aggregate minimum lease commitments under this agreement were $56.8 million through the contractual term ending in 2023.  The lease agreement with Martin was terminated upon our acquisition of such facilities in May 2009.  See Note 8 for additional information regarding our acquisition of certain rail and truck terminal facilities from Martin.

Except for the foregoing, there have been no material changes in our operating lease commitments since December 31, 2008.

Purchase obligations.  Apart from that discussed below, there have been no material changes in our consolidated purchase obligations since December 31, 2008. 

As a result of our dissociation from TOPS, capital expenditure commitments decreased by an estimated $203.0 million from that reported in this Current Report on Form 8-K under Exhibit 99.1.  See Note 6 for additional information regarding TOPS.

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In January 2008, TEPPCO entered into an amended throughput and deficiency agreement with Colonial Pipeline Company (“Colonial”) related to our Boligee river terminal.  Under terms of the agreement, Colonial agreed to provide transportation services to the Boligee terminal for a period of 10-years effective January 1, 2009.  The minimum annual throughput commitment to Colonial was approximately 8.0 million barrels of product.  We agreed to pay annual deficiency charges if it failed to meet its minimum annual volume throughput commitment.

The contractual annual minimum commitment of 8.0 million barrels was premised upon expected throughput volumes at the Boligee terminal, which was designed to serve several planned river terminals to be constructed. In September 2009, the expansion river terminal construction projects were suspended.  Based on the current level of terminal volumes, we forecast that the Boligee terminal will not be able to meet its annual minimum commitment to Colonial over the term of the contract.  As a result, we accrued a liability of $28.7 million for deficiency fees that it reasonably estimates will be incurred due to the expected level of throughput volumes at Boligee.  In accordance with applicable accounting standards, we will adjust its accrual if it determines that it is probable that the amount it is obligated to pay Colonial changes in the future.

At September 30, 2009, the accrued liability was recorded as a component of other current liabilities and other long-term liabilities, as appropriate, on our Unaudited Supplemental Condensed Consolidated Balance Sheet. 

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, 2009, claims against us totaled approximately $4.8 million.  These matters are in various stages of assessment and the ultimate outcome of such disputes cannot be reasonably estimated.  However, in our opinion, the likelihood of a material adverse outcome related to disputes against us is remote.  Accordingly, accruals for loss contingencies related to these matters, if any, that might result from the resolution of such disputes have not been reflected in our Unaudited Supplemental Condensed Consolidated Balance Sheet.

Note 15.   Significant Risks and Uncertainties

Insurance Matters

EPCO completed its annual insurance renewal process during the second quarter of 2009.  In light of recent hurricane and other weather-related events, the renewal of policies for weather-related risks resulted in significant increases in premiums and certain deductibles, as well as changes in the scope of coverage. 

EPCO’s deductible for onshore physical damage from windstorms increased from $10.0 million per storm to $25.0 million per storm.  EPCO’s onshore program currently provides $150.0 million per occurrence for named windstorm events compared to $175.0 million per occurrence in the prior year.  With respect to offshore assets, the windstorm deductible increased significantly from $10.0 million per storm (with a one-time aggregate deductible of $15.0 million) to $75.0 million per storm.  EPCO’s offshore program currently provides $100.0 million in the aggregate compared to $175.0 million in the aggregate for the prior year.  For non-windstorm events, EPCO’s deductible for both onshore and offshore physical damage remained at $5.0 million per occurrence.  For certain of our major offshore assets, our producer customers have agreed to provide a specified level of physical damage insurance for named windstorms.  For example, the producers associated with our Independence Hub and Marco Polo platforms have agreed to cover windstorm generated physical damage costs up to $250.0 million for each platform.

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Business interruption coverage in connection with a windstorm event remains in place for onshore assets, but was eliminated for offshore assets.  Onshore assets covered by business interruption insurance must be out-of-service in excess of 60 days before any losses from business interruption will be covered.  Furthermore, pursuant to the current policy, we will now absorb 50% of the first $50.0 million of any loss in excess of deductible amounts for our onshore assets.

In the third quarter of 2008, certain of our onshore and offshore facilities located along the Gulf Coast of Texas and Louisiana were damaged by Hurricanes Gustav and Ike.  The disruptions in hydrocarbon production caused by these storms resulted in decreased volumes for some of our pipeline systems, natural gas processing plants, NGL fractionators and offshore platforms, which in turn caused a decrease in gross operating margin from these operations.  As a result of our share of EPCO’s insurance deductibles for windstorm coverage, we expensed a combined cumulative total of $48.8 million of repair costs for property damage in connection with these two storms through September 30, 2009.  We continue to file property damage claims in connection with the damage caused by these storms.  We recognize business interruption proceeds as income when they are received in cash.

The following table summarizes proceeds we received during the nine months ended September 30, 2009 from business interruption and property damage insurance claims with respect to certain named storms:

Business interruption proceeds:
Hurricane Ike	$	19.2
Property damage proceeds:
Hurricane Ivan		0.7
Hurricane Katrina		26.7
Total property damage proceeds		27.4
Total	$	46.6

At September 30, 2009, we had $22.6 million of estimated property damage claims outstanding related to storms that we believe are probable of collection during the next twelve months and $45.2 million thereafter.  To the extent we estimate the dollar value of such damages, please be aware that a change in our estimates may occur, if and when additional information becomes available.

Credit Risk due to Industry Concentrations

On January 6, 2009, LyondellBasell Industries and its affiliates (“LBI”) announced that its U.S. operations had voluntarily filed to reorganize under Chapter 11 of the U.S. Bankruptcy Code.  At the time of the bankruptcy filing, we had approximately $10.0 million of net credit exposure to LBI.  We resolved our outstanding claims with LBI in October 2009 with no gain or loss being recorded in connection with the settlement.  We continue to do business with this important customer; however, we continue to monitor our credit exposure to LBI.

Note 16.  Subsequent Events

Issuance of Senior Notes Q and R

On October 5, 2009, EPO issued $500.0 million in principal amount of 10-year unsecured Senior Notes Q and $600.0 million in principal amount of 30-year unsecured Senior Notes R.  Senior Notes Q were issued at 99.355% of their principal amount, have a fixed interest rate of 5.25% and mature on January 31, 2020.  Senior Notes R were issued at 99.386% of their principal amount, have a fixed interest rate of 6.125% and mature on October 15, 2039.  Net proceeds from the issuance of Senior Notes Q and R were used (i) to repay $500.0 million in aggregate principal amount of Senior Notes F that matured in October 2009, (ii) to temporarily reduce borrowings outstanding under EPO’s Multi-Year Revolving Credit Facility and (iii) for general partnership purposes.

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ENTERPRISE PRODUCTS GP, LLC

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED BALANCE SHEET

Senior Notes Q and R 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 Q and R 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.

Completion of TEPPCO Merger

On October 26, 2009, the related mergers of Enterprise Products Partners’ wholly owned subsidiaries with TEPPCO and TEPPCO GP were completed.  Under terms of the merger agreements, TEPPCO and TEPPCO GP became wholly owned subsidiaries of Enterprise Products Partners and each of TEPPCO's unitholders, except for a privately held affiliate of EPCO, were entitled to receive 1.24 of Enterprise Products Partners’ common units for each TEPPCO unit.  In total, Enterprise Products Partners issued an aggregate of 126,932,318 common units and 4,520,431 Class B units (described below) as consideration in the TEPPCO Merger for both TEPPCO units and the TEPPCO GP membership interests.  TEPPCO’s units, which had been trading on the NYSE under the ticker symbol TPP, have been delisted and are no longer publicly traded.

A privately held affiliate of EPCO exchanged a portion of its TEPPCO units, based on the 1.24 exchange rate, for 4,520,431 of Enterprise Products Partners’ Class B units in lieu of common units.  The Class B units are not entitled to regular quarterly cash distributions for the first sixteen quarters following the closing date of the merger.  The Class B units automatically convert into the same number of common units on the date immediately following the payment date for the sixteenth quarterly distribution following the closing date of the merger.  The Class B units are entitled to vote together with the common units as a single class on partnership matters and, except for the payment of distributions, have the same rights and privileges as Enterprise Products Partners’ common units.

Under the terms of the TEPPCO Merger agreements, Enterprise GP Holdings received 1,331,681 of Enterprise Products Partners’ common units and an increase in the capital account of EPGP to maintain its 2% general partner interest in Enterprise Products Partners as consideration for 100% of the membership interests of TEPPCO GP.  Following the closing of the TEPPCO Merger, affiliates of EPCO owned approximately 31.3% of Enterprise Products Partners’ outstanding limited partner units, including 3.4% owned by Enterprise GP Holdings.

The post-merger partnership, which retains the name Enterprise Products Partners L.P., accesses the largest producing basins of natural gas, NGLs and crude oil in the U.S., and serves some of the largest consuming regions for natural gas, NGLs, refined products, crude oil and petrochemicals.  The post-merger partnership owns almost 48,000 miles of pipelines comprised of over 22,000 miles of NGL, refined product and petrochemical pipelines, over 20,000 miles of natural gas pipelines and more than 5,000 miles of crude oil pipelines.  The merged partnership’s logistical assets include approximately 200 MMBbls of NGL, refined product and crude oil storage capacity; 27 Bcf of natural gas storage capacity; one of the largest NGL import/export terminals in the U.S., located on the Houston Ship Channel; 60 NGL, refined product and chemical terminals spanning the U.S. from the west coast to the east coast; and crude oil import terminals on the Texas Gulf Coast.  The post-merger partnership owns interests in 17 fractionation plants with over 600 thousand barrels per day (“MBPD”) of net capacity; 25 natural gas processing plants with a net capacity of approximately 9 Bcf/d; and 3 butane isomerization facilities with a capacity of 116 MBPD. The post-merger partnership is also one of the largest inland tank barge companies in the U.S.

The merger transactions will be accounted for as a reorganization of entities under common control.  The financial and operating activities of Enterprise Products Partners, TEPPCO and Enterprise GP Holdings and their respective general partners, and EPCO and its privately held subsidiaries, are under the common control of Dan L. Duncan.

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ENTERPRISE PRODUCTS GP, LLC

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED BALANCE SHEET

In connection with the TEPPCO Merger, EPO commenced offers in September 2009 to exchange all of TEPPCO’s outstanding notes for a corresponding series of new EPO notes.  The purpose of the exchange offer was to simplify our capital structure following the TEPPCO Merger.  The exchanges were completed on October 27, 2009.  The new EPO notes are guaranteed by Enterprise Products Partners L.P.    As presented in the following table, the aggregate principal amount of the TEPPCO notes was $2 billion, of which $1.95 billion was exchanged:

TEPPCO Notes Exchanged	Principal Amount Exchanged		Principal Amount Not Exchanged
7.625% Senior Notes due 2012	$	490.5	$	9.5
6.125% Senior Notes due 2013		182.5		17.5
5.90% Senior Notes due 2013		237.6		12.4
6.65% Senior Notes due 2018		349.7		0.3
7.55% Senior Notes due 2038		399.6		0.4
7.00% Junior Fixed/Floating Subordinated Notes due 2067		285.8		14.2
Total	$	1,945.7	$	54.3

The EPO notes issued in the exchange will be recorded at the same carrying value as the TEPPCO notes being replaced.  Accordingly, we will recognize no gain or loss for accounting purposes related to this exchange.  All note exchange direct costs paid to third parties will be expensed.

In addition to the debt exchange, we gained approval from the requisite TEPPCO noteholders to eliminate substantially all of the restrictive covenants and reporting requirements associated with the remaining TEPPCO notes.

Upon the consummation of the TEPPCO Merger, EPO repaid and terminated indebtedness under TEPPCO’s Revolving Credit Facility.

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