Enterprise Products Partners (EPD) 8-K Recast of Certain Sections of the 2008 Annual Report on Form 10-K

EXHIBIT 99.3

ENTERPRISE PRODUCTS PARTNERS L.P.

RECAST OF ITEM 1 FROM QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTERLY PERIOD ENDING SEPTEMBER 30, 2009

Recast of Item 1.  Financial Statements.

INDEX TO SUPPLEMENTAL FINANCIAL STATEMENTS

Unaudited Supplemental Condensed Consolidated Balance Sheets	2
Unaudited Supplemental Condensed Statements of Consolidated Operations	3
Unaudited Supplemental Condensed Statements of Consolidated Comprehensive Income	4
Unaudited Supplemental Condensed Statements of Consolidated Cash Flows	5
Unaudited Supplemental Condensed Statements of Consolidated Equity	6
Notes to Unaudited Supplemental Condensed Consolidated Financial Statements:
1.  Partnership Organization and Basis of Presentation	7
2.  General Accounting Matters	9
3.  Accounting for Equity Awards	11
4.  Derivative Instruments, Hedging Activities and Fair Value Measurements	16
5.  Inventories	25
6.  Property, Plant and Equipment	26
7.  Investments in Unconsolidated Affiliates	28
8.  Business Combinations	29
9.  Intangible Assets and Goodwill	30
10.  Debt Obligations	32
11.  Equity and Distributions	35
12.  Business Segments	39
13.  Related Party Transactions	43
14.  Earnings Per Unit	47
15.  Commitments and Contingencies	48
16.  Significant Risks and Uncertainties	52
17.  Supplemental Cash Flow Information	54
18.  Supplemental Condensed Consolidated Financial Information of EPO	54
19.  Subsequent Events	55

1 

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED SUPPLEMENTAL CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

	September 30,			December 31,
ASSETS	2009			2008
Current assets:
Cash and cash equivalents	$	77.3		$	61.7
Restricted cash		102.8			203.8
Accounts and notes receivable – trade, net of allowance for doubtful accounts  of $17.0 at September 30, 2009 and $17.7 at December 31, 2008		2,579.6			2,028.5
Accounts receivable – related parties		9.6			35.3
Inventories (see Note 5)		1,220.6			405.0
Derivative assets (see Note 4)		199.5			218.6
Prepaid and other current assets		168.0			149.8
Total current assets		4,357.4			3,102.7
Property, plant and equipment, net		17,297.0			16,732.8
Investments in unconsolidated affiliates		899.3			911.9
Intangible assets, net of accumulated amortization of $765.6 at    September 30, 2009 and $675.1 at December 31, 2008		1,093.2			1,182.9
Goodwill		2,018.3			2,019.6
Deferred tax asset		1.1			0.4
Other assets		264.9			261.3
Total assets	$	25,931.2		$	24,211.6
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable – trade	$	399.7		$	388.9
Accounts payable – related parties		44.2			17.4
Accrued product payables		2,657.4			1,845.7
Accrued interest payable		163.1			188.3
Other accrued expenses		55.1			65.7
Derivative liabilities (see Note 4)		264.6			302.9
Other current liabilities		263.5			292.3
Total current liabilities		3,847.6			3,101.2
Long-term debt: (see Note 10)
Senior debt obligations – principal		10,404.0			10,030.1
Junior subordinated notes – principal		1,532.7			1,532.7
Other		62.5			75.1
Total long-term debt		11,999.2			11,637.9
Deferred tax liabilities		69.6			66.1
Other long-term liabilities		151.2			110.5
Commitments and contingencies
Equity: (see Note 11)
Enterprise Products Partners L.P. partners’ equity:
Limited Partners:
Common units (475,293,998 units outstanding at September 30, 2009   and 439,354,731 units outstanding at December 31, 2008)		6,670.8			6,036.9
Restricted common units (2,658,850 units outstanding at September 30, 2009   and 2,080,600 units outstanding at December 31, 2008)		34.1			26.2
General partner		136.6			123.6
Accumulated other comprehensive loss		(67.1	)		(97.2	)
Total Enterprise Products Partners L.P. partners’ equity		6,774.4			6,089.5
Noncontrolling interest		3,089.2			3,206.4
Total equity		9,863.6			9,295.9
Total liabilities and equity	$	25,931.2		$	24,211.6

See Notes to Unaudited Supplemental Condensed Consolidated Financial Statements.

2 

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED SUPPLEMENTAL CONDENSED STATEMENTS OF

CONSOLIDATED OPERATIONS

 (Dollars in millions, except per unit amounts)

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2009			2008			2009			2008
Revenues:
Third parties	$	6,679.0		$	10,246.1		$	16,688.4		$	28,812.4
Related parties		110.4			253.0			422.2			731.7
Total revenues (see Note 12)		6,789.4			10,499.1			17,110.6			29,544.1
Costs and expenses:
Operating costs and expenses:
Third parties		6,128.2			9,875.1			15,046.4			27,593.5
Related parties		267.6			199.2			750.5			556.7
Total operating costs and expenses		6,395.8			10,074.3			15,796.9			28,150.2
General and administrative costs:
Third parties		26.9			12.4			56.3			29.4
Related parties		25.4			21.5			77.0			71.0
Total general and administrative costs		52.3			33.9			133.3			100.4
Total costs and expenses		6,448.1			10,108.2			15,930.2			28,250.6
Equity in income of unconsolidated affiliates		15.0			10.1			32.0			31.8
Operating income		356.3			401.0			1,212.4			1,325.3
Other income (expense):
Interest expense		(161.0	)		(137.0	)		(472.0	)		(396.3	)
Interest income		0.3			2.5			1.9			6.2
Other, net		(0.1	)		(0.7	)		0.3			(1.0	)
Total other expense, net		(160.8	)		(135.2	)		(469.8	)		(391.1	)
Income before provision for income taxes		195.5			265.8			742.6			934.2
Provision for income taxes		(7.7	)		(7.7	)		(26.8	)		(20.1	)
Net income		187.8			258.1			715.8			914.1
Net (income) loss attributable to noncontrolling interest		25.1			(55.0	)		(91.0	)		(188.1	)
Net income attributable to Enterprise Products Partners L.P.	$	212.9		$	203.1		$	624.8		$	726.0
Net income allocated to:
Limited partners	$	171.3		$	167.6		$	504.6		$	620.5
General partner	$	41.6		$	35.5		$	120.2		$	105.5
Basic and diluted earnings per unit (see Note 14)	$	0.36		$	0.38		$	1.09		$	1.41

See Notes to Unaudited Supplemental Condensed Consolidated Financial Statements.

3 

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED SUPPLEMENTAL CONDENSED STATEMENTS OF CONSOLIDATED

COMPREHENSIVE INCOME (LOSS)

(Dollars in millions)

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2009			2008			2009			2008
Net income	$	187.8		$	258.1		$	715.8		$	914.1
Other comprehensive income (loss):
Cash flow hedges:
Commodity derivative instrument losses during period		(8.3	)		(236.1	)		(146.9	)		(143.3	)
Reclassification adjustment for losses included in net income related to commodity derivative instruments		77.8			43.9			176.3			50.5
Interest rate derivative instrument gains (losses) during period		(8.0	)		(1.1	)		7.1			(46.1	)
Reclassification adjustment for (gains) losses included in net income related to interest rate derivative instruments		2.8			--			7.6			(2.5	)
Foreign currency derivative gains (losses)		0.2			--			(10.3	)		(1.3	)
Total cash flow hedges		64.5			(193.3	)		33.8			(142.7	)
Foreign currency translation adjustment		1.1			0.4			1.7			0.5
Change in funded status of pension and postretirement plans, net of tax		--			--			--			(0.3	)
Total other comprehensive income (loss)		65.6			(192.9	)		35.5			(142.5	)
Comprehensive income		253.4			65.2			751.3			771.6
Comprehensive (income) loss attributable to noncontrolling interest		23.3			(78.0	)		(96.4	)		(179.7	)
Comprehensive income (loss) attributable to Enterprise Products Partners L.P.	$	276.7		$	(12.8	)	$	654.9		$	591.9

See Notes to Unaudited Supplemental Condensed Consolidated Financial Statements.

4 

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED SUPPLEMENTAL CONDENSED STATEMENTS OF

CONSOLIDATED CASH FLOWS

(Dollars in millions)

	For the Nine Months
	Ended September 30,
	2009			2008
Operating activities:
Net income	$	715.8		$	914.1
Adjustments to reconcile net income to net cash  flows provided by operating activities:
Depreciation, amortization and accretion		619.9			540.7
Non-cash impairment charge		26.3			--
Equity in income of unconsolidated affiliates		(32.0	)		(31.8	)
Distributions received from unconsolidated affiliates		55.2			50.5
Operating lease expense paid by EPCO, Inc.		0.5			1.6
Gain from asset sales and related transactions		(0.5	)		(2.0	)
Loss on forfeiture of investment in Texas Offshore Port System		68.4			--
Loss on early extinguishment of debt		--			8.7
Deferred income tax expense		2.5			5.6
Changes in fair market value of derivative instruments		10.6			4.9
Effect of pension settlement recognition		(0.1	)		(0.1	)
Net effect of changes in operating accounts (see Note 17)		(574.9	)		(241.1	)
Net cash flows provided by operating activities		891.7			1,251.1
Investing activities:
Capital expenditures		(1,100.4	)		(1,844.7	)
Contributions in aid of construction costs		12.8			22.5
Decrease (increase) in restricted cash		100.8			(112.2	)
Cash used for business combinations		(74.5	)		(408.8	)
Acquisition of intangible assets		(1.4	)		(5.4	)
Investments in unconsolidated affiliates		(13.9	)		(23.9	)
Proceeds from asset sales and related activities		2.9			8.0
Other investing activities		1.5			--
Cash used in investing activities		(1,072.2	)		(2,364.5	)
Financing activities:
Borrowings under debt agreements		4,963.8			10,209.3
Repayments of debt		(4,594.0	)		(8,266.7	)
Debt issuance costs		(5.5	)		(18.5	)
Cash distributions paid to partners		(860.6	)		(770.9	)
Cash distributions paid to noncontrolling interest (see Note 11)		(324.5	)		(276.0	)
Net cash proceeds from issuance of common units		878.2			57.2
Cash contributions from noncontrolling interest (see Note 11)		140.9			271.3
Acquisition of treasury units		(1.8	)		(0.8	)
Monetization of interest rate derivative instruments		--			(74.2	)
Cash provided by financing activities		196.5			1,130.7
Effect of exchange rate changes on cash		(0.4	)		(0.1	)
Net change in cash and cash equivalents		16.0			17.3
Cash and cash equivalents, January 1		61.7			51.3
Cash and cash equivalents, September 30	$	77.3		$	68.5

See Notes to Unaudited Supplemental Condensed Consolidated Financial Statements.

5 

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED SUPPLEMENTAL CONDENSED STATEMENTS OF CONSOLIDATED EQUITY

(See Note 11 for Unit History and Detail of Changes in Limited Partners’ Equity)

(Dollars in millions)

	Enterprise Products Partners L.P.
							Accumulated
							Other
	Limited			General			Comprehensive			Noncontrolling
	Partners			Partner			Loss			Interest			Total
Balance, December 31, 2008	$	6,063.1		$	123.6		$	(97.2	)	$	3,206.4		$	9,295.9
Net income		504.6			120.2			--			91.0			715.8
Operating leases paid by EPCO, Inc.		0.5			--			--			--			0.5
Cash distributions paid to partners		(735.2	)		(124.9	)		--			--			(860.1	)
Unit option reimbursements to EPCO, Inc.		(0.5	)		--			--			--			(0.5	)
Cash distributions paid to noncontrolling interest (see Note 11)		--			--			--			(324.5	)		(324.5	)
Net cash proceeds from issuance of common units		860.2			17.5			--			--			877.7
Cash proceeds from exercise of unit options		0.5			--			--			--			0.5
Cash contributions from noncontrolling interest (see Note 11)		--			--			--			140.9			140.9
Deconsolidation of Texas Offshore Port System		--			--			--			(33.4	)		(33.4	)
Amortization of equity awards		13.5			0.2			--			3.1			16.8
Acquisition of treasury units		(1.8	)		--			--			--			(1.8	)
Foreign currency translation adjustment		--			--			1.7			--			1.7
Cash flow hedges		--			--			28.4			5.4			33.8
Other		--			--			--			0.3			0.3
Balance, September 30, 2009	$	6,704.9		$	136.6		$	(67.1	)	$	3,089.2		$	9,863.6

	Enterprise Products Partners L.P.
							Accumulated
							Other
	Limited			General			Comprehensive			Noncontrolling
	Partners			Partner			Income (Loss)			Interest			Total
Balance, December 31, 2007	$	5,992.9		$	122.3		$	19.1			2,882.2		$	9,016.5
Net income		620.5			105.5			--			188.1			914.1
Operating leases paid by EPCO, Inc.		1.6			--			--			--			1.6
Cash distributions paid to partners		(663.9	)		(106.4	)		--			--			(770.3	)
Unit option reimbursements to EPCO, Inc.		(0.6	)		--			--			--			(0.6	)
Cash distributions paid to noncontrolling interest (see Note 11)		--			--			--			(276.0	)		(276.0	)
Net cash proceeds from issuance of common units		55.4			1.1			--			--			56.5
Issuance of units by TEPPCO in connection with
Cenac acquisition		--			--			--			186.6			186.6
Cash proceeds from exercise of unit options		0.7			--			--			--			0.7
Cash contributions from noncontrolling interest (see Note 11)		--			--			--			271.3			271.3
Amortization of equity awards		8.7			0.1			--			1.1			9.9
Interest acquired from noncontrolling interest		--			--			--			(7.6	)		(7.6	)
Acquisition of treasury units		(0.8	)		--			--			--			(0.8	)
Foreign currency translation adjustment		--			--			0.5			--			0.5
Change in funded status of pension and postretirement plans		--			--			(0.3	)		--			(0.3	)
Cash flow hedges		--			--			(134.4	)		(8.3	)		(142.7	)
Other		--			--			--			0.5			0.5
Balance, September 30, 2008	$	6,014.5		$	122.6		$	(115.1	)	$	3,237.9		$	9,259.9

See Notes to Unaudited Supplemental Condensed Consolidated Financial Statements.

6 

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.  Partnership Organization and Basis of Presentation

Partnership Organization

Enterprise Products Partners L.P. is a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.”  Unless the context requires otherwise, references to “we,” “us,” “our” or “Enterprise Products Partners” are intended to 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.

We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO, Inc. (“EPCO”).  We conduct substantially all of our business through our wholly owned subsidiary, Enterprise Products Operating LLC (“EPO”).  We are owned 98% by our limited partners and 2% by Enterprise Products GP, LLC (our general partner, referred to as “EPGP”).  EPGP is owned 100% by Enterprise GP Holdings L.P. (“Enterprise GP Holdings”), a publicly traded limited partnership, the units of which are listed on the NYSE under the ticker symbol “EPE.”  The general partner of Enterprise GP Holdings is EPE Holdings, LLC (“EPE Holdings”), a wholly owned subsidiary of Dan Duncan LLC, all of the membership interests of which are owned by Dan L. Duncan.  We, EPGP, Enterprise GP Holdings, EPE Holdings and Dan Duncan LLC are affiliates and under the common control of Dan L. Duncan, the Group Co-Chairman and controlling shareholder of EPCO.

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 our subsidiaries.  On October 26, 2009, we completed the mergers with TEPPCO and TEPPCO GP (such related mergers referred to herein individually and together as the “TEPPCO Merger”).  See Note 19 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 a noncontrolling interest 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.

For financial reporting purposes, we consolidate the financial statements of Duncan Energy Partners L.P. (“Duncan Energy Partners”) with those of our own and reflect its operations in our business segments.  We control Duncan Energy Partners through our ownership of its general partner, DEP Holdings, LLC (“DEP GP”).  Also, due to common control of the entities by Dan L. Duncan, the initial consolidated balance sheet of Duncan Energy Partners reflects our historical carrying basis in each of the subsidiaries contributed to Duncan Energy Partners.  Public ownership of Duncan Energy Partners’ net assets and earnings are presented as a component of noncontrolling interest in our supplemental consolidated financial statements.  The borrowings of Duncan Energy Partners are presented as part of our consolidated debt; however, neither Enterprise Products Partners L.P. nor EPO have any obligation for the payment of interest or repayment of borrowings incurred by Duncan Energy Partners.

7 

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Basis of Presentation

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 supplemental consolidated financial statements 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 supplemental consolidated financial statements prior to the TEPPCO Merger reflect 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 supplemental financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”).  The financial statements 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.

As previously noted, the TEPPCO Merger was accounted for as a reorganization of entities under common control.  The following information is provided to reconcile total revenues and total gross operating margin as currently presented for the three and nine months ended September 30, 2009 and 2008, with those we previously presented.  There was no change in net income attributable to Enterprise Products Partners L.P. for such periods since net income attributable to TEPPCO and TEPPCO GP was allocated to noncontrolling interests.  Additionally, there was no change in our reported earnings per unit for such periods.  See Note 12 for information regarding total segment gross operating margin, which is a non-generally accepted accounting principle (“non-GAAP”) financial measure of segment performance.

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2009			2008			2009			2008
Total revenues, as previously reported	$	4,596.1		$	6,297.9		$	11,527.1		$	18,322.1
Revenues from TEPPCO		2,205.3			4,205.7			5,576.1			11,194.7
Revenues from Jonah Gas Gathering Company (“Jonah”) (1)		60.2			58.7			180.8			177.0
Eliminations (2)		(72.2	)		(63.2	)		(173.4	)		(149.7	)
Total revenues, as currently reported	$	6,789.4		$	10,499.1		$	17,110.6		$	29,544.1
Total segment gross operating margin, as previously reported	$	560.9		$	478.9		$	1,618.8		$	1,535.5
Gross operating margin from TEPPCO		62.5			122.9			309.9			379.7
Gross operating margin from Jonah		46.6			40.7			137.8			121.9
Eliminations (3)		(31.3	)		(26.9	)		(91.6	)		(79.5	)
Total segment gross operating margin, as currently reported	$	638.7		$	615.6		$	1,974.9		$	1,957.6
(1)Prior to the TEPPCO Merger, we and TEPPCO were joint venture partners in Jonah. As a result of the TEPPCO Merger, Jonah became a consolidated subsidiary. (2)Represents the eliminations of revenues between us, TEPPCO and Jonah. (3)Represents equity earnings from Jonah recorded by us and TEPPCO prior to the merger.

8 

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 that were previously identified as minority interest in our financial statements.  The new guidance requires, among other things, that (i) noncontrolling interests be presented as a component of equity on our consolidated balance sheet (i.e., elimination of the “mezzanine” presentation previously used for minority interest); (ii) elimination of minority interest amounts as a deduction in deriving net income or loss and, as a result, that net income or loss be allocated between controlling and noncontrolling interests; and (iii) comprehensive income or loss be allocated between controlling and noncontrolling interest.  Earnings per unit amounts are not affected by these changes.  See Note 2 for additional information regarding the establishment of the ASC by the Financial Accounting Standards Board (“FASB”).  See Note 11 for additional information regarding noncontrolling interest.

The new presentation and disclosure requirements pertaining to noncontrolling interests have been applied retroactively to the supplemental consolidated financial statements and notes included in this  Exhibit 99.3.  As a result, net income reported for the three and nine months ended September 30, 2008 in these supplemental financial statements is higher than that disclosed previously; however, the allocation of such net income results in our unitholders, general partner and noncontrolling interests (i.e., the former minority interest) receiving the same amounts as they did previously.

General.  Our results of operations for the three and nine months ended September 30, 2009 are not necessarily indicative of results expected for the full year.

Essentially all of our assets, liabilities, revenues and expenses are recorded at EPO’s level in our supplemental consolidated financial statements.  Enterprise Products Partners L.P. acts as guarantor of certain of EPO’s debt obligations.  See Note 18 for supplemental condensed consolidated financial information of EPO.

In our opinion, the accompanying Unaudited Supplemental Condensed Consolidated Financial Statements include all adjustments consisting of normal recurring accruals necessary for fair presentation.  Although we believe the disclosures in these supplemental financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual supplemental financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”).  These Unaudited Supplemental Condensed Consolidated Financial Statements and Notes thereto should be read in conjunction with the Audited Supplemental Consolidated Financial Statements and Notes thereto included in this Current Report on Form 8-K under Exhibit 99.2.

Note 2.  General Accounting Matters

Estimates

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

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

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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 the dates indicated:

	September 30, 2009					December 31, 2008
	Carrying			Fair		Carrying		Fair
Financial Instruments	Value			Value		Value		Value
Financial assets:
Cash and cash equivalents and restricted cash	$	180.1		$	180.1	$	265.5	$	265.5
Accounts receivable		2,589.2	��		2,589.2		2,063.8		2,063.8
Financial liabilities:
Accounts payable and accrued expenses		3,319.5			3,319.5		2,506.0		2,506.0
Other current liabilities		263.5			263.5		292.3		292.3
Fixed-rate debt (principal amount)		9,986.7			10,450.6		9,704.3		8,192.2
Variable-rate debt		1,950.0			1,950.0		1,858.5		1,858.5

Recent Accounting Developments

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

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 in our supplemental consolidated financial statements 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 financial statements or related disclosures.

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 financial statements 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 financial statements 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 financial statements.

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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 financial statements.

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 and December 31, 2008, our restricted cash amounts were $102.8 million and $203.8 million, respectively.  See Note 4 for additional information regarding derivative instruments and hedging activities.

Subsequent Events

We have evaluated subsequent events through November 9, 2009, which is the original filing date of our Quarterly Report on Form 10-Q for the nine months ended September 30, 2009.

Note 3.  Accounting for Equity Awards

Certain key employees of EPCO participate in long-term incentive compensation plans managed by EPCO.  The compensation expense we record related to equity awards is based on an allocation of the total cost of such incentive plans to 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, results of operations or cash flows for the periods presented.  The amount of equity-based compensation allocable to our businesses was $7.0 million and $5.0 million for the three months ended September 30, 2009 and 2008, respectively.  For the nine months ended September 30, 2009 and 2008, the amount of equity-based compensation allocable to our businesses was $17.4 million and $12.5 million, respectively.

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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 our 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 our 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 our common units of 10%; and (v) expected unit price volatility on our common units of 72.76%.

The total intrinsic value of option awards exercised during the three months ended September 30, 2009 and 2008 was $0.3 million and $0.1 million, respectively.  For each of the nine months ended September 30, 2009 and 2008, the total intrinsic value of option awards exercised was $0.6 million.  At September 30, 2009, the estimated total unrecognized compensation cost related to nonvested unit option awards granted under the EPCO 1998 Plan was $1.1 million.  We will recognize our share of these costs in accordance with the EPCO administrative services agreement (the “ASA”) (see Note 13) over a weighted-average period of 1.8 years.

During the nine months ended September 30, 2009 and 2008, we received cash of $0.5 million and $0.7 million, respectively, from the exercise of option awards granted under the EPCO 1998 Plan.  Conversely, our option-related reimbursements to EPCO during each of these periods were $0.5 million and $0.6 million, respectively.

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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 our 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.  At September 30, 2009, the estimated total unrecognized compensation cost related to nonvested restricted unit awards granted under the EPCO 1998 Plan was $39.6 million.  We expect to recognize our share of this cost over a weighted-average period of 2.5 years in accordance with the ASA.

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 our 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 our 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 our common units of 9.37%; (v) expected weighted-average unit price volatility on our 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.

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At September 30, 2009, the estimated total unrecognized compensation cost related to nonvested unit option awards granted under the EPD 2008 LTIP was $6.6 million.  We expect to recognize our share of this cost over a weighted-average period of 3.4 years in accordance with the ASA.

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 and December 31, 2008, we had accrued an immaterial liability for compensation related to these phantom unit awards.

DEP GP Unit Appreciation Rights

At September 30, 2009 and December 31, 2008, 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 and December 31, 2008, 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 and December 31, 2008, TEPPCO had accrued liability balances of $0.1 million and $0.4 million, respectively, for compensation related to the TEPPCO 1999 Plan.

Effective upon the consummation of the TEPPCO Merger (see Note 19), 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 our 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 19), 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 our awards except for UARs and phantom

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unit awards held by non-employee directors of TEPPCO GP which were settled in cash.  The vesting terms and other provisions remain unchanged.

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.

At September 30, 2009, the estimated total unrecognized compensation cost related to nonvested option awards granted under the TEPPCO 2006 LTIP was $1.2 million.  TEPPCO expects to recognize its share of this cost over a weighted-average period of 3.2 years in accordance with the ASA.

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.  At September 30, 2009, the estimated total unrecognized compensation cost related to restricted unit awards granted under the TEPPCO 2006 LTIP was $5.3 million.  TEPPCO expects to recognize its share of this cost over a weighted-average period of 2.9 years in accordance with the ASA.

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

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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 and December 31, 2008, 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

As of September 30, 2009, the estimated total unrecognized compensation cost related to the seven Employee Partnerships was $40.6 million.  We will recognize our share of these costs in accordance with the ASA over a weighted-average period of 4.2 years.

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 our common units in connection with the TEPPCO Merger.  See Note 19 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 - In a fair value hedge, all gains and losses (of both the derivative instrument and the hedged item) are recognized in income during the period of change.

§   Variable cash flows of a forecasted transaction - In a cash flow hedge, the effective portion of the hedge is reported in other comprehensive income (“OCI”) and is reclassified into earnings when the forecasted transaction affects earnings.

§   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.

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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

The changes in fair value of the fair value interest rate swaps and the related hedged items were recorded on the balance sheet with the offset recorded as interest expense.  This resulted in an increase of interest expense of $2.5 million and $3.1 million, respectively, for the three and nine months ended September 30, 2009.

At times, we may use treasury lock derivative instruments to hedge the underlying U.S. treasury rates related to forecasted issuances of debt.  As cash flow hedges, gains or losses on these instruments are recorded in OCI and amortized to earnings using the effective interest method over the estimated term of the underlying fixed-rate debt.  In March 2008, we terminated treasury locks having a combined notional amount of $950.0 million.  On April 1, 2008, we terminated treasury locks having a notional amount of $250.0 million.  We recognized an aggregate loss of $43.9 million in OCI during the first quarter of 2008 related to these terminations.  There were no losses recognized during the second quarter of 2008 in connection with such terminations.

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 and gains and losses on interest rate derivative instruments and related hedged items, see “Tabular Presentation of Fair Value Amounts, and Gains and Losses on Derivative Instruments and Related Hedged Items” within this Note 4.

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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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NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

At September 30, 2009, this program had hedged future estimated gross margins (before plant operating expenses) of $131.0 million on 5.0 MMBbls of forecasted NGL forward sales transactions extending through December 2009.

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 and gains and losses on commodity derivative instruments and related hedged items, see “Tabular Presentation of Fair Value Amounts, and Gains and Losses 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 and gains and losses on foreign currency derivative instruments and related hedged items, see “Tabular Presentation of Fair Value Amounts, and Gains and Losses on Derivative Instruments and Related Hedged Items” within this Note 4.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 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, and Gains and Losses on

   Derivative Instruments and Related Hedged Items

The following table provides a balance sheet overview of our derivative assets and liabilities at the dates indicated:

	Asset Derivatives						Liability Derivatives
	September 30, 2009			December 31, 2008			September 30, 2009			December 31, 2008
	Balance Sheet	Fair		Balance Sheet	Fair		Balance Sheet	Fair		Balance Sheet	Fair
	Location	Value		Location	Value		Location	Value		Location	Value
Derivatives designated as hedging instruments:
Interest rate derivatives	Derivative assets	$	23.2	Derivative assets	$	7.8	Derivative liabilities	$	6.0	Derivative liabilities	$	5.9
Interest rate derivatives	Other assets		33.4	Other assets		38.9	Other liabilities		2.0	Other liabilities		3.9
Total interest rate derivatives			56.6			46.7			8.0			9.8
Commodity derivatives	Derivative assets		51.9	Derivative assets		150.6	Derivative liabilities		133.2	Derivative liabilities		253.5
Commodity derivatives	Other assets		0.2	Other assets		--	Other liabilities		2.1	Other liabilities		0.2
Total commodity derivatives (1)			52.1			150.6			135.3			253.7
Foreign currency derivatives (2)	Derivative assets		0.3	Derivative assets		9.3	Derivative liabilities		--	Derivative liabilities		--
Total derivatives
designated as hedging
instruments		$	109.0		$	206.6		$	143.3		$	263.5
Derivatives not designated as hedging instruments:
Commodity derivatives	Derivative assets	$	124.1	Derivative assets	$	50.9	Derivative liabilities	$	125.4	Derivative liabilities	$	43.4
Commodity derivatives	Other assets		1.1	Other assets		--	Other liabilities		2.4	Other liabilities		--
Total commodity derivatives			125.2			50.9			127.8			43.4
Foreign currency derivatives	Derivative assets		--	Derivative assets		--	Derivative liabilities		--	Derivative liabilities		0.1
Total derivatives not
designated as hedging
instruments		$	125.2		$	50.9		$	127.8		$	43.5
(1)  Represent commodity derivative 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.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following tables present the effect of our derivative instruments designated as fair value hedges on our Unaudited Supplemental Condensed Statements of Consolidated Operations for the periods indicated:

Derivatives in
Fair Value		Gain/(Loss) Recognized in
Hedging Relationships	Location	Income on Derivative
		For the Three Months				For the Nine Months
		Ended September 30,				Ended September 30,
		2009		2008		2009			2008
Interest rate derivatives	Interest expense	$	12.0	$	4.2	$	(4.2	)	$	(1.7	)
Commodity derivatives	Revenue		0.6		--		(0.1	)		--
Total		$	12.6	$	4.2	$	(4.3	)	$	(1.7	)

Derivatives in
Fair Value		Gain/(Loss) Recognized in
Hedging Relationships	Location	Income on Hedged Item
		For the Three Months						For the Nine Months
		Ended September 30,						Ended September 30,
		2009			2008			2009		2008
Interest rate derivatives	Interest expense	$	(14.5	)	$	(4.2	)	$	1.1	$	1.7
Commodity derivatives	Revenue		(0.5	)		--			0.6		--
Total		$	(15.0	)	$	(4.2	)	$	1.7	$	1.7

The following tables present the effect of our derivative instruments designated as cash flow hedges on our Unaudited Supplemental Condensed Statements of Consolidated Operations for the periods indicated:

Derivatives in	Change in Value
Cash Flow	Recognized in OCI on
Hedging Relationships	Derivative (Effective Portion)
	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2009			2008			2009			2008
Interest rate derivatives	$	(8.0	)	$	(1.1	)	$	7.1		$	(46.1	)
Commodity derivatives – Revenue		(21.3	)		(17.4	)		44.5			(49.4	)
Commodity derivatives – Operating costs and expenses		13.0			(218.7	)		(191.4	)		(93.9	)
Foreign currency derivatives		0.2			--			(10.3	)		(1.3	)
Total	$	(16.1	)	$	(237.2	)	$	(150.1	)	$	(190.7	)

Derivatives in	Location of Gain/(Loss)	Amount of Gain/(Loss)
Cash Flow	Reclassified from AOCI	Reclassified from AOCI
Hedging Relationships	into Income (Effective Portion)	to Income (Effective Portion)
		For the Three Months						For the Nine Months
		Ended September 30,						Ended September 30,
		2009			2008			2009			2008
Interest rate derivatives	Interest expense	$	(2.8	)	$	--		$	(7.6	)	$	2.5
Commodity derivatives	Revenue		(12.5	)		(32.6	)		7.2			(58.0	)
Commodity derivatives	Operating costs and expenses		(65.3	)		(11.3	)		(183.5	)		7.5
Total		$	(80.6	)	$	(43.9	)	$	(183.9	)	$	(48.0	)

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Location of Gain/(Loss)	Amount of Gain/(Loss)
Derivatives in	Recognized in Income	Recognized in Income on
Cash Flow	on Ineffective Portion	Ineffective Portion of
Hedging Relationships	of Derivative	Derivative
		For the Three Months						For the Nine Months
		Ended September 30,						Ended September 30,
		2009			2008			2009			2008
Interest rate derivatives	Interest expense	$	--		$	--		$	--		$	(3.6	)
Commodity derivatives	Revenue		0.8			--			0.1			--
Commodity derivatives	Operating costs and expenses		(1.0	)		(5.6	)		(2.3	)		(2.9	)
Total		$	(0.2	)	$	(5.6	)	$	(2.2	)	$	(6.5	)

Over the next twelve months, we expect to reclassify $11.4 million of accumulated other comprehensive loss (“AOCI”) attributable to interest rate derivative instruments to earnings as an increase to interest expense. Likewise, we expect to reclassify $81.3 million of AOCI attributable to commodity derivative instruments to earnings, $32.1 million as an increase in operating costs and expenses and $49.2 million as a reduction in revenues.

The following table presents the effect of our derivative instruments not designated as hedging instruments on our Unaudited Supplemental Condensed Statements of Consolidated operations for the periods indicated:

Derivatives Not Designated		Gain/(Loss) Recognized in
as  Hedging Instruments	Location	Income on Derivative
		For the Three Months					For the Nine Months
		Ended September 30,					Ended September 30,
		2009			2008		2009			2008
Commodity derivatives (1)	Revenue	$	(5.4	)	$	38.3	$	26.6		$	35.9
Commodity derivatives	Operating costs and expenses		--			1.9		(0.1	)		(7.1	)
Total		$	(5.4	)	$	40.2	$	26.5		$	28.8
(1)  Amounts for the three and nine months ended September 30, 2009 include $0.9 million and $3.8 million of gains on derivatives that were excluded from fair value hedging relationships, respectively.

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.

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.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

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

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

	For the Nine Months
	Ended September 30,
	2009			2008
Balance, January 1	$	32.4		$	(5.1	)
Total gains (losses) included in:
Net income (1)		12.9			(1.8	)
Other comprehensive income (loss)		1.5			2.4
Purchases, issuances, settlements		(12.3	)		1.9
Balance, March 31		34.5			(2.6	)
Total gains (losses) included in:
Net income (1)		7.7			0.3
Other comprehensive income		(23.1	)		(2.4	)
Purchases, issuances, settlements		(8.1	)		--
Transfer in/out of Level 3		(0.2	)		--
Balance, June 30		10.8			(4.7	)
Total gains (losses) included in:
Net income (1)		7.6			(0.6	)
Other comprehensive income		(10.1	)		23.1
Purchases, issuances, settlements		(6.7	)		2.2
Transfer in/out of Level 3		(2.3	)		--
Balance, September 30	$	(0.7	)	$	20.0
(1)  There were unrealized losses of $3.3 million and $3.5 million included in these amounts for the three and nine months ended September 30, 2009, respectively. There were unrealized gains of $1.5 million and $1.9 million included in these amounts for the three and nine months ended September 30, 2008, respectively.

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 period:

	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 during the third quarter of 2009.  In addition, we recorded an impairment charge of $1.3 million related to goodwill.  These charges are reflected in operating costs and expenses for the three and nine months ended September 30, 2009.  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 15 for information regarding a related $28.7 million charge for contractual obligations associated with the terminal assets.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.   This charge is included in operating costs and expenses for the nine months ended September 30, 2009.  The fair value adjustment was allocated to plant, property and equipment.

Note 5.  Inventories

Our inventory amounts were as follows at the dates indicated:

	September 30,		December 31,
	2009		2008
Working inventory (1)	$	533.3	$	211.9
Forward sales inventory (2)		687.3		193.1
Total inventory	$	1,220.6	$	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. 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.

Operating costs and expenses, as presented on our Unaudited Supplemental Condensed Statements of Consolidated Operations, include cost of sales amounts related to the sale of inventories.  Our costs of sales amounts were $5.58 billion and $9.4 billion for the three months ended September 30, 2009 and 2008, respectively.  For the nine months ended September 30, 2009 and 2008, our costs of sales amounts were $13.82 billion and $26.33 billion, respectively.  The decrease in cost of sales period-to-period is primarily due to lower energy commodity prices associated with our marketing activities.

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.  These non-cash charges are a component of cost of sales in the period they are recognized, and reflected in operating costs and expenses as presented on our Unaudited Supplemental Condensed Statements of Consolidated Operations.  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.  For the three months ended September 30, 2009 and 2008, we recognized LCM adjustments of $0.5 million and $45.8 million, respectively.  We recognized LCM adjustments of $8.6 million and $50.7 million for the nine months ended September 30, 2009 and 2008, respectively.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 6.  Property, Plant and Equipment

Our property, plant and equipment values and accumulated depreciation balances were as follows at the dates indicated:

	Estimated
	Useful Life		September 30,		December 31,
	in Years		2009		2008
Plants and pipelines (1)		3-45 (5)	$	16,958.5	$	15,266.7
Underground and other storage facilities (2)		5-40 (6)		1,254.9		1,203.9
Platforms and facilities (3)		20-31		637.6		634.8
Transportation equipment (4)		3-10		56.3		50.9
Marine vessels		20-30		527.0		453.0
Land				260.2		254.5
Construction in progress				1,226.8		2,015.4
Total				20,921.3		19,879.2
Less accumulated depreciation				3,624.3		3,146.4
Property, plant and equipment, net			$	17,297.0	$	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; 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).

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.  As a result, operating costs and expenses and net income for the nine months ended September 30, 2009 include a non-cash charge of $68.4 million.  This loss represents the forfeiture of our cumulative investment in TOPS through the date of dissociation and reflects our capital contributions to TOPS for construction in progress amounts.  

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.  See Note 15 for information regarding expense amounts recognized in the third quarter of 2009 in connection with a settlement agreement involving TOPS.

The following table summarizes our depreciation expense and capitalized interest amounts for the periods indicated:

	For the Three Months				For the Nine Months
	Ended September 30,				Ended September 30,
	2009		2008		2009		2008
Depreciation expense (1)	$	175.3	$	148.8	$	509.2	$	431.8
Capitalized interest (2)		11.4		21.6		39.5		67.1
(1)  Depreciation expense is a component of costs and expenses as presented in our Unaudited Supplemental Condensed Statements of Consolidated Operations. (2)  Capitalized interest increases the carrying value of the associated asset and reduces interest expense during the period it is recorded.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

We recorded $18.3 million and $20.6 million of non-cash impairment charges related to our Petrochemical & Refined Products Services segment during the three and nine months ended September 30, 2009, respectively.  See Note 4 for additional information.

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

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.  We incurred $13.6 million of costs through September 30, 2009 as a result of ARO settlement activities associated with certain pipeline laterals and a platform located in the Gulf of Mexico.

Our consolidated property, plant and equipment at September 30, 2009 and December 31, 2008 includes $26.3 million and $11.7 million, respectively, of asset retirement costs capitalized as an increase in the associated long-lived asset.  Based on information currently available, we estimate that accretion expense will approximate $0.9 million for the fourth quarter of 2009, $3.6 million for each of 2010 and 2011, $3.9 million for 2012 and $4.2 million for 2013.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 the dates indicated.

	Ownership
	Percentage at
	September 30,		September 30,		December 31,
	2009		2009		2008
NGL Pipelines & Services:
Venice Energy Service Company, L.L.C.		13.1%	$	33.1	$	37.7
K/D/S Promix, L.L.C. (“Promix”)		50%		47.8		46.4
Baton Rouge Fractionators LLC		32.2%		23.6		24.2
Skelly-Belvieu Pipeline Company, L.L.C. (“Skelly-Belvieu”)		49%		37.4		36.0
Onshore Natural Gas Pipelines & Services:
Evangeline (1)		49.5%		5.4		4.5
White River Hub, LLC		50%		27.1		21.4
Onshore Crude Oil Pipelines & Services:
Seaway Crude Pipeline Company (“Seaway”)		50%		181.0		186.2
Offshore Pipelines & Services:
Poseidon Oil Pipeline, L.L.C. (“Poseidon”)		36%		61.3		60.2
Cameron Highway Oil Pipeline Company (“Cameron Highway”)		50%		243.2		250.9
Deepwater Gateway, L.L.C.		50%		102.8		104.8
Neptune Pipeline Company, L.L.C. (“Neptune”)		25.7%		54.4		52.7
Nemo Gathering Company, LLC		33.9%		--		0.4
Petrochemical & Refined Products Services:
Baton Rouge Propylene Concentrator, LLC		30%		11.4		12.6
La Porte (2)		50%		3.5		3.9
Centennial Pipeline LLC (“Centennial”)		50%		66.8		69.7
Other		25%		0.5		0.3
Total			$	899.3	$	911.9
(1)  Refers to our ownership interests in Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp., collectively. (2)  Refers to our ownership interests in La Porte Pipeline Company, L.P. and La Porte GP, LLC, collectively.

On occasion, the price we pay to 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 unconsolidated affiliates.  At September 30, 2009 and December 31, 2008, our investments in Promix, Skelly-Belvieu, La Porte, Neptune, Poseidon, Cameron Highway, Seaway and Centennial included excess cost amounts totaling $70.5 million and $75.6 million, respectively, 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.  To the extent that we attribute all or a portion of an excess cost amount to higher fair values, we amortize such excess cost as a reduction in equity earnings in a manner similar to depreciation.  To the extent we attribute an excess cost amount to goodwill, we do not amortize this amount but it is subject to evaluation for impairment.  Amortization of excess cost amounts was $1.7 million and $1.8 million for the three months ended September 30, 2009 and 2008, respectively.  For each of the nine months ended September 30, 2009 and 2008, amortization of such amounts was $5.1 million.

28 

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table presents our equity in income (loss) of unconsolidated affiliates by business segment for the periods indicated:

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2009			2008			2009			2008
NGL Pipelines & Services	$	4.0		$	3.0		$	7.5		$	2.3
Onshore Natural Gas Pipelines & Services		1.4			0.4			3.9			0.8
Onshore Crude Oil Pipelines & Services		1.2			2.7			7.4			9.9
Offshore Pipelines & Services		10.6			6.0			22.1			27.9
Petrochemical & Refined Products Services		(2.2	)		(2.0	)		(8.9	)		(9.1	)
Total	$	15.0		$	10.1		$	32.0		$	31.8

Summarized Financial Information of Unconsolidated Affiliates

The following tables present unaudited income statement data for our current unconsolidated affiliates, aggregated by business segment, for the periods indicated (on a 100% basis):

	Summarized Income Statement Information for the Three Months Ended
	September 30, 2009							September 30, 2008
			Operating		Net					Operating		Net
	Revenues		Income		Income (Loss)			Revenues		Income		Income
NGL Pipelines & Services	$	60.0	$	10.9	$	11.2		$	75.1	$	9.7	$	6.8
Onshore Natural Gas Pipelines & Services		54.5		2.9		2.7			130.3		2.0		0.8
Onshore Crude Oil Pipelines & Services		20.7		6.8		6.9			24.6		11.6		11.7
Offshore Pipelines & Services		43.2		24.7		24.0			31.9		12.9		11.9
Petrochemical & Refined Products Services		12.2		2.2		(0.3	)		15.0		3.6		0.9

	Summarized Income Statement Information for the Nine Months Ended
	September 30, 2009							September 30, 2008
			Operating		Net					Operating		Net
	Revenues		Income		Income (Loss)			Revenues		Income		Income
NGL Pipelines & Services	$	161.7	$	23.7	$	24.2		$	217.8	$	17.7	$	15.1
Onshore Natural Gas Pipelines & Services		137.1		8.0		7.6			315.5		5.5		1.5
Onshore Crude Oil Pipelines & Services		62.2		25.6		25.6			72.5		37.3		37.4
Offshore Pipelines & Services		106.4		39.2		37.7			115.0		62.4		57.2
Petrochemical & Refined Products Services		39.5		4.7		(3.0	)		46.1		8.5		0.4

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 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.

29 

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The results of operations of these acquisitions are included in our supplemental consolidated financial statements beginning at the date of 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, while transaction costs associated with these transactions were expensed as incurred.  Such fair values have been developed using recognized business valuation techniques.

On a pro forma consolidated basis, our revenues, costs and expenses, operating income, net income and earnings per unit amounts would not have differed materially from those we actually reported for the three and nine months ended September 30, 2009 and 2008 due to immaterial nature of our 2009 business combination transactions.

Note 9.  Intangible Assets and Goodwill

Identifiable Intangible Assets

The following table summarizes our intangible assets by segment at the dates indicated:

	September 30, 2009							December 31, 2008
	Gross		Accum.			Carrying		Gross		Accum.			Carrying
	Value		Amort.			Value		Value		Amort.			Value
NGL Pipelines & Services:
Customer relationship intangibles	$	237.4	$	(82.2	)	$	155.2	$	237.4	$	(68.7	)	$	168.7
Contract-based intangibles		320.5		(151.7	)		168.8		320.3		(137.6	)		182.7
Subtotal		557.9		(233.9	)		324.0		557.7		(206.3	)		351.4
Onshore Natural Gas Pipelines & Services:												��
Customer relationship intangibles		372.0		(119.1	)		252.9		372.0		(103.2	)		268.8
Gas gathering agreements		464.0		(234.1	)		229.9		464.0		(213.1	)		250.9
Contract-based intangibles		101.3		(43.1	)		58.2		101.3		(36.6	)		64.7
Subtotal		937.3		(396.3	)		541.0		937.3		(352.9	)		584.4
Onshore Crude Oil Pipelines & Services:
Contract-based intangibles		10.0		(3.4	)		6.6		10.0		(3.1	)		6.9
Subtotal		10.0		(3.4	)		6.6		10.0		(3.1	)		6.9
Offshore Pipelines & Services:
Customer relationship intangibles		205.8		(101.8	)		104.0		205.8		(90.7	)		115.1
Contract-based intangibles		1.2		(0.2	)		1.0		1.2		(0.1	)		1.1
Subtotal		207.0		(102.0	)		105.0		207.0		(90.8	)		116.2
Petrochemical & Refined Products Services:
Customer relationship intangibles		104.6		(17.6	)		87.0		104.9		(13.8	)		91.1
Contract-based intangibles		42.0		(12.4	)		29.6		41.1		(8.2	)		32.9
Subtotal		146.6		(30.0	)		116.6		146.0		(22.0	)		124.0
Total	$	1,858.8	$	(765.6	)	$	1,093.2	$	1,858.0	$	(675.1	)	$	1,182.9

The following table presents the amortization expense of our intangible assets by business segment for the periods indicated:

	For the Three Months				For the Nine Months
	Ended September 30,				Ended September 30,
	2009		2008		2009		2008
NGL Pipelines & Services	$	9.4	$	10.1	$	27.6	$	30.8
Onshore Natural Gas Pipelines & Services		13.9		15.2		43.4		46.9
Onshore Crude Oil Pipelines & Services		0.1		0.1		0.3		0.3
Offshore Pipelines & Services		3.6		4.1		11.2		12.9
Petrochemical & Refined Products Services		2.7		2.7		8.0		7.4
Total	$	29.7	$	32.2	$	90.5	$	98.3

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Based on information currently available, we estimate that amortization expense will approximate $29.7 million for the fourth quarter 2009, $113.8 million for 2010, $106.3 million for 2011, $90.8 million for 2012 and $83.7 million for 2013.

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 the dates indicated:

	September 30,		December 31,
	2009		2008
NGL Pipelines & Services	$	341.2	$	341.2
Onshore Natural Gas Pipelines & Services		284.9		284.9
Onshore Crude Oil Pipelines & Services		303.0		303.0
Offshore Pipelines & Services		82.1		82.1
Petrochemical & Refined Products Services		1,007.1		1,008.4
Total	$	2,018.3	$	2,019.6

31 

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 10.  Debt Obligations

Our consolidated debt obligations consisted of the following at the dates indicated:

	September 30,			December 31,
	2009			2008
EPO senior debt obligations:
Multi-Year Revolving Credit Facility, variable rate, due November 2012	$	638.0		$	800.0
Pascagoula MBFC Loan, 8.70% fixed-rate, due March 2010 (1)		54.0			54.0
Petal GO Zone Bonds, variable rate, due August 2037		57.5			57.5
Yen Term Loan, 4.93% fixed-rate, due March 2009 (2)		--			217.6
Senior Notes B, 7.50% fixed-rate, due February 2011		450.0			450.0
Senior Notes C, 6.375% fixed-rate, due February 2013		350.0			350.0
Senior Notes D, 6.875% fixed-rate, due March 2033		500.0			500.0
Senior Notes F, 4.625% fixed-rate, due October 2009 (1)		500.0			500.0
Senior Notes G, 5.60% fixed-rate, due October 2014		650.0			650.0
Senior Notes H, 6.65% fixed-rate, due October 2034		350.0			350.0
Senior Notes I, 5.00% fixed-rate, due March 2015		250.0			250.0
Senior Notes J, 5.75% fixed-rate, due March 2035		250.0			250.0
Senior Notes K, 4.950% fixed-rate, due June 2010 (1)		500.0			500.0
Senior Notes L, 6.30% fixed-rate, due September 2017		800.0			800.0
Senior Notes M, 5.65% fixed-rate, due April 2013		400.0			400.0
Senior Notes N, 6.50% fixed-rate, due January 2019		700.0			700.0
Senior Notes O, 9.75% fixed-rate, due January 2014		500.0			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			516.7
TEPPCO Senior Notes, 7.625% fixed-rate, due February 2012		500.0			500.0
TEPPCO Senior Notes, 6.125% fixed-rate, due February 2013		200.0			200.0
TEPPCO Senior Notes, 5.90% fixed-rate, due April 2013		250.0			250.0
TEPPCO Senior Notes, 6.65% fixed-rate, due April 2018		350.0			350.0
TEPPCO Senior Notes, 7.55% fixed-rate, due April 2038		400.0			400.0
Duncan Energy Partners’ debt obligations:
DEP Revolving Credit Facility, variable rate, due February 2011		180.5			202.0
DEP Term Loan, variable rate, due December 2011		282.3			282.3
Total principal amount of senior debt obligations		10,404.0			10,030.1
EPO Junior Subordinated Notes A, fixed/variable rate, due August 2066		550.0			550.0
EPO Junior Subordinated Notes B, fixed/variable rate, due January 2068		682.7			682.7
TEPPCO Junior Subordinated Notes, fixed/variable rate, due June 2067		300.0			300.0
Total principal amount of senior and junior debt obligations		11.936.7			11,562.8
Other, non-principal amounts:
Change in fair value of debt-related derivative instruments		47.6			51.9
Unamortized discounts, net of premiums		(12.1	)		(12.6	)
Unamortized deferred net gains related to terminated interest rate swaps		27.0			35.8
Total other, non-principal amounts		62.5			75.1
Total long-term debt	$	11,999.2		$	11,637.9
Letters of credit outstanding	$	109.3		$	1.0
(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.

32 

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 99.2.

$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 19 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 19 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.

33 

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Dixie Revolving Credit Facility

The Dixie Revolving Credit Facility was terminated in January 2009.  As of December 31, 2008, there were no debt obligations outstanding under this facility.

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

34 

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 99.2.

Note 11.  Equity and Distributions

Our common units represent limited partner interests, which give the holders thereof the right to participate in distributions and to exercise the other rights or privileges available to them under ourFifth Amended and Restated Agreement of Limited Partnership (together with all amendments thereto, the “Partnership Agreement”).  We are managed by our general partner, EPGP.

Equity Offerings and Registration Statements

We have a universal shelf registration statement on file with the SEC that allows us to issue an unlimited amount of debt and equity securities for general partnership purposes.  In January 2009, we issued 10,590,000 common units (including an over-allotment of 990,000 common units) to the public at an offering price of $22.20 per unit under this registration statement.  We used the net proceeds of $225.6 million from the January 2009 equity offering to temporarily reduce borrowings outstanding under EPO’s Multi-Year Revolving Credit Facility and for general partnership purposes.  In June 2009, EPO issued $500.0 million in principal amount of Senior Notes P under this registration statement.  Net proceeds from this senior note offering were used to repay the $200.0 Million Term Loan, to temporarily reduce borrowings outstanding under EPO’s Multi-Year Revolving Credit Facility and for general partnership purposes.

In September 2009, we issued 8,337,500 common units (including an over-allotment of 1,087,500 common units) to the public at an offering price of $28.00 per unit under this registration statement.  We used the net proceeds of $226.4 million from the September 2009 equity offering to temporarily reduce borrowings outstanding under EPO’s Multi-Year Revolving Credit Facility and for general partnership purposes.  In October 2009, EPO issued $1.1 billion in principal amount of Senior Notes Q and R under this registration statement.  Net proceeds from this senior note offering were used to repay $500.0 million in aggregate principal amount of Senior Notes F that matured in October 2009, to temporarily reduce borrowings outstanding under EPO’s Multi-Year Revolving Credit Facility and for general partnership purposes.

We also have a registration statement on file with the SEC authorizing the issuance of up to 40,000,000 common units in connection with our distribution reinvestment plan (“DRIP”).  A total of 32,202,131 common units have been issued under this registration statement through September 30, 2009.

In addition, we have a registration statement on file related to our employee unit purchase plan (“EUPP”), under which we can issue up to 1,200,000 common units.  A total of 792,809 common units have been issued to employees under this plan through September 30, 2009.

On September 4, 2009, we agreed to issue 5,940,594 common units in a private placement to EPCO Holdings, Inc., a privately held affiliate controlled by Dan L. Duncan, for $150.0 million, or $25.25 per unit.  In accordance with the terms of the private placement, as approved by the Audit, Conflicts and Governance (“ACG”) Committee of EPGP’s Board of Directors on September 1, 2009, the per unit purchase price of $25.25 was calculated based on a five percent discount to the five-day volume weighted average price (“5-Day VWAP”) of our common units, as reported by the NYSE at the close of business on September 4, 2009.  The 5-Day VWAP was based on (i) the closing price for the common units on the

35 

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NYSE for each of the trading days in such five-day period and (ii) the total trading volume for the common units reported by the NYSE for each such trading day.  The common units were issued on September 8, 2009.

The following table reflects the number of common units issued and the net proceeds received from underwritten and other common unit offerings completed during the nine months ended September 30, 2009:

	Net Proceeds from Sale of Common Units
	Number of		Contributed		Contributed by		Total
	Common Units		by Limited		General		Net
	Issued		Partners		Partner		Proceeds
January underwritten offering		10,590,000	$	225.6	$	4.6	$	230.2
February DRIP and EUPP		3,679,163		78.9		1.6		80.5
May DRIP and EUPP		3,671,679		86.1		1.8		87.9
August DRIP and EUPP		3,521,754		93.2		1.8		95.0
September private placement		5,940,594		150.0		3.1		153.1
September underwritten offering		8,337,500		226.4		4.6		231.0
Total 2009		35,740,690	$	860.2	$	17.5	$	877.7

Net proceeds from the issuance of common units during 2009 have been used to temporarily reduce borrowings under EPO’s Multi-Year Revolving Credit Facility and for general partnership purposes.

Summary of Changes in Outstanding Units

The following table summarizes changes in our outstanding units since December 31, 2008:

				Restricted
	Common			Common			Treasury
	Units			Units			Units
Balance, December 31, 2008		439,354,731			2,080,600			--
Common units issued in connection with underwritten offerings		18,927,500			--			--
Common units issued in connection with private placement		5,940,594			--			--
Common units issued in connection with DRIP and EUPP		10,872,596			--			--
Common units issued in connection with equity awards		18,500			--			--
Restricted units issued		--			1,016,950			--
Forfeiture of restricted units		--			(194,400	)		--
Conversion of restricted units to common units		244,300			(244,300	)		--
Acquisition of treasury units		(64,223	)		--			64,223
Cancellation of treasury units		--			--			(64,223	)
Balance, September 30, 2009		475,293,998			2,658,850			--

36 

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Summary of Changes in Limited Partners’ Equity

The following table details the changes in limited partners’ equity since December 31, 2008:

				Restricted
	Common			Common
	Units			Units			Total
Balance, December 31, 2008	$	6,036.9		$	26.2		$	6,063.1
Net income		501.9			2.7			504.6
Operating leases paid by EPCO		0.5			--			0.5
Cash distributions to partners		(731.5	)		(3.7	)		(735.2	)
Unit option reimbursements to EPCO		(0.5	)		--			(0.5	)
Net proceeds from issuance of common units		860.2			--			860.2
Proceeds from exercise of unit options		0.5			--			0.5
Acquisition of treasury units		--			(1.8	)		(1.8	)
Amortization of equity awards		2.8			10.7			13.5
Balance, September 30, 2009	$	6,670.8		$	34.1		$	6,704.9

Distributions to Partners

We paid EPGP incentive distributions of $38.1 million and $32.0 million during the three months ended September 30, 2009 and 2008, respectively.  During the nine months ended September 30, 2009 and 2008, we paid incentive distributions of $109.9 million and $92.8 million, respectively, to EPGP.

We paid aggregate distributions to our unitholders and our general partner of $860.1 million during the nine months ended September 30, 2009.  These distributions pertained to the nine month period ended June 30, 2009 (i.e., the fourth quarter of 2008, and first and second quarters of 2009).  On November 5, 2009, we paid a quarterly cash distribution of $0.5525 per unit with respect to the third quarter of 2009, to unitholders of record at the close of business on October 30, 2009, which included former TEPPCO unitholders who received our common units upon completion of the TEPPCO Merger.  See Note 19 for additional information regarding the TEPPCO Merger.

Accumulated Other Comprehensive Loss

The following table presents the components of AOCI at the dates indicated:

	September 30,			December 31,
	2009			2008
Commodity derivative instruments (1)	$	(84.7	)	$	(114.1	)
Interest rate derivative instruments (1)		(27.2	)		(41.9	)
Foreign currency derivative instruments (1)		0.3			10.6
Foreign currency translation adjustment (2)		0.4			(1.3	)
Pension and postretirement benefit plans		(0.8	)		(0.8	)
Subtotal		(112.0	)		(147.5	)
Amount attributable to noncontrolling interest		44.9			50.3
Total accumulated other comprehensive loss in partners’ equity	$	(67.1	)	$	(97.2	)
(1)  See Note 4 for additional information regarding these components of accumulated other comprehensive loss. (2)  Relates to transactions of our Canadian NGL marketing subsidiary.

37 

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Noncontrolling Interest

The following table presents the components of noncontrolling interest as presented on our Unaudited Supplemental Condensed Consolidated Balance Sheets at the dates indicated:

	September 30,			December 31,
	2009			2008
Former owners of TEPPCO (1)	$	2,608.7		$	2,827.6
Limited partners of Duncan Energy Partners (2)		416.9			281.1
Joint venture partners (3)		108.5			148.0
AOCI attributable to noncontrolling interest		(44.9	)		(50.3	)
Total noncontrolling interest on consolidated balance sheets	$	3,089.2		$	3,206.4
(1)  Represents former ownership interests in TEPPCO and TEPPCO GP (see Note 1 - “Basis of Financial Statement Presentation”). (2)  Represents non-affiliate public unitholders of Duncan Energy Partners. The increase in noncontrolling interest between periods is attributable to Duncan Energy Partners’ equity offering in June 2009 (see Note 13). (3) 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 LLC. The balance at December 31, 2008, included $35.6 million related to Oiltanking’s ownership interest in TOPS, from which our wholly owned subsidiaries dissociated in April 2009 (see Note 6).

As a result of the dissociation of our wholly owned subsidiaries from TOPS (see Note 6), we discontinued the consolidation of TOPS during the second quarter of 2009.  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 a $68.4 million aggregate write-off of the investment.

The following table presents the components of net income (loss) attributable to noncontrolling interest as presented on our Unaudited Supplemental Condensed Statements of Consolidated Operations for the periods indicated:

	For the Three Months					For the Nine Months
	Ended September 30,					Ended September 30,
	2009			2008		2009		2008
Former owners of TEPPCO	$	(42.1	)	$	47.1	$	48.5	$	158.8
Limited partners of Duncan Energy Partners		10.1			2.7		21.8		11.8
Joint venture partners		6.9			5.2		20.7		17.5
Total	$	(25.1	)	$	55.0	$	91.0	$	188.1

Net income attributable to the former owners of TEPPCO decreased during the three and nine months ended September 30, 2009 relative to the same periods in 2008 by $33.5 million and $66.9 million, respectively, primarily due to charges related to TOPS (see Notes 6 and 15).  In addition, TEPPCO recorded $51.0 million in charges during the three months ended September 30, 2009 primarily related to its indefinite suspension of certain river terminal projects (see Notes 4 and 15).

38 

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table presents cash distributions paid to, and cash contributions from, noncontrolling interest as presented on our Unaudited Supplemental Condensed Statements of Consolidated Cash Flows and Unaudited Supplemental Condensed Statements of Consolidated Equity for the periods indicated:

	For the Nine Months
	Ended September 30,
	2009		2008
Cash distributions paid to noncontrolling interest:
Former owners of TEPPCO	$	274.5	$	236.8
Limited partners of Duncan Energy Partners		23.2		18.5
Joint venture partners		26.8		20.7
Total cash distributions paid to noncontrolling interest	$	324.5	$	276.0
Cash contributions from noncontrolling interest:
Former owners of TEPPCO		3.5		271.3
Limited partners of Duncan Energy Partners		137.4		--
Total cash contributions from noncontrolling interest	$	140.9	$	271.3

Distributions paid to the limited partners of Duncan Energy Partners and former owners of TEPPCO primarily represent the quarterly cash distributions paid by these entities to their unitholders.  Contributions from the limited partners of Duncan Energy Partners and former owners of TEPPCO primarily represent proceeds each entity received from unit offerings.

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.

Contributions from the former owners of TEPPCO decreased during the nine months ended September 30, 2009 relative to the nine months ended September 30, 2008 due to net proceeds that TEPPCO received from its unit offering in September 2008.

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.

39 

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table shows our measurement of total segment gross operating margin for the periods indicated:

		For the Three Months						For the Nine Months
		Ended September 30,						Ended September 30,
		2009			2008			2009			2008
Revenues (1)		$	6,789.4		$	10,499.1		$	17,110.6		$	29,544.1
Less:	Operating costs and expenses (1)		(6,395.8	)		(10,074.3	)		(15,796.9	)		(28,150.2	)
Add:	Equity in income (loss) of unconsolidated affiliates (1)		15.0			10.1			32.0			31.8
	Depreciation, amortization and accretion in operating costs and expenses (2)		206.0			181.3			602.9			532.3
	Impairment charges included in operating costs and expenses (2)		24.0			--			26.3			--
	Operating lease expense paid by EPCO (2)		0.2			0.5			0.5			1.6
	Gain from asset sales and related transactions in operating costs and expenses (2)		(0.1	)		(1.1	)		(0.5	)		(2.0	)
Total segment gross operating margin		$	638.7		$	615.6		$	1,974.9		$	1,957.6
(1)These amounts are taken from our Unaudited Supplemental Condensed Statements of Consolidated Operations. (2)These non-cash expenses are taken from the operating activities section of our Unaudited Supplemental Condensed Statements of Consolidated Cash Flows.

A reconciliation of our total segment gross operating margin to operating income and income before provision for income taxes follows:

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2009			2008			2009			2008
Total segment gross operating margin	$	638.7		$	615.6		$	1,974.9		$	1,957.6
Adjustments to reconcile total segment gross operating margin
to operating income:
Depreciation, amortization and accretion in operating costs and expenses		(206.0	)		(181.3	)		(602.9	)		(532.3	)
Impairment charges included in operating costs and expenses		(24.0	)		--			(26.3	)		--
Operating lease expense paid by EPCO		(0.2	)		(0.5	)		(0.5	)		(1.6	)
Gain from asset sales and related transactions in operating    costs and expenses		0.1			1.1			0.5			2.0
General and administrative costs		(52.3	)		(33.9	)		(133.3	)		(100.4	)
Operating income		356.3			401.0			1,212.4			1,325.3
Other expense, net		(160.8	)		(135.2	)		(469.8	)		(391.1	)
Income before provision for income taxes	$	195.5		$	265.8		$	742.6		$	934.2

40 

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

	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
Revenues from third parties:
Three months ended September 30, 2009	$	3,141.7	$	708.1	$	2,007.0	$	101.7	$	720.5		$	--		$	6,679.0
Three months ended September 30, 2008		4,300.5		886.5		3,994.1		64.9		1,000.1			--			10,246.1
Nine months ended September 30, 2009		7,767.6		2,007.6		5,003.1		247.5		1,662.6			--			16,688.4
Nine months ended September 30, 2008		12,581.9		2,636.3		10,628.9		205.1		2,760.2			--			28,812.4
Revenues from related parties:
Three months ended September 30, 2009		47.2		60.2		3.0		--		--			--			110.4
Three months ended September 30, 2008		93.6		154.7		4.7		--		--			--			253.0
Nine months ended September 30, 2009		245.3		173.1		3.8		--		--			--			422.2
Nine months ended September 30, 2008		409.2		314.7		7.8		--		--			--			731.7
Intersegment and intrasegment revenues:
Three months ended September 30, 2009		1,640.5		125.5		11.1		0.4		158.6			(1,936.1	)		--
Three months ended September 30, 2008		2,366.9		303.4		23.0		0.4		219.5			(2,913.2	)		--
Nine months ended September 30, 2009		4,535.5		392.8		34.7		1.0		393.8			(5,357.8	)		--
Nine months ended September 30, 2008		6,541.5		677.3		52.3		1.1		538.0			(7,810.2	)		--
Total revenues:
Three months ended September 30, 2009		4,829.4		893.8		2,021.1		102.1		879.1			(1,936.1	)		6,789.4
Three months ended September 30, 2008		6,761.0		1,344.6		4,021.8		65.3		1,219.6			(2,913.2	)		10,499.1
Nine months ended September 30, 2009		12,548.4		2,573.5		5,041.6		248.5		2,056.4			(5,357.8	)		17,110.6
Nine months ended September 30, 2008		19,532.6		3,628.3		10,689.0		206.2		3,298.2			(7,810.2	)		29,544.1
Equity in income (loss) of unconsolidated affiliates:
Three months ended September 30, 2009		4.0		1.4		1.2		10.6		(2.2	)		--			15.0
Three months ended September 30, 2008		3.0		0.4		2.7		6.0		(2.0	)		--			10.1
Nine months ended September 30, 2009		7.5		3.9		7.4		22.1		(8.9	)		--			32.0
Nine months ended September 30, 2008		2.3		0.8		9.9		27.9		(9.1	)		--			31.8
Gross operating margin:
Three months ended September 30, 2009		403.4		108.4		34.1		22.8		70.0			--			638.7
Three months ended September 30, 2008		342.4		133.0		35.4		16.4		88.4			--			615.6
Nine months ended September 30, 2009		1,118.1		391.5		126.7		83.0		255.6			--			1,974.9
Nine months ended September 30, 2008		970.9		452.8		109.5		133.3		291.1			--			1,957.6
Segment assets:
At September 30, 2009		6,280.3		5,761.5		391.6		1,488.4		2,148.4			1,226.8			17,297.0
At December 31, 2008		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 7)
At September 30, 2009		141.9		32.5		181.0		461.7		82.2			--			899.3
At December 31, 2008		144.3		25.9		186.2		469.0		86.5			--			911.9
Intangible assets, net: (see Note 9)
At September 30, 2009		324.0		541.0		6.6		105.0		116.6			--			1,093.2
At December 31, 2008		351.4		584.4		6.9		116.2		124.0			--			1,182.9
Goodwill: (see Note 9)
At September 30, 2009		341.2		284.9		303.0		82.1		1,007.1			--			2,018.3
At December 31, 2008		341.2		284.9		303.0		82.1		1,008.4			--			2,019.6

41 

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table provides additional information regarding our consolidated revenues (net of adjustments and eliminations) and expenses for the periods indicated:

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2009			2008			2009			2008
NGL Pipelines & Services:
Sales of NGLs	$	3,015.4		$	4,212.6		$	7,527.6		$	12,433.2
Sales of other petroleum and related products		0.6			0.5			1.5			1.9
Midstream services		172.9			181.0			483.8			556.0
Total		3,188.9			4,394.1			8,012.9			12,991.1
Onshore Natural Gas Pipelines & Services:
Sales of natural gas		585.8			859.2			1,645.4			2,400.4
Midstream services		182.5			182.0			535.3			550.6
Total		768.3			1,041.2			2,180.7			2,951.0
Onshore Crude Oil Pipelines & Services:
Sales of crude oil		1,991.3			3,980.5			4,946.1			10,580.7
Midstream services		18.7			18.3			60.8			56.0
Total		2,010.0			3,998.8			5,006.9			10,636.7
Offshore Pipelines & Services:
Sales of natural gas		0.3			0.9			0.9			2.5
Sales of other petroleum and related products		2.0			3.7			3.1			10.7
Midstream services		99.4			60.3			243.5			191.9
Total		101.7			64.9			247.5			205.1
Petrochemical Services:
Sales of other petroleum and related products		597.2			848.4			1,272.0			2,329.2
Midstream services		123.3			151.7			390.6			431.0
Total		720.5			1,000.1			1,662.6			2,760.2
Total consolidated revenues	$	6,789.4		$	10,499.1		$	17,110.6		$	29,544.1
Consolidated cost and expenses:
Operating costs and expenses:
Cost of sales for our marketing activities	$	5,008.5		$	8,473.0		$	12,248.3		$	23,705.2
Depreciation, amortization and accretion		206.0			181.4			602.8			532.3
Gain on sale of assets and related transactions		(0.1	)		(1.1	)		(0.5	)		(2.0	)
Non-cash impairment charge		24.0			--			26.3			--
Other operating costs and expenses		1,157.4			1,421.0			2,920.0			3,914.7
General and administrative costs		52.3			33.9			133.3			100.4
Total consolidated costs and expenses	$	6,448.1		$	10,108.2		$	15,930.2		$	28,250.6

42 

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 13.  Related Party Transactions

The following table summarizes our related party transactions for the periods indicated:

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2009			2008			2009			2008
Revenues from consolidated operations:
Energy Transfer Equity and subsidiaries	$	54.5		$	99.6		$	266.5		$	413.0
Unconsolidated affiliates		55.9			153.4			155.7			318.7
Total	$	110.4		$	253.0		$	422.2		$	731.7
Cost of sales:
EPCO and affiliates	$	19.5		$	10.3		$	46.4		$	31.0
Energy Transfer Equity and subsidiaries		100.6			50.6			286.5			119.4
Unconsolidated affiliates		13.9			25.5			38.2			80.3
Total	$	134.0		$	86.4		$	371.1		$	230.7
Operating costs and expenses:
EPCO and affiliates	$	119.9		$	105.4		$	338.2		$	318.2
Energy Transfer Equity and subsidiaries		12.5			5.9			23.6			15.0
Cenac and affiliates		6.0			13.0			33.0			30.2
Unconsolidated affiliates		(4.8	)		(11.5	)		(15.4	)		(37.4	)
Total	$	133.6		$	112.8		$	379.4		$	326.0
General and administrative expenses:
EPCO and affiliates	$	24.9		$	20.7		$	74.9		$	68.9
Cenac and affiliates		0.5			0.8			2.1			2.1
Total	$	25.4		$	21.5		$	77.0		$	71.0
Other expense:
EPCO and affiliates	$	--		$	--		$	--		$	0.3

The following table summarizes our related party receivable and payable amounts at the dates indicated:

	September 30,		December 31,
	2009		2008
Accounts receivable - related parties:
EPCO and affiliates	$	--	$	0.2
Energy Transfer Equity and subsidiaries		6.4		35.0
Other		3.2		0.1
Total	$	9.6	$	35.3
Accounts payable - related parties:
EPCO and affiliates	$	12.0	$	14.1
Energy Transfer Equity and subsidiaries		27.2		0.1
Other		5.0		3.2
Total	$	44.2	$	17.4

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.

43 

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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;

§   EPGP, our general partner;

§   Enterprise GP Holdings, which owns and controls our general partner; and

§   the Employee Partnerships.

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 our outstanding common units, which includes 13,952,402 of our 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 our managing partner.  The executive officers and certain of the directors of EPGP and EPE Holdings are employees of EPCO.

As our general partner, EPGP received cash distributions of $124.9 million and $106.4 million from us during the nine months ended September 30, 2009 and 2008, respectively.  These amounts include incentive distributions of $109.9 million and $92.8 million for the nine months ended September 30, 2009 and 2008, respectively.

See Note 11 for information regarding the private placement of 5,940,594 common units with a privately held affiliate of EPCO in September 2009.

We 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 us, 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 us and Enterprise GP Holdings $354.9 million and $300.2 million in cash distributions during the nine months ended September 30, 2009 and 2008, respectively.

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.  Our operating costs and expenses include reimbursement payments to EPCO for the costs it incurs to operate our facilities, including compensation of EPCO’s employees to the extent that such employees spend time on our businesses.  We reimbursed EPCO $138.9 million for operating costs and expenses and $24.9 million for general and administrative costs for the three months ended September 30, 2009.  For the nine months ended September 30, 2009, we reimbursed EPCO $384.1 million for operating costs and expenses and $74.9 million for general and administrative costs.

44 

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 recorded $54.5 million and $99.6 million, respectively, of revenues from Energy Transfer Partners, L.P. (“ETP”), primarily from NGL marketing activities for the three months ended September 30, 2009 and 2008.  For the nine months ended September 30, 2009 and 2008, we recorded $266.5 million and $413.0 million, respectively, of revenues from ETP, primarily from NGL marketing activities.  We incurred $113.1 million and $56.5 million for the three months ended September 30, 2009 and 2008, respectively, in costs of sales and operating costs and expenses.  For the nine months ended September 30, 2009 and 2008, we incurred $310.1 million and $134.4 million, respectively, in costs of sales and operating costs and expenses.  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 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.

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ENTERPRISE PRODUCTS PARTNERS L.P.

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CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 and $32.5 million in connection with the Omnibus Agreement during the nine months ended September 30, 2009 and 2008, respectively.  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 and $86.4 million under the Mont Belvieu Caverns limited liability company agreement during the nine months ended September 30, 2009 and 2008, respectively, 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.

Relationships with Unconsolidated Affiliates

Our significant related party revenue and expense transactions with unconsolidated affiliates consist of the sale of natural gas to Evangeline and 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 our common units, 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.

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ENTERPRISE PRODUCTS PARTNERS L.P.

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CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 14.  Earnings Per Unit

The following table presents the net income available to EPGP for the periods indicated:

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2009			2008			2009			2008
Net income attributable to Enterprise Products Partners L.P.	$	212.9		$	203.1		$	624.8		$	726.0
Less incentive earnings allocations to EPGP		(38.1	)		(32.0	)		(109.9	)		(92.8	)
Net income available after incentive earnings allocation		174.8			171.1			514.9			633.2
Multiplied by EPGP ownership interest		2.0	%		2.0	%		2.0	%		2.0	%
Standard earnings allocation to EPGP	$	3.5		$	3.4		$	10.3		$	12.7
Incentive earnings allocation to EPGP	$	38.1		$	32.0		$	109.9		$	92.8
Standard earnings allocation to EPGP		3.5			3.4			10.3			12.7
Net income available to EPGP		41.6			35.4			120.2			105.5
Adjustment for ASC 260 (1)		2.5			1.1			5.3			3.2
Net income available to EPGP for EPU purposes	$	44.1		$	36.5		$	125.5		$	108.7
(1)For purposes of computing basic and diluted earnings per unit, the master limited partnerships subsections of ASC 260 have been applied.

The following table presents our calculation of basic and diluted earnings per unit for the periods indicated and does not include any pro forma impact relating to outstanding TEPPCO units:

	For the Three Month						For the Nine Month
	Ended September 30,						Ended September 30,
	2009			2008			2009			2008
BASIC EARNINGS PER UNIT
Numerator
Net income attributable to Enterprise Products Partners L.P.	$	212.9		$	203.1		$	624.8		$	726.0
Net income available to EPGP for EPU purposes		(44.1	)		(36.5	)		(125.5	)		(108.7	)
Net income available to limited partners	$	168.8		$	166.6		$	499.3		$	617.3
Denominator
Weighted – average common units		461.5			435.3			456.0			434.6
Weighted – average time-vested restricted units		2.8			2.3			2.4			2.0
Total		464.3			437.6			458.4			436.6
Basic earnings per unit
Net income per unit before EPGP earnings allocation	$	0.45		$	0.46		$	1.36		$	1.66
Net income available to EPGP		(0.09	)		(0.08	)		(0.27	)		(0.25	)
Net income available to limited partners	$	0.36		$	0.38		$	1.09		$	1.41
DILUTED EARNINGS PER UNIT
Numerator
Net income attributable to Enterprise Products Partners L.P.	$	212.9		$	203.1		$	624.8		$	726.0
Net income available to EPGP for EPU purposes		(44.1	)		(36.5	)		(125.5	)		(108.7	)
Net income available to limited partners	$	168.8		$	166.6		$	499.3		$	617.3
Denominator
Weighted – average common units		461.5			435.3			456.0			434.6
Weighted – average time-vested restricted units		2.8			2.3			2.4			2.0
Incremental option units		0.1			0.2			0.1			0.3
Total		464.4			437.8			458.5			436.9
Diluted earnings per unit
Net income per unit before EPGP earnings allocation	$	0.45		$	0.46		$	1.36		$	1.66
Net income available to EPGP		(0.09	)		(0.08	)		(0.27	)		(0.25	)
Net income available to limited partners	$	0.36		$	0.38		$	1.09		$	1.41

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 15.  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, results of operations or cash flows.

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 supplementalfinancial statements.

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 us or our 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) us and certain of our affiliates, (iii) EPCO and (iv) Dan L. Duncan.

The amended complaint alleges, among other things, that the defendants caused TEPPCO to enter into specified transactions that were unfair to TEPPCO or otherwise unfairly favored us or our affiliates over TEPPCO.  These transactions are alleged to include: (i) the joint venture to further expand the Jonah system entered into by TEPPCO and us in August 2006 (the plaintiff alleges that TEPPCO did not receive fair value for allowing us to participate in the joint venture); (ii) the sale by TEPPCO of its Pioneer natural gas processing plant and certain gas processing rights to us 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 us, EPGP, TEPPCO GP, the directors of TEPPCO GP, EPCO and Dan L. Duncan.

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ENTERPRISE PRODUCTS PARTNERS L.P.

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CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 we, 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 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 19 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

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ENTERPRISE PRODUCTS PARTNERS L.P.

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CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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, results of operations or cash flows.

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 us and TEPPCO to make capital contributions to fund the project and impose liabilities on us and TEPPCO.  On September 17, 2009, we 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).  We recognized approximately $66.9 million of expense during the third quarter of 2009 in connection with this settlement.  This charge is classified within our Offshore Pipelines & Services business segment.

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

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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, financial position, demand for our operations, results of operations and cash flows.

Contractual Obligations

Scheduled maturities of long-term debt. See Notes 10 and 19 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.  Lease and rental expense was $16.2 million and $13.2 million during the three months ended September 30, 2009 and 2008, respectively.  For the nine months ended September 30, 2009 and 2008, lease and rental expense was $45.0 million and $42.7 million, respectively.

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 99.2.  See Note 6 for additional information regarding TOPS.

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.

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ENTERPRISE PRODUCTS PARTNERS L.P.

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CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 Sheets.  The accrued deficiency charges are included in operating costs and expenses for the three and nine months ended September 30, 2009.  There was no impact on net income attributable to Enterprise Products Partners, as all of this charge was absorbed by noncontrolling interests in consolidation (i.e., by former owners of TEPPCO).

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 supplemental consolidated financial statements.

Note 16.   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.

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.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 periods indicated from business interruption and property damage insurance claims with respect to certain named storms:

	For the Three Months				For the Nine Months
	Ended September 30,				Ended September 30,
	2009		2008		2009		2008
Business interruption proceeds:
Hurricane Katrina	$	--	$	--	$	--	$	0.5
Hurricane Rita		--		--		--		0.7
Hurricane Ike		19.2		--		19.2		--
Total business interruption proceeds		19.2		--		19.2		1.2
Property damage proceeds:
Hurricane Ivan		0.7		--		0.7		--
Hurricane Katrina		3.5		2.5		26.7		9.4
Hurricane Rita		--		--		--		2.7
Total property damage proceeds		4.2		2.5		27.4		12.1
Total	$	23.4	$	2.5	$	46.6	$	13.3

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.  LBI accounted for 5.9% of our consolidated revenues during 2008.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 17.  Supplemental Cash Flow Information

The following table provides information regarding the net effect of changes in our operating assets and liabilities for the periods indicated:

	For the Nine Months
	Ended September 30,
	2009			2008
Decrease (increase) in:
Accounts and notes receivable – trade	$	(551.2	)	$	(242.0	)
Accounts receivable – related parties		36.0			22.3
Inventories		(830.1	)		(383.6	)
Prepaid and other current assets		(6.4	)		(59.0	)
Other assets		(14.1	)		18.6
Increase (decrease) in:
Accounts payable – trade		(3.1	)		(36.4	)
Accounts payable – related parties		18.9			30.4
Accrued product payables		817.1			381.8
Accrued interest payable		(25.6	)		(15.2	)
Other accrued expenses		(11.0	)		35.3
Other current liabilities		(26.7	)		11.7
Other liabilities		21.3			(5.0	)
Net effect of changes in operating accounts	$	(574.9	)	$	(241.1	)

We incurred liabilities for construction in progress that had not been paid at September 30, 2009 and December 31, 2008 of $122.2 million and $109.0 million, respectively.  Such amounts are not included under the caption “Capital expenditures” on the Unaudited Supplemental Condensed Statements of Consolidated Cash Flows.

Note 18.  Supplemental Condensed Consolidated Financial Information of EPO

EPO conducts substantially all of our business.  Currently, we have no independent operations or material assets outside those of EPO. EPO consolidates the financial statements of Duncan Energy Partners with its own financial statements.

Immediately after the closing of the TEPPCO Merger (see Note 19), Enterprise Products Partners L.P. contributed its ownership interests in TEPPCO and TEPPCO GP to EPO.  The following supplemental condensed consolidated financial information for EPO has been recast to include TEPPCO and TEPPCO GP using the same basis of presentation described in Note 1 for our consolidated financial statements.

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

The reconciling items between our supplemental consolidated financial statements and those of EPO are insignificant.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table presents supplemental condensed consolidated balance sheet data for EPO at the dates indicated:

	September 30,		December 31,
	2009		2009
ASSETS
Current assets	$	4,358.9	$	3,114.6
Property, plant and equipment, net		17,297.0		16,732.8
Investments in unconsolidated affiliates		899.3		911.9
Intangible assets, net		1,093.2		1,182.9
Goodwill		2,018.3		2,019.6
Other assets		265.1		261.1
Total	$	25,931.8	$	24,222.9
LIABILITIES AND EQUITY
Current liabilities	$	3,840.3	$	3,100.8
Long-term debt		11,999.2		11,637.9
Other long-term liabilities		220.9		176.5
Equity		9,871.4		9,307.7
Total	$	25,931.8	$	24,222.9
Total EPO debt obligations guaranteed Enterprise Products Partners L.P.	$	8,682.2	$	8,561.8

The following table presents supplemental condensed consolidated statements of operations data for EPO for the periods indicated:

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2009			2008			2009			2008
Revenues	$	6,789.4		$	10,499.1		$	17,110.6		$	29,544.2
Costs and expenses		6,439.8			10,107.9			15,915.4			28,249.1
Equity in income of unconsolidated affiliates		15.0			10.0			32.0			31.8
Operating income		364.6			401.2			1,227.2			1,326.9
Other expense		(160.8	)		(135.2	)		(469.8	)		(391.2	)
Income before provision for income taxes		203.8			266.0			757.4			935.7
Provision for income taxes		(7.7	)		(7.7	)		(26.8	)		(20.1	)
Net income		196.1			258.3			730.6			915.6
Net (income) loss attributable to the noncontrolling interest		25.1			(55.0	)		(91.2	)		(188.2	)
Net income attributable to EPO	$	221.2		$	203.3		$	639.4		$	727.4

Note 19.  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.

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

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 our 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 ours and each of TEPPCO's unitholders, except for a privately held affiliate of EPCO, were entitled to receive 1.24 of our common units for each TEPPCO unit.  In total, we 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 our 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 our common units.

Under the terms of the TEPPCO Merger agreements, Enterprise GP Holdings received 1,331,681 of our common units and an increase in the capital account of EPGP to maintain its 2% general partner interest in us 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 our 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.

We incurred $26.8 million of merger-related expenses during the nine months ended September 30, 2009 that are reflected as a component of general and administrative costs.

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.    

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED SUPPLEMENTAL

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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
	$	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.

57