Enterprise Products Partners (EPD) 8-K 4 Dec 09 Recast of Certain Sections of the 2008 Annual Report on Form 10-K Financial data

UNAUDITED CONDENSED CONSOLIDATE

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS (USD $)
In Millions	Sep. 30, 2009	Dec. 31, 2008	Dec. 31, 2007
Current assets:
Cash and cash equivalents	77.3	61.7	51.3
Restricted cash	102.8	203.8	53.1
Accounts and notes receivable - trade, net of allowance for doubtful accounts	2579.6	2028.5	3363.4
Accounts receivable - related parties	9.6	35.3	40.1
Inventories	1220.6	405	425.7
Derivative assets	199.5	218.6	12.3
Prepaid and other current assets	168	149.8	115.1
Total current assets	4357.4	3102.7	4,061
Property, plant and equipment, net	17,297	16732.8	14309.1
Investments in unconsolidated affiliates	899.3	911.9	885.6
Intangible assets, net of accumulated amortization	1093.2	1182.9	1214.1
Goodwill	2018.3	2019.6	1813.3
Deferred tax asset	1.1	0.4	3.5
Other assets	264.9	261.3	228.9
Total assets	25931.2	24211.6	22515.5
Current liabilities:
Current maturities of long-term debt		0	354
Accounts payable - trade	399.7	388.9	398.3
Accounts payable - related parties	44.2	17.4	16.7
Accrued product payables	2657.4	1845.7	3572.8
Accrued interest payable	163.1	188.3	166.5
Other accrued expenses	55.1	65.7	62
Derivative liabilities	264.6	302.9	96.4
Other current liabilities	263.5	292.3	292.6
Total current liabilities	3847.6	3101.2	4959.3
Long-term debt:
Senior debt obligations - principal	10,404	10030.1	6837.5
Junior subordinated notes - principal	1532.7	1532.7	1,550
Other	62.5	75.1	29.6
Total long-term debt	11999.2	11637.9	8417.1
Deferred tax liabilities	69.6	66.1	21.4
Other long-term liabilities	151.2	110.5	101.2
Limited Partners:
Common units	6670.8	6036.9	5,977
Restricted common units	34.1	26.2	15.9
General partner	136.6	123.6	122.3
Accumulated other comprehensive income (loss)	-67.1	-97.2	19.1
Total Enterprise Products Partners L.P. partners' equity	6774.4	6089.5	6134.3
Noncontrolling interest	3089.2	3206.4	2882.2
Total equity	9863.6	9295.9	9016.5
Total liabilities and equity	25931.2	24211.6	22515.5

PARENTHETICAL DATA TO THE UNAUD

PARENTHETICAL DATA TO THE UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS (USD $)
In Millions, except Share data	Sep. 30, 2009	Dec. 31, 2008	Dec. 31, 2007
Current assets:
Allowance for doubtful accounts	$17	17.7	21.8
Accumulated amortization	765.6	675.1	545.9
Limited Partners:
Common units outstanding	475,293,998	439,354,731	433,608,763
Restricted common units outstanding	2,658,850	2,080,600	1,688,540

UNAUDITED CONDENSED STATEMENTS

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS (USD $)
In Millions, except Per Share data	3 Months Ended Sep. 30, 2009	3 Months Ended Sep. 30, 2008	9 Months Ended Sep. 30, 2009	9 Months Ended Sep. 30, 2008	12 Months Ended Dec. 31, 2008	12 Months Ended Dec. 31, 2007	12 Months Ended Dec. 31, 2006
Revenues:
Third parties	$6,679	10246.1	16688.4	28812.4	34454.2	26128.6	23251.4
Related parties	110.4	253	422.2	731.7	1015.4	585.2	360.7
Total revenues	6789.4	10499.1	17110.6	29544.1	35469.6	26713.8	23612.1
Operating costs and expenses:
Third parties	6128.2	9875.1	15046.4	27593.5	32861.9	24938.2	21964.1
Related parties	267.6	199.2	750.5	556.7	757	463.9	443.8
Total operating costs and expenses	6395.8	10074.3	15796.9	28150.2	33618.9	25402.1	22407.9
General and administrative costs:
Third parties	26.9	12.4	56.3	29.4	43.4	44.6	32.2
Related parties	25.4	21.5	77	71	93.8	82.6	63.7
Total general and administrative costs	52.3	33.9	133.3	100.4	137.2	127.2	95.9
Total costs and expenses	6448.1	10108.2	15930.2	28250.6	33756.1	25529.3	22516.2
Equity in income of unconsolidated affiliates	15	10.1	32	31.8	34.9	10.5	25.2
Operating income	356.3	401	1212.4	1325.3	1748.4	1,195	1121.1
Other income (expense):
Interest expense	(161)	(137)	(472)	-396.3	-540.7	(413)	-324.2
Interest income	0.3	2.5	1.9	6.2	7.4	11.1	9.7
Other, net	-0.1	-0.7	0.3	(1)	4.8	60.6	1.5
Total other expense, net	-160.8	-135.2	-469.8	-391.1	-528.5	-341.3	(313)
Income before provision for income taxes and the cumulative effect of change in accounting principle	195.5	265.8	742.6	934.2	1219.9	853.7	808.1
Provision for income taxes	-7.7	-7.7	-26.8	-20.1	(31)	-15.7	(22)
Income before the cumulative effect of change in accounting principle					1188.9	838	786.1
Cumulative effect of change in accounting principle					0	0	1.5
Net income	187.8	258.1	715.8	914.1	1188.9	838	787.6
Net (income) loss attributable to noncontrolling interest	25.1	(55)	(91)	-188.1	-234.9	-304.4	-186.5
Net income attributable to Enterprise Products Partners L.P.	212.9	203.1	624.8	726	954	533.6	601.1
Net income allocated to:
Limited partners	171.3	167.6	504.6	620.5	811.5	417.7	504.1
General partner	41.6	35.5	120.2	105.5	142.5	115.9	$97
Basic and diluted earnings per unit	0.36	0.38	1.09	1.41	1.84	0.95	1.2
Basic and Diluted Earnings Per Unit Before Changes in Accounting Principles
Basic and diluted earnings per unit before change in accounting principle					1.84	0.95	1.2

1_UNAUDITED CONDENSED STATEMENT

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS) (USD $)
In Millions	3 Months Ended Sep. 30, 2009	3 Months Ended Sep. 30, 2008	9 Months Ended Sep. 30, 2009	9 Months Ended Sep. 30, 2008	12 Months Ended Dec. 31, 2008	12 Months Ended Dec. 31, 2007	12 Months Ended Dec. 31, 2006
Net income	187.8	258.1	715.8	914.1	1188.9	$838	787.6
Cash flow hedges:
Commodity derivative instrument gains (losses) during period	-8.3	-236.1	-146.9	-143.3	-170.2	-46.9	9.9
Reclassification adjustment for (gains) losses included in net income related to commodity derivative instruments	77.8	43.9	176.3	50.5	96.3	9.5	-12.8
Interest rate derivative instrument gains (losses) during period	(8)	-1.1	7.1	-46.1	-55.6	-8.9	11
Reclassification adjustment for (gains) losses included in net income related to interest rate derivative instruments	2.8	0	7.6	-2.5	2.5	-5.8	-4.2
Foreign currency derivative gains (losses)	0.2	0	-10.3	-1.3	9.3	1.3	0
Total cash flow hedges	64.5	-193.3	33.8	-142.7	-117.7	-50.8	3.9
Foreign currency translation adjustment	1.1	0.4	1.7	0.5	-2.5	2	-0.8
Change in funded status of pension and postretirement plans, net of tax	0	0	0	-0.3	-1.3	0	0
Total other comprehensive income (loss)	65.6	-192.9	35.5	-142.5	-121.5	-48.8	3.1
Comprehensive income	253.4	65.2	751.3	771.6	1067.4	789.2	790.7
Comprehensive (income) loss attributable to noncontrolling interest	23.3	(78)	-96.4	-179.7	-229.6	-258.7	(187)
Comprehensive income attributable to Enterprise Products Partners L.P.	276.7	-12.8	654.9	591.9	837.8	530.5	603.7

2_UNAUDITED CONDENSED STATEMENT

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (USD $)
In Millions	9 Months Ended Sep. 30, 2009	9 Months Ended Sep. 30, 2008	12 Months Ended Dec. 31, 2008	12 Months Ended Dec. 31, 2007	12 Months Ended Dec. 31, 2006
Operating activities:
Net income	715.8	914.1	1188.9	$838	787.6
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion	619.9	540.7	737.8	658.4	563.5
Non-cash impairment charge	26.3	0
Equity in income of unconsolidated affiliates	(32)	-31.8	-34.9	-10.5	-25.2
Distributions received from unconsolidated affiliates	55.2	50.5	80.8	87	76.5
Cumulative effect of change in accounting principle			0	0	1.5
Operating leases paid by EPCO, Inc.	0.5	1.6	2	2.1	2.1
Gain from asset sales, ownership interests and related transactions	-0.5	(2)	(4)	-67.4	-5.1
Loss on forfeiture of investment in Texas Offshore Port System	68.4	0
Loss on Early Extinguishment of Debt	0	8.7	1.6	1.6	0
Deferred income tax expense	2.5	5.6	6.2	7.6	15.1
Changes in fair market value of derivative instruments	10.6	4.9	-0.1	1.3	-0.1
Effect of pension settlement recognition	-0.1	-0.1	-0.1	0.6	0
Net effect of changes in operating accounts	-574.9	-241.1	-411.1	434.9	46.2
Net cash flows provided by operating activities	891.7	1251.1	1567.1	1953.6	1459.1
Investing activities:
Capital expenditures	-1100.4	-1844.7	(2,541)	(2,764)	-1727.7
Contributions in aid of construction costs	12.8	22.5	28.6	57.6	60.5
Decrease (increase) in restricted cash	100.8	-112.2	-132.8	-47.3	-8.7
Cash used for business combinations	-74.5	-408.8	-553.4	-35.9	-292.2
Acquisition of intangible assets	-1.4	-5.4	-5.8	-14.5	0
Investments in unconsolidated affiliates	-13.9	-23.9	-64.7	-236.8	-11.3
Proceeds from asset sales and related transactions	-2.9	(8)	22.2	169.1	5.8
Other proceeds from investing activities	-1.5	0
Cash used in investing activities	-1072.2	-2364.5	-3246.9	-2871.8	-1973.6
Financing activities:
Borrowings under debt agreements	4963.8	10209.3	13,188	7629.8	4302.1
Repayments of debt	(4,594)	-8266.7	-10434.3	-5799.9	(3,747)
Debt issuance costs	-5.5	-18.6	-27.5	-20.6	-8.9
Cash distributions paid to partners	-860.6	-770.8	-1037.5	-957.7	-843.3
Cash distributions paid to noncontrolling interest	-324.5	(276)	-383.9	-326.8	-287.4
Net cash proceeds from issuance of common units	878.2	57.2	142.8	69.2	857.2
Cash contributions from noncontrolling interest	140.9	271.3	311.5	304.7	222.6
Repurchase of Restricted Units and Options			0	-1.5	0
Acquisition of Treasury Units	-1.8	-0.8	-1.9	0	0
Monetization of interest rate derivative instruments	0	-74.2	-66.5	49.1	0
Cash provided by financing activities	196.5	1130.7	1690.7	946.3	495.3
Effect of exchange rate changes on cash	-0.4	-0.1	-0.5	0.4	-0.2
Net change in cash and cash equivalents	16	17.3	10.9	28.1	-19.2
Cash and cash equivalents, January 1	61.7	51.3	51.3	22.8	42.2
Cash and Cash Equivalents, Ending Balance	77.3	68.5	61.7	51.3	22.8

3_UNAUDITED CONDENSED STATEMENT

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY (USD $)
In Millions	9 Months Ended Sep. 30, 2009	9 Months Ended Sep. 30, 2008	12 Months Ended Dec. 31, 2008	12 Months Ended Dec. 31, 2007	12 Months Ended Dec. 31, 2006
Partners' Capital, Beginning Balance	9295.9	9016.5	9016.5	9124.9	8203.8
Net income	715.8	914.1	1188.9	838	787.6
Operating leases paid by EPCO, Inc.	0.5	1.6	2	2.1	2.1
Cash distributions paid to partners	-860.1	-770.3	-1036.8	-958.2	-841.4
Unit option reimbursements to EPCO, Inc.	-0.5	-0.6	-0.6	(3)	-1.9
Cash distributions paid to noncontrolling interest	324.5	276	383.9	326.8	287.4
Net cash proceeds from issuance of common units	877.7	56.5	142.1	61.6	847.8
Common Units Issued in Connection with Acquisitions		186.6	186.6		184.8
Cash proceeds from exercise of unit options	0.5	0.7	0.7	7.6	5.7
Cash contributions from noncontrolling interest	140.9	271.3	311.5	304.7	222.6
Deconsolidation of Texas Offshore Port System	-33.4
Repurchase of Restricted Units and Options			0	-1.5	0
Change In Accounting Method For Equity Awards					-1.5
Amortization of equity awards	16.8	9.9	14.1	14.7	8.5
Interest acquired from noncontrolling interest		-7.6	-22.3		(2)
Acquisition of Treasury Units	-1.8	-0.8	-1.9	0	0
Foreign currency translation adjustment	1.7	0.5	-2.5	2	-0.8
Change in funded status of pension and postretirement plans		-0.3	-1.3	1.2	-0.6
Acquisition-related disbursement of cash					-6.3
Cash flow hedges	33.8	-142.7	-117.7	-50.8	3.9
Other	0.3	0.5	0.5
Partners' Capital, Ending Balance	9863.6	9259.9	9295.9	9016.5	9124.9
Limited Partner [Member]
Partners' Capital, Beginning Balance	6063.1	5992.9	5992.9	6329.8	5561.3
Net income	504.6	620.5	811.5	417.7	504.1
Operating leases paid by EPCO, Inc.	0.5	1.6	2	2.1	2.1
Cash distributions paid to partners	-735.2	-663.9	-892.7	-833.8	-739.6
Unit option reimbursements to EPCO, Inc.	-0.5	-0.6	-0.6	(3)	-1.9
Cash distributions paid to noncontrolling interest	0	0	0	0	0
Net cash proceeds from issuance of common units	860.2	55.4	139.3	60.4	830.8
Common Units Issued in Connection with Acquisitions		0	0		181.1
Cash proceeds from exercise of unit options	0.5	0.7	0.7	7.5	5.6
Cash contributions from noncontrolling interest	0	0	0	0	0
Deconsolidation of Texas Offshore Port System	0
Repurchase of Restricted Units and Options				-1.5
Change In Accounting Method For Equity Awards					-15.8
Amortization of equity awards	13.5	8.7	11.9	13.7	8.3
Interest acquired from noncontrolling interest		0	0		0
Acquisition of Treasury Units	-1.8	-0.8	-1.9
Foreign currency translation adjustment	0	0	0	0	0
Change in funded status of pension and postretirement plans		0	0	0	0
Acquisition-related disbursement of cash					-6.2
Cash flow hedges	0	0	0	0	0
Other	0	0	0
Partners' Capital, Ending Balance	6704.9	6014.5	6063.1	5992.9	6329.8
General Partner [Member]
Partners' Capital, Beginning Balance	123.6	122.3	122.3	129.3	113.5
Net income	120.2	105.5	142.5	115.9	97
Operating leases paid by EPCO, Inc.	0	0	0	0	0
Cash distributions paid to partners	-124.9	-106.4	-144.1	-124.4	-101.8
Unit option reimbursements to EPCO, Inc.	0	0	0	0	0
Cash distributions paid to noncontrolling interest	0	0	0	0	0
Net cash proceeds from issuance of common units	17.5	1.1	2.8	1.2	17
Common Units Issued in Connection with Acquisitions		0	0		3.7
Cash proceeds from exercise of unit options	0	0	0	0.1	0.1
Cash contributions from noncontrolling interest	0	0	0	0	0
Deconsolidation of Texas Offshore Port System	0
Repurchase of Restricted Units and Options				0
Change In Accounting Method For Equity Awards					-0.3
Amortization of equity awards	0.2	0.1	0.1	0.2	0.2
Interest acquired from noncontrolling interest		0	0		0
Acquisition of Treasury Units	0	0	0
Foreign currency translation adjustment	0	0	0	0	0
Change in funded status of pension and postretirement plans		0	0	0	0
Acquisition-related disbursement of cash					-0.1
Cash flow hedges	0	0	0	0	0
Other	0	0	0
Partners' Capital, Ending Balance	136.6	122.6	123.6	122.3	129.3
Deferred Compensation [Member]
Partners' Capital, Beginning Balance	0	0	0	0	-14.6
Net income			0	0	0
Operating leases paid by EPCO, Inc.			0	0	0
Cash distributions paid to partners			0	0	0
Unit option reimbursements to EPCO, Inc.			0	0	0
Cash distributions paid to noncontrolling interest			0	0	0
Net cash proceeds from issuance of common units			0	0	0
Common Units Issued in Connection with Acquisitions			0		0
Cash proceeds from exercise of unit options			0	0	0
Cash contributions from noncontrolling interest			0	0	0
Repurchase of Restricted Units and Options				0
Change In Accounting Method For Equity Awards					14.6
Amortization of equity awards			0	0	0
Interest acquired from noncontrolling interest			0		0
Acquisition of Treasury Units			0
Foreign currency translation adjustment			0	0	0
Change in funded status of pension and postretirement plans			0	0	0
Acquisition-related disbursement of cash					0
Cash flow hedges			0	0	0
Partners' Capital, Ending Balance			0	0	0
Accumulated Other Comprehensive Income [Member]
Partners' Capital, Beginning Balance	-97.2	19.1	19.1	21.1	19.1
Net income	0	0	0	0	0
Operating leases paid by EPCO, Inc.	0	0	0	0	0
Cash distributions paid to partners	0	0	0	0	0
Unit option reimbursements to EPCO, Inc.	0	0	0	0	0
Cash distributions paid to noncontrolling interest	0	0	0	0	0
Net cash proceeds from issuance of common units	0	0	0	0	0
Common Units Issued in Connection with Acquisitions		0	0		0
Cash proceeds from exercise of unit options	0	0	0	0	0
Cash contributions from noncontrolling interest	0	0	0	0	0
Deconsolidation of Texas Offshore Port System	0
Repurchase of Restricted Units and Options				0
Change In Accounting Method For Equity Awards					0
Amortization of equity awards	0	0	0	0	0
Interest acquired from noncontrolling interest		0	0		0
Acquisition of Treasury Units	0	0	0
Foreign currency translation adjustment	1.7	0.5	-2.5	2	-0.8
Change in funded status of pension and postretirement plans		-0.3	-1.3	1.2	-0.6
Acquisition-related disbursement of cash					0
Cash flow hedges	28.4	-134.4	-112.5	-5.2	3.4
Other	0	0	0
Partners' Capital, Ending Balance	-67.1	-115.1	-97.2	19.1	21.1
Noncontrolling Interest [Member]
Partners' Capital, Beginning Balance	3206.4	2882.2	2882.2	2644.7	2524.5
Net income	91	188.1	234.9	304.4	186.5
Operating leases paid by EPCO, Inc.	0	0	0	0	0
Cash distributions paid to partners	0	0	0	0	0
Unit option reimbursements to EPCO, Inc.	0	0	0	0	0
Cash distributions paid to noncontrolling interest	-324.5	(276)	-383.9	-326.8	-287.4
Net cash proceeds from issuance of common units	0	0	0	0	0
Common Units Issued in Connection with Acquisitions		186.6	186.6		0
Cash proceeds from exercise of unit options	0	0	0	0	0
Cash contributions from noncontrolling interest	140.9	271.3	311.5	304.7	222.6
Deconsolidation of Texas Offshore Port System	-33.4
Repurchase of Restricted Units and Options				0
Change In Accounting Method For Equity Awards					0
Amortization of equity awards	3.1	1.1	2.1	0.8	0
Interest acquired from noncontrolling interest		-7.6	-22.3		(2)
Acquisition of Treasury Units	0	0	0
Foreign currency translation adjustment	0	0	0	0	0
Change in funded status of pension and postretirement plans		0	0	0	0
Acquisition-related disbursement of cash					0
Cash flow hedges	5.4	-8.3	-5.2	-45.6	0.5
Other	0.3	0.5	0.5
Partners' Capital, Ending Balance	3089.2	3237.9	3206.4	2882.2	2644.7

Partnership Organization and Ba

Partnership Organization and Basis of Presentation
	9 Months Ended Sep. 30, 2009 USD / shares	12 Months Ended Dec. 31, 2008 USD / shares
Notes To Financial Statements [Abstract]
Partnership Organization and Basis of Presentation	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.Publi	Note 1.Partnership Organization and Basis of Presentation 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 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 TEPPCO Merger and Basis of Presentation within this Note 1 for additional information regarding the TEPPCO Merger. References to Energy Transfer Equity mean the business and operations of Energy Transfer Equity, L.P. and its consolidated subsidiaries.References to LE GP mean LE GP, LLC, which is the general partner of Energy Transfer Equity.On May 7, 2007, Enterprise GP Holdings acquired noncontrolling interests in both LE GP and Energy Transfer Equity.Enterprise GP Holdings accounts for its investments in LE GP and Energy Transfer Equity using the equity method of accounting. References to Employee Partnerships mean EPE Unit L.P. (EPE Unit I), EPE Unit II, L.P. (EPE Unit II), EPE Unit III, L.P. (EPE Unit III), Enterprise Unit L.P. (Enterprise Unit), EPCO Unit L.P. (EPCO Unit), TEPPCO Unit L.P. (TEPPCO Unit I), and TEPPCO Unit II L.P. (TEPPCO Unit II), collectively, all of which are private company affiliates of EPCO. On February 5, 2007, a consolidated subsidiary of ours, Duncan Energy Partners L.P. (Duncan Energy Partners), completed an initial public offering of its common units (see Note 17).Duncan Energy Partners owns equity interests in certain of our midstream energy businesses.References to DEP GP mean DEP Holdings, LLC, which is the general partner of Duncan Energy Partners and is wholly owned by EPO. On Dece

General Accounting Matters

General Accounting Matters
	9 Months Ended Sep. 30, 2009 USD / shares	12 Months Ended Dec. 31, 2008 USD / shares
Notes To Financial Statements [Abstract]
General Accounting Matters	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 9 ENTERPRISE PRODUCTS PARTNERS L.P. NOTES TO UNAUDITED SUPPLEMENTAL CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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 marke	Note 2.General Accounting Matters Allowance for Doubtful Accounts Our allowance for doubtful accounts is determined based on specific identification and estimates of future uncollectible accounts.Our procedure for determining the allowance for doubtful accounts is based on (i) historical experience with customers, (ii) the perceived financial stability of customers based on our research and (iii) the levels of credit we grant to customers.In addition, we may increase the allowance account in response to the specific identification of customers involved in bankruptcy proceedings and similar financial difficulties.On a routine basis, we review estimates associated with the allowance for doubtful accounts to ensure that we have recorded sufficient reserves to cover potential losses.Our allowance also includes estimates for uncollectible natural gas imbalances based on specific identification of accounts. 10 ENTERPRISE PRODUCTS PARTNERS L.P. NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS The following table presents the activity of our allowance for doubtful accounts for the periods indicated: For the Year Ended December 31, 2008 2007 2006 Balance at beginning of period $ 21.8 $ 23.5 $ 37.6 Charges to expense 3.5 2.6 0.5 Deductions (7.6 ) (4.3 ) (14.6 ) Balance at end of period $ 17.7 $ 21.8 $ 23.5 See Credit Risk Due to Industry Concentrations in Note 21 for more information. Cash and Cash Equivalents Cash and cash equivalents represent unrestricted cash on hand and highly liquid investments with original maturities of less than three months from the date of purchase. Our Supplemental Statements of Consolidated Cash Flows are prepared using the indirect method.The indirect method derives net cash flows provided by operating activities by adjusting net income to remove (i) the effects of all deferrals of past operating cash receipts and payments, such as changes during the period in inventory, deferred income and similar transactions, (ii) the effects of all accruals of expected future operating cash receipts and cash payments, such as changes during the period in receivables and payables, (iii) other non-cash amounts such as depreciation, amortization, changes in the fair market value of derivative instruments and equity in earnings in unconsolidated affiliates and (iv) the effects of all items classified as investing or financing cash flows, such as proceeds from asset sales and related transactions or extinguishment of debt. Consolidation Policy Our supplemental consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest, after the elimination of all material intercompany accounts and transactions.We also consolidate other entities and ventures in which we possess a controlling financial interest as well as partnership interests where we are the sole general partner of the partnership.We evaluate our financial interests in business enterprises to determine if they represent variable interest entities where we a

Recent Accounting Developments

Recent Accounting Developments
	12 Months Ended Dec. 31, 2008 USD / shares
Notes To Financial Statements [Abstract]
Recent Accounting Pronouncements	Note 3.Recent Accounting Developments The accounting standard setting bodies have recently issued the following accounting guidance that will affect our future financial statements:SFAS 141(R), Business Combinations;FASB Staff Position (FSP) SFAS142-3, Determination of the Useful Life of Intangible Assets;SFAS 157, Fair Value Measurements;SFAS 160, Noncontrolling Interests in Consolidated Financial Statements An amendment of ARB 51; SFAS 161, Disclosures about Derivative Instruments and Hedging Activities An Amendment of SFAS 133; Emerging Issues Task Force (EITF) 08-6, Equity Method Investment Accounting Considerations; and EITF 07-4, Application of the Two Class Method Under SFAS 128, Earnings Per Share, to Master Limited Partnerships (MLPs). 18 ENTERPRISE PRODUCTS PARTNERS L.P. NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS SFAS 141(R), Business Combinations. SFAS 141(R) replaces SFAS 141, Business Combinations and was effective January 1, 2009.SFAS 141(R) retains the fundamental requirements of SFAS 141 in that the acquisition method of accounting (previously termed the purchase method) be used for all business combinations and for the acquirer to be identified in each business combination.SFAS 141(R) defines the acquirer as the entity that obtains control of one or more businesses in a business combination and establishes the acquisition date as the date that the acquirer achieves control.This new guidance also retains guidance in SFAS 141 for identifying and recognizing intangible assets separately from goodwill.SFAS 141(R) will have an impact on the way in which we evaluate acquisitions. The objective of SFAS 141(R) is to improve the relevance, representational faithfulness, and comparability of the information a reporting entity provides in its financial reports about business combinations and their effects.To accomplish this, SFAS 141(R) establishes principles and requirements for how the acquirer: Recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interests in the acquiree. Recognizes and measures any goodwill acquired in the business combination or a gain resulting from a bargain purchase.SFAS 141(R) defines a bargain purchase as a business combination in which the total acquisition-date fair value of the identifiable net assets acquired exceeds the fair value of the consideration transferred plus any noncontrolling interest in the acquiree, and requires the acquirer to recognize that excess in net income as a gain attributable to the acquirer. Determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS 141(R) also requires that direct costs of an acquisition (e.g. finders fees, outside consultants, etc.) be expensed as incurred and not capitalized as part of the purchase price. FSP FAS142-3, Determination of the Useful Life of Intangible Assets. FSP142-3 revised the factors that should be considered in developing renewal or extension assumptions used in determining the useful life of recognize

Revenue Recognition

Revenue Recognition
	12 Months Ended Dec. 31, 2008 USD / shares
Notes To Financial Statements [Abstract]
Revenue Recognition	Note 4.Revenue Recognition In general, we recognize revenue from our customers when all of the following criteria are met:(i) persuasive evidence of an exchange arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the buyers price is fixed or determinable and (iv) collectability is reasonably assured.The following information provides a general description of our underlying revenue recognition policies by business segment: NGL Pipelines Services NGL Pipelines Services includes our (i) natural gas processing business and related NGL marketing activities; (ii) NGL pipelines, including our Mid-America Pipeline System; (iii) NGL and related product storage facilities; and (iv) NGL fractionation facilities.This segment also includes our import and export terminal operations. In our natural gas processing business, we enter into margin-band contracts, percent-of-liquids contracts, percent-of-proceeds contracts, fee-based contracts, hybrid-contracts (i.e. mixed percent-of-liquids and fee-based) and keepwhole contracts.Under margin-band and keepwhole contracts, we take ownership of mixed NGLs extracted from the producers natural gas stream and recognize revenue when the extracted NGLs are delivered and sold to customers under NGL marketing sales contracts.In the same way, revenue is recognized under our percent-of-liquids contracts except that the volume of NGLs we extract and sell is less than the total amount of NGLs extracted from the producers natural gas.Under a percent-of-liquids contract, the producer retains title to the remaining percentage of mixed NGLs we extract.Under a percent-of-proceeds contract, we share in the proceeds generated from the sale of the mixed NGLs we extract on the producers behalf.If a cash fee for natural gas processing services is stipulated by the contract, we record revenue when the natural gas has been processed and delivered to the producer. Our NGL marketing activities generate revenues from the sale of NGLs obtained from either our natural gas processing activities or purchased from third parties on the open market.Revenues from these sales contracts are recognized when the NGLs are delivered to customers.In general, the sales prices referenced in these contracts are market-related and can include pricing differentials for such factors as delivery location. Under our NGL pipeline transportation contracts and tariffs, revenue is recognized when volumes have been delivered to customers.Revenue from these contracts and tariffs is generally based upon a fixed fee per gallon of liquids transported multiplied by the volume delivered.Transportation fees charged under these arrangements are either contractual or regulated by governmental agencies such as the Federal Energy Regulatory Commission (FERC). We collect storage revenues under our NGL and related product storage contracts based on the number of days a customer has volumes in storage multiplied by a storage rate (as defined in each contract).Under these contracts, revenue is recognized ratably over the length of the storage period.With respect to capacity reservation agreements, we collect a fee for reser

Accounting for Equity Awards

Accounting for Equity Awards
	9 Months Ended Sep. 30, 2009 USD / shares	12 Months Ended Dec. 31, 2008 USD / shares
Notes To Financial Statements [Abstract]
Accounting for Equity Awards	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. 11 ENTERPRISE PRODUCTS PARTNERS L.P. NOTES TO UNAUDITED SUPPLEMENTAL CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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	Note 5.Accounting for Equity Awards We account for equity awards in accordance with SFAS 123(R), Share-Based Payment.SFAS 123(R) requires us to recognize compensation expense related to equity awards based on the fair value of the award at grant date.The fair value of restricted unit awards is based on the market price of the underlying common units on the date of grant. The fair value of other equity awards is estimated using the Black-Scholes option pricing model.The fair value of an equity-classified award (such as a restricted unit award) is amortized to earnings on a straight-line basis over the requisite service or vesting period.Compensation expense for liability-classified awards (such as unit appreciation rights (UARs)) is recognized over the requisite service or vesting period of an award based on the fair value of the award remeasured at each reporting period.Liability-classified awards are settled in cash upon vesting. As used in the context of the EPCO plans, the term restricted unit represents a time-vested unit under SFAS 123(R).Such awards are non-vested until the required service period expires. Upon our adoption of SFAS 123(R), we recognized, as a benefit, a cumulative effect of a change in accounting principle of $1.5 million based on the SFAS 123(R) requirement to recognize compensation expense based upon the grant date fair value of an equity award and the application of an estimated forfeiture rate to unvested awards.In addition, previously recognized deferred compensation expense of $14.6 million related to our restricted common units was reversed on January 1, 2006. 24 ENTERPRISE PRODUCTS PARTNERS L.P. NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS Prior to our adoption of SFAS 123(R), we did not recognize any compensation expense related to unit options; however, compensation expense was recognized in connection with awards granted by EPE Unit I and the issuance of restricted units.The effects of applying SFAS 123(R) during the year ended December 31, 2006 did not have a material effect on our net income or basic and diluted earnings per unit.Since we adopted SFAS 123(R) using the modified prospective method, we have not restated the financial statements of prior periods to reflect this new standard. The following tables summarize our equity compensation amounts by plan for each of the periods indicated: For the Year Ended December 31, 2008 2007 2006 Employee Partnerships $ 6.3 $ 4.3 $ 2.1 EPCO 1998 Long-Term Incentive Plan (EPCO 1998 Plan): Unit options 0.4 4.4 0.7 Restricted units 9.9 8.4 5.2 Total EPCO 1998 Plan (1) 10.3 12.8 5.9 Enterprise Products 2008 Long-Term Incentive Plan(EPD 2008 LTIP): Unit options 0.1 -- -- Total EPD 2008 LTIP 0.1 -- -- TEPPCO 1999 Phantom Unit Retention Plan (TEPPCO 1999 Plan) (0.1 ) 0.9 0.9 TEPPCO 2000 Long-Term Incentive Plan (TEPPCO 2000 LTIP) (0.3 ) 0.4 0.4 TEPPCO 2005 Phantom Unit Plan (TEPPCO 2005 Phantom Unit Plan) (

Employee Benefit Plans

Employee Benefit Plans
	12 Months Ended Dec. 31, 2008 USD / shares
Notes To Financial Statements [Abstract]
Employee Benefit Plans	Note 6.Employee Benefit Plans Dixie In 2005, we acquired a controlling ownership interest in Dixie, which resulted in Dixie becoming a consolidated subsidiary of ours.Dixie employs the personnel that operate its pipeline system and certain of these employees are eligible to participate in a defined contribution plan and pension and postretirement benefit plans.Due to the immaterial nature of Dixies employee benefit plans to our consolidated financial position, results of operations and cash flows, our discussion is limited to the following: Defined Contribution Plan.Dixie contributed $0.3 million to its company-sponsored defined contribution plan for each of the years ended December 31, 2008 and 2007. Pension and Postretirement Benefit Plans.Dixies pension plan is a noncontributory defined benefit plan that provides for the payment of benefits to retirees based on their age at retirement, years of service and average compensation.Dixies postretirement benefit plan also provides medical and life insurance to retired employees.The medical plan is contributory and the life insurance plan is noncontributory.Dixie employees hired after July 1, 2004 are not eligible for pension and other benefit plans after retirement. The following table presents Dixies benefit obligations, fair value of plan assets and funded status at December 31, 2008: Pension Postretirement Plan Plan Projected benefit obligation $ 7.7 $ 5.0 Accumulated benefit obligation 5.7 -- Fair value of plan assets 4.0 -- Funded status (3.7 ) (5.0 ) Projected benefit obligations and net periodic benefit costs are based on actuarial estimates and assumptions.The weighted-average actuarial assumptions used in determining the projected benefit obligation at December 31, 2008 were as follows:discount rate of 6.4%; rate of compensation increase of 4.0% for both the pension and postretirement plans; and a medical trend rate of 8.5% for 2009 grading to an ultimate trend of 5.0% for 2015 and later years.Dixies net pension and postretirement benefit costs for 2008 were $0.6 million and $0.4 million, respectively.Dixies net pension and postretirement benefit costs for 2007 were $1.1 million (including settlement loss of $0.6 million) and $0.4 million, respectively. 35 ENTERPRISE PRODUCTS PARTNERS L.P. NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS Future benefits expected to be paid from Dixies pension and postretirement plans are as follows for the periods indicated: Pension Postretirement Plan Plan 2009 $ 0.3 $ 0.3 2010 0.3 0.4 2011 0.5 0.4 2012 0.4 0.4 2013 0.8 0.4 2014 through 2017 4.2 2.1 Total $ 6.5 $ 4.0 Included in accumulated other comprehensive loss on the Supplemental Consolidated Balance Sheets at December 31, 2008 and 2007 are the following amounts that have not been recognized in net periodic pension costs: December 31, 2008 2007 Unrecognized transition obligation $ 0.9 $ 1.0 Net of t

Derivative Instruments, Hedging

Derivative Instruments, Hedging Activities and Fair Value Measurements
	9 Months Ended Sep. 30, 2009 USD / shares	12 Months Ended Dec. 31, 2008 USD / shares
Notes To Financial Statements [Abstract]
Derivative Instruments, Hedging Activities and Fair Value Measurements	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. 16 ENTERPRISE PRODUCTS PARTNERS L.P. NOTES TO UNAUDITED SUPPLEMENTAL CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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 inst	Note 7.Derivative Instruments, Hedging Activities and Fair Value Measurements We are exposed to financial market risks, including changes in commodity prices, interest rates and foreign exchange rates.We may use derivative instruments (e.g., futures, forwards, swaps, options and other derivative instruments with similar characteristics) to mitigate the risks of certain identifiable and anticipated transactions.In general, the types of risks we attempt to hedge are those related to (i) the variability of future earnings, (ii) fair values of certain debt obligations and (iii) cash flows resulting from changes in applicable interest rates, commodity prices or exchange rates. See Note 14 for information regarding our consolidated debt obligations. We routinely review our outstanding derivative instruments in light of current market conditions.If market conditions warrant, some derivative instruments may be closed out in advance of their contractual settlement dates thus realizing income or loss depending on the specific hedging criteria.When this occurs, we may enter into a new derivative instrument to reestablish the hedge to which the closed instrument relates. 36 ENTERPRISE PRODUCTS PARTNERS L.P. NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS The following table presents gains (losses) recorded in net income attributable to our interest rate risk and commodity risk hedging transactions for the periods indicated.These amounts do not present the corresponding gains (losses) attributable to the underlying hedged items. For the Year Ended December 31, 2008 2007 2006 Interest Rate Risk Hedging Portfolio: Enterprise Products Partners (excluding Duncan Energy Partners): Ineffective portion of cash flow hedges $ (0.1 ) $ -- $ -- Reclassification of cash flow hedge amounts from AOCI, net (0.5 ) 5.5 4.2 Loss from treasury lock cash flow hedge (3.6 ) -- -- Other gains (losses) from derivative transactions 9.4 (3.7 ) 3.4 Duncan Energy Partners: Ineffective portion of cash flow hedges -- (0.2 ) -- Reclassification of cash flow hedge amounts from AOCI, net (2.0 ) 0.4 -- Total hedging gains, net, in consolidated interest expense $ 3.2 $ 2.0 $ 7.6 Commodity Risk Hedging Portfolio: Enterprise Products Partners: Reclassification of cash flow hedge amounts fromAOCI, net - natural gas marketing activities $ (30.2 ) $ (3.3 ) $ (1.3 ) Reclassification of cash flow hedge amounts from AOCI, net - crude oil marketing activities (37.9 ) (1.6 ) 0.2 Reclassification of cash flow hedge amounts fromAOCI, net - NGL and petrochemical operations (28.2 ) (4.6 ) 13.9 Other gains (losses) from derivative transactions 29.4 (20.5 ) (2.4 ) Total hedging gains (losses), net, in consolidated operating costs and expenses $ (66.9 ) $ (30.0 ) $ 10.4 The following table provides additional i

Cumulative Effect of Change in

Cumulative Effect of Change in Accounting Principle
	12 Months Ended Dec. 31, 2008 USD / shares
Notes To Financial Statements [Abstract]
Cumulative Effect of Change in Accounting Principle	Note 8.Cumulative Effect of Change in Accounting Principle SFAS 123(R) requires us to recognize compensation expense related to equity awards based on the fair value of the award at grant date.The fair value of restricted unit awards is based on the market price of the underlying common units on the date of grant.The fair value of other equity awards is estimated using the Black-Scholes option pricing model.Under SFAS 123(R), the fair value of an equity award is amortized to earnings on a straight-line basis over the requisite service or vesting period for equity awards.Compensation for liability-classified awards is recognized over the requisite service or vesting period of an award based on the fair value of the award remeasured at each reporting period.Liability awards will be cash settled upon vesting. 44 ENTERPRISE PRODUCTS PARTNERS L.P. NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS Upon adoption of SFAS 123(R), we recognized, as a benefit, the cumulative effect of a change in accounting principle of $1.5 million based on the SFAS 123(R) requirement to recognize compensation expense based upon the grant date fair value of equity awards and the application of an estimated forfeiture rate to unvested awards.See Note 5 for additional information regarding our accounting for equity awards. The following table shows unaudited pro forma net income for the year ended December 31, 2006, assuming the accounting change noted above was applied retroactively to January 1, 2006. Pro Forma income statement amounts: Historical net income attributable to Enterprise Products Partners L.P. $ 601.1 Adjustments to derive pro forma net income attributable to Enterprise Products Partners L.P.: Effect of implementation of SFAS 123(R): Remove cumulative effect of change in accountingprinciple recorded in January 2006 (1.5 ) Pro forma net income attributable to Enterprise Products Partners L.P. 599.6 EPGP interest (1) (103.0 ) Pro forma net income allocated to limited partners $ 496.6 Pro forma per unit data (basic): Historical units outstanding 414.4 Per unit data: As reported $ 1.20 Pro forma $ 1.20 Pro forma per unit data (diluted): Historical units outstanding 414.7 Per unit data: As reported $ 1.20 Pro forma $ 1.20 (1)Includes provisions of EITF 07-4(see Note 19).

Inventories

Inventories
	9 Months Ended Sep. 30, 2009 USD / shares	12 Months Ended Dec. 31, 2008 USD / shares
Notes To Financial Statements [Abstract]
Inventories Disclosure	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 $13.82billion 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.	Note 9.Inventories Our inventory amounts were as follows at the dates indicated: December 31, 2008 2007 Working inventory (1) $ 211.9 $ 397.5 Forward sales inventory (2) 193.1 28.2 Total inventory $ 405.0 $ 425.7 (1) Working inventory is comprised of inventories of natural gas, crude oil, refined products, lubrication oils, NGLs and certain petrochemical products that are either available-for-sale or used in the provision for services. (2) Forward sales inventory consists of identified natural gas, crude oil and NGL volumes dedicated to the fulfillment of forward sales contracts. Our inventory values reflect payments for product purchases, freight charges associated with such purchase volumes, terminal and storage fees, vessel inspection costs, demurrage charges and other related costs.We value our inventories at the lower of average cost or market. Operating costs and expenses, as presented on our Supplemental Statements of Consolidated Operations, include cost of sales amounts related to the sale of inventories.Our costs of sales were $31.20 billion, $23.49 billion and $20.71 billion for the years ended December 31, 2008, 2007 and 2006, respectively. 45 ENTERPRISE PRODUCTS PARTNERS L.P. NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS In those instances where we take ownership of inventory volumes through percent-of-liquids contracts and similar arrangements (as opposed to actually purchasing volumes for cash from third parties, see Note 4), these volumes are valued at market-related prices during the month in which they are acquired.We capitalize as a component of inventory those ancillary costs (e.g. freight-in and other handling and processing charges) incurred in connection with volumes obtained through such contracts. Due to fluctuating commodity prices, we recognize lower of cost or market (LCM) adjustments when the carrying value of our inventories exceed their net realizable value.These non-cash charges are a component of cost of sales in the period they are recognized and generally affect our segment operating results in the following manner: Write-downs of NGL inventories associated with our NGL marketing activities are recorded within our NGL Pipelines Services business segment; Write-downs of natural gas inventories are recorded as a cost of our natural gas pipeline operations within our Onshore Natural Gas Pipelines Services business segment; Write-downs of crude oil inventories are recorded as a cost of our crude oil operations within our Onshore Crude Oil Pipelines Services; and Write-downs of petrochemical and related inventories, including refined products, associated with our Petrochemical Refined Products business segment are recorded as a cost of our petrochemical marketing activities, refined products businesses or octane enhancement production business, as applicable. For the years ended December 31, 2008, 2007 and 2006, we recognized LCM adjustments of approximately $63.0 million, $14.1 million and $20.3 million, respectively.To the extent our commodity hedging strategie

Property, Plant and Equipment

Property, Plant and Equipment
	9 Months Ended Sep. 30, 2009 USD / shares	12 Months Ended Dec. 31, 2008 USD / shares
Notes To Financial Statements [Abstract]
Property, Plant and Equipment	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 Oiltankings 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 se	Note 10.Property, Plant and Equipment Our property, plant and equipment values and accumulated depreciation balances were as follows at the dates indicated: Estimated Useful Life December 31, in Years 2008 2007 Plants and pipelines (1) 3-40 (6) $ 15,266.7 $ 13,395.2 Underground and other storage facilities (2) 5-40 (7) 1,203.9 981.6 Platforms and facilities (3) 20-31 634.8 637.8 Transportation equipment (4) 3-10 50.9 41.0 Marine vessels (5) 20-30 453.0 -- Land 254.5 220.5 Construction in progress 2,015.4 1,588.3 Total 19,879.2 16,864.4 Less accumulated depreciation 3,146.4 2,555.3 Property, plant and equipment, net $ 16,732.8 $ 14,309.1 (1) Plants and pipelines include processing plants; NGL, petrochemical, crude oil and natural gas pipelines; terminal loading and unloading facilities; office furniture and equipment; buildings; laboratory and shop equipment; and related assets. (2) Underground and other storage facilities include underground product storage caverns; above ground storage tanks; water wells; and related assets. (3) Platforms and facilities include offshore platforms and related facilities and other associated assets. (4) Transportation equipment includes vehicles and similar assets used in our operations. (5) See Note 12 for additional information regarding the acquisition of marine services businesses in February 2008. (6) In general, the estimated useful lives of major components of this category are as follows:processing plants, 20-35 years; pipelines and related equipment, 5-40 years; terminal facilities, 10-35 years; delivery facilities, 20-40 years; office furniture and equipment, 3-20 years; buildings, 20-40 years; and laboratory and shop equipment, 5-35 years. (7) In general, the estimated useful lives of major components of this category are as follows:underground storage facilities, 5-35 years; storage tanks, 10-40 years; and water wells, 5-35 years. The following table summarizes our depreciation expense and capitalized interest amounts for the periods indicated: For the Year Ended December 31, 2008 2007 2006 Depreciation expense (1) $ 595.9 $ 515.7 $ 433.7 Capitalized interest (2) 90.7 86.5 66.4 (1)Depreciation expense is a component of costs and expenses as presented in our Supplemental 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. We reviewed assumptions underlying the estimated remaining useful lives of certain of our assets during the first quarter of 2008.As a result of our review, effective January 1, 2008, we revised the remaining useful lives of these assets, most notably the assets that constitute our Texas Intrastate System.This revision increased the remaining useful life of such assets

Investments in Unconsolidated A

Investments in Unconsolidated Affiliates
	9 Months Ended Sep. 30, 2009 USD / shares	12 Months Ended Dec. 31, 2008 USD / shares
Notes To Financial Statements [Abstract]
Investments in Unconsolidated Affiliates	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 th	Note 11.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 16 for a general discussion of our business segments.The following table shows our investments in unconsolidated affiliates at the dates indicated: Ownership Percentage at December 31, December 31, 2008 2008 2007 NGL Pipelines Services: Venice Energy Service Company, L.L.C. (VESCO) 13.1% $ 37.7 $ 40.1 K/D/S Promix, L.L.C. (Promix) 50% 46.4 51.5 Baton Rouge Fractionators LLC (BRF) 32.2% 24.2 25.4 Skelly-Belvieu Pipeline Company, L.L.C. (Skelly-Belvieu) (1) 49% 36.0 -- Onshore Natural Gas Pipelines Services: Evangeline (2) 49.5% 4.5 3.5 White River Hub, LLC (White River Hub) (3) 50% 21.4 -- Onshore Crude Oil Pipelines Services Seaway Crude Pipeline Company (Seaway) 50% 186.2 184.8 Offshore Pipelines Services: Poseidon Oil Pipeline, L.L.C. (Poseidon) 36% 60.2 58.4 Cameron Highway Oil Pipeline Company (Cameron Highway) (4) 50% 250.9 256.6 Deepwater Gateway, L.L.C. (Deepwater Gateway) 50% 104.8 111.2 Neptune 25.7% 52.7 55.5 Nemo (5) 33.9% 0.4 2.9 Petrochemical Refined Products Services: Baton Rouge Propylene Concentrator, LLC (BRPC) 30% 12.6 13.3 La Porte (6) 50% 3.9 4.1 Centennial Pipeline LLC (Centennial) 50% 69.7 77.9 Other 25% 0.3 0.4 Total $ 911.9 $ 885.6 (1)In December 2008, we acquired a 49% ownership interest in Skelly-Belvieu. (2)Refers to our ownership interests in Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp., collectively. (3)In February 2008, we acquired a 50% ownership interest in White River Hub. (4)During the year ended December 31, 2007, we contributed $216.5 million to Cameron Highway to fund our portion of the repayment of Cameron Highways debt. (5)The December 31, 2007 amount includes a $7.0 million non-cash impairment charge attributable to our investment in Nemo. (6)Refers to our ownership interests in La Porte Pipeline Company, L.P. and La Porte GP, LLC, collectively. On occasion, the price we pay to acquire an ownership interest in a company exceeds the underlying book value of the capital accounts we acquire.Such excess cost amounts are included within the carrying values of our investments in and advances to unconsolidated affiliates.At December 31, 2008 and 2007, our investments in Promix, Skelly-Belvieu, La Porte, Neptune, Poseidon, Cameron Highway, Seaway and Centennial included excess cost amounts totaling $75.6 million and $69.5 million, respectively, all of which were attributable to the fair va

Business Combinations

Business Combinations
	9 Months Ended Sep. 30, 2009 USD / shares	12 Months Ended Dec. 31, 2008 USD / shares
Notes To Financial Statements [Abstract]
Business Combinations	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 12. Business Combinations The following table presents our cash used for business combinations for the periods indicated: For Year Ended December 31, 2008 2007 2006 Great Divide Gathering System acquisition $ 125.2 $ -- $ -- Encinal acquisition -- 0.1 145.2 Piceance Creek acquisition -- 0.4 100.0 South Monco acquisition -- 35.0 -- Canadian Enterprise Gas Products, Ltd. acquisition -- -- 17.7 Cenac acquisition 258.1 -- -- Horizon acquisition 87.6 -- -- Terminal assets purchased from New York LP Gas Storage, Inc. -- -- 9.9 Refined products terminal purchased from MississippiTerminal and Marketing Inc. -- -- 5.8 Additional ownership interests in Dixie 57.1 0.4 12.9 Additional ownership interests in Tri-States and Belle Rose 19.9 -- -- Other business combinations 5.5 -- 0.7 Total $ 553.4 $ 35.9 $ 292.2 The following information highlights aspects of certain transactions noted in the preceding table: 2008 Transactions Our expenditures for business combinations during the year ended December 31, 2008 were $553.4 million and primarily reflect the acquisitions described below. On a pro forma consolidated basis, our revenues, costs and expenses, operating income, net income attributable to Enterprise Products Partners L.P. and earnings per unit amounts would not have differed materially from those we actually reported for 2008, 2007 and 2006 due to the immaterial nature of our 2008 business combination transactions. 55 ENTERPRISE PRODUCTS PARTNERS L.P. NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS Great Divide Gathering System Acquisition. In December 2008, one of our subsidiaries, Enterprise Gas Processing, LLC, purchased a 100% membership interest in Great Divide Gathering, LLC (Great Divide) for cash consideration of $125.2 million. Great Divide was wholly owned by EnCana Oil Gas (EnCana). The assets of Great Divide consist of a 31-mile natural gas gathering system, the Great Divide Gathering System, located in the Piceance Basin of northwestern Colorado.The Great Divide Gathering System extends from the southern portion of the Piceance Basin, including production from EnCanas Mamm Creek field, to a pipeline interconnection with our Piceance Basin Gathering System.Volumes of natural gas originating on the Great Divide Gathering System are transported through our Piceance Creek Gathering System to our 1.4 Bcf/d Meeker natural gas treating and processing complex.A significant portion of these volumes are produced by EnCana, one of the largest natural gas producers in the region, and are dedicated the Great Divide and Piceance Creek Gathering Systems for the life of the associated lease holdings. Tri-States and Belle Rose Acquisitions. In October 2008, we acquired additional 16.7% membership interests in both Tri-States NGL Pipeline, L.L.C. (Tri-States) and Belle Rose NGL Pipeline, L.L.C. (Belle Rose) for total cash considera

Intangible Assets and Goodwill

Intangible Assets and Goodwill
	9 Months Ended Sep. 30, 2009 USD / shares	12 Months Ended Dec. 31, 2008 USD / shares
Notes To Financial Statements [Abstract]
Intangible Assets and Goodwill	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 30 ENTERPRISE PRODUCTS PARTNERS L.P. NOTES TO UNAUDITED SUPPLEMENTAL CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Based on information currently available, we estimate th	Note 13.Intangible Assets and Goodwill Identifiable Intangible Assets The following table summarizes our intangible assets at the dates indicated: December 31, 2008 December 31, 2007 Gross Accum. Carrying Gross Accum. Carrying Value Amort. Value Value Amort. Value NGL Pipelines Services: (1) Customer relationship intangibles $ 237.4 $ (68.7 ) $ 168.7 $ 224.6 $ (49.0 ) $ 175.6 Contract-based intangibles 320.3 (137.6 ) 182.7 316.1 (116.6 ) 199.5 Segment total 557.7 (206.3 ) 351.4 540.7 (165.6 ) 375.1 Onshore Natural Gas Pipelines Services: Customer relationship intangibles (2) 372.0 (103.2 ) 268.8 362.3 (81.4 ) 280.9 Gas gathering agreements 464.0 (213.1 ) 250.9 464.0 (181.7 ) 282.3 Other contract-based intangibles 101.3 (36.6 ) 64.7 101.3 (28.0 ) 73.3 Segment total 937.3 (352.9 ) 584.4 927.6 (291.1 ) 636.5 Onshore Crude Oil Pipelines Services: Contract-based intangibles 10.0 (3.1 ) 6.9 10.0 (2.7 ) 7.3 Segment total 10.0 (3.1 ) 6.9 10.0 (2.7 ) 7.3 Offshore Pipelines Services: Customer relationship intangibles 205.8 (90.7 ) 115.1 205.8 (73.9 ) 131.9 Contract-based intangibles 1.2 (0.1 ) 1.1 1.2 (0.1 ) 1.1 Segment total 207.0 (90.8 ) 116.2 207.0 (74.0 ) 133.0 Petrochemical Refined Products Services: Customer relationship intangibles 104.9 (13.8 ) 91.1 53.6 (9.1 ) 44.5 Contract-based intangibles (3) 41.1 (8.2 ) 32.9 21.1 (3.4 ) 17.7 Segment total 146.0 (22.0 ) 124.0 74.7 (12.5 ) 62.2 Total all segments $ 1,858.0 $ (675.1 ) $ 1,182.9 $ 1,760.0 $ (545.9 ) $ 1,214.1 (1) In 2008, we acquired $6.0 million of certain permits related to our Mont Belvieu complex and had $12.7 million of purchase price allocation adjustmentsrelated to San Felipe customer relationships from the December 2007 South Monco acquisition. (2) In 2008, we acquired $9.8 million of customer relationships due to the Great Divide business combination. (3) In 2007, we paid $11.2 million for certain air emission credits related to our Morgans Point facility. The following table presents the amortization expense of our intangible assets by segment for the periods indicated: For the Year Ended December 31, 2008 2007 2006 NGL Pipelines Services $ 40.7 $ 38.2 $ 33.1 Onshore Natural Gas Pipelines Services 61.7 64.4 64.0 Onshore Crude Oil Pipelines Services 0.5 0.5 0.6 Offshore Pipelines Services 16.9 19.3 22.2 Petrochemical Refined Products Services 10.2 2.8 2.2 Tot

Debt Obligations

Debt Obligations
	9 Months Ended Sep. 30, 2009 USD / shares	12 Months Ended Dec. 31, 2008 USD / shares
Notes To Financial Statements [Abstract]
Debt Obligations	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 a	Note 14.Debt Obligations Our consolidated debt obligations consisted of the following at the dates indicated: December 31, 2008 2007 EPO senior debt obligations: Multi-Year Revolving Credit Facility, variable rate, due November 2012 $ 800.0 $ 725.0 Pascagoula MBFC Loan, 8.70% fixed-rate, due March 2010 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 (1) 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 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 -- Senior Notes N, 6.50% fixed-rate, due January 2019 700.0 -- Senior Notes O, 9.75% fixed-rate, due January 2014 500.0 -- TEPPCO senior debt obligations: TEPPCO Revolving Credit Facility, variable rate, due December 2012 516.7 490.0 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 -- TEPPCO Senior Notes, 6.65% fixed-rate, due April 2018 350.0 -- TEPPCO Senior Notes, 7.55% fixed-rate, due April 2038 400.0 -- TE Products Senior Notes, 6.45% fixed-rate, due January 2008 -- 180.0 TE Products Senior Notes, 7.51% fixed-rate, due January 2028 -- 175.0 Duncan Energy Partners debt obligations: DEP I Revolving Credit Facility, variable rate, due February 2011 202.0 200.0 DEP II Term Loan Agreement, variable rate, due December 2011 282.3 -- Dixie Revolving Credit Facility, variable rate, due June 2010 (2) -- 10.0 Total principal amount of senior debt obligations 10,030.1 7,191.5 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 682.7 700.0 TEPPCO Junior Subordinated Notes, fixed/variable rate, due June 2067 300.0 300.0 Total principal amount of senior and junior debt obligations 11,562.8 8,741.5 Other, non-principal amounts: Change in fair value of debt-related derivative instruments (see Note 7) 51.9 14.8 Unamortized discounts, net of premiums

Equity and Distributions

Equity and Distributions
	9 Months Ended Sep. 30, 2009 USD / shares	12 Months Ended Dec. 31, 2008 USD / shares
Notes To Financial Statements [Abstract]
Equity and Distributions	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 EPOs 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 EPOs 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 EPOs 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 EPOs 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 EPGPs Board of Directors on September 1, 2009, the per unit purchase price of $25.25 was calculated based	Note 15.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. In accordance with the Partnership Agreement, capital accounts are maintained for our general partner and limited partners.The capital account provisions of our Partnership Agreement incorporate principles established for U.S. Federal income tax purposes and are not comparable to the equity accounts reflected under GAAP in our supplemental consolidated financial statements. Our Partnership Agreement sets forth the calculation to be used in determining the amount and priority of cash distributions that our limited partners and general partner will receive. The Partnership Agreement also contains provisions for the allocation of net earnings and losses to our limited partners and general partner.For purposes of maintaining partner capital accounts, the Partnership Agreement specifies 74 ENTERPRISE PRODUCTS PARTNERS L.P. NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS that items of income and loss shall be allocated among the partners in accordance with their respective percentage interests.Normal income and loss allocations according to percentage interests are done only after giving effect to priority earnings allocations in an amount equal to incentive cash distributions allocated to our general partner. In August 2005, we revised our Partnership Agreement to allow EPGP, at its discretion, to elect not to make its proportionate capital contributions to us in connection with our issuance of limited partner interests, in which case its 2% general partner interest would be proportionately reduced.At the time of such offerings, EPGP has historically contributed cash to us to maintain its 2% general partner interest.EPGP made such cash contributions to us during the years ended December 31, 2008 and 2007.If EPGP exercises this option in the future, the amount of earnings we allocate to it and the cash distributions it receives from us will be reduced accordingly.If this occurs, EPGP can, under certain conditions, restore its full 2% general partner interest by making additional cash contributions to us. Equity offerings and registration statements In general, the Partnership Agreement authorizes us to issue an unlimited number of additional limited partner interests and other equity securities for such consideration and on such terms and conditions as may be established by EPGP in its sole discretion (subject, under certain circumstances, to the approval of our unitholders). In August 2007, we filed a universal shelf registration statement with the SEC that allows us to issue an unlimited amount of debt and equity securities.In January 2009, we sold 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 universal she

Business Segments

Business Segments
	9 Months Ended Sep. 30, 2009 USD / shares	12 Months Ended Dec. 31, 2008 USD / shares
Notes To Financial Statements [Abstract]
Business Segments	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	Note 16.Business Segments As previously mentioned in Note 1, we revised our business segments and related disclosures as a result of the TEPPCO Merger.We have five reportable business segments: NGL Pipelines Services, Onshore Natural Gas Pipelines Services, Onshore Crude Oil Pipelines Services, Offshore Pipelines Services and Petrochemical Refined Products Services.Our business segments are generally organized and managed according to the type of services rendered (or technologies employed) and products produced and/or sold.The following information summarizes the principal operations and activities of each of our new business segments: NGL Pipelines Services includes our (i) natural gas processing business and related NGL marketing activities; (ii) NGL pipelines, including our Mid-America Pipeline System; (iii) NGL and related product storage facilities; and (iv) NGL fractionation facilities.This segment also includes our import and export terminal operations. Onshore Natural Gas Pipelines Services includes our onshore natural gas pipeline systems that provide for the gathering and transportation of natural gas in Alabama, Colorado, Louisiana, Mississippi, New Mexico, Texas and Wyoming.We own two salt dome natural gas storage facilities located in Mississippi and lease natural gas storage facilities located in Texas and Louisiana.This segment also includes our natural gas marketing activities. Onshore Crude Oil Pipelines Services business segment includes our onshore crude oil pipelines and related storage terminals.This segment also includes our related crude oil marketing activities. Offshore Pipelines Services includes our (i) offshore natural gas pipelines strategically located to serve production areas including some of the most active drilling and development regions in the Gulf of Mexico, (ii) offshore Gulf of Mexico crude oil pipeline systems and (iii) six multi- 80 ENTERPRISE PRODUCTS PARTNERS L.P. NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS purpose offshore hub platforms located in the Gulf of Mexico with crude oil or natural gas processing capabilities. Petrochemical Refined Products Services includes our (i) propylene fractionation plants and related activities, (ii) butane isomerization facilities, (iii) octane enhancement facility, (iv) refined products pipelines, including our Products Pipeline System, and related activities and (v) marine transportation assets and other services. We evaluate segment performance based on the non-GAAP financial measure of gross operating margin.Gross operating margin (either in total or by individual segment) is an important performance measure of the core profitability of our operations.This measure forms the basis of our internal financial reporting and is used by our management in deciding how to allocate capital resources among business segments.We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results.The GAAP financial measure most directly comparable to total segment gross operating margin is operating income.Our non-GAAP financial measu

Related Party Transactions

Related Party Transactions
	9 Months Ended Sep. 30, 2009 USD / shares	12 Months Ended Dec. 31, 2008 USD / shares
Notes To Financial Statements [Abstract]
Related Party Transactions	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 stateme	Note 17.Related Party Transactions The following table summarizes our related party transactions for the periods indicated. For the Year Ended December 31, 2008 2007 2006 Revenues from consolidated operations EPCO and affiliates $ -- $ 0.2 $ 55.8 Energy Transfer Equity and subsidiaries 618.5 294.5 -- Unconsolidated affiliates 396.9 290.5 304.9 Total $ 1,015.4 $ 585.2 $ 360.7 Cost of sales EPCO and affiliates $ 40.1 $ 34.0 $ 75.3 Energy Transfer Equity and subsidiaries 173.9 26.9 -- Unconsolidated affiliates 58.6 41.0 45.2 Total $ 272.6 $ 101.9 $ 120.5 Operating costs and expenses EPCO and affiliates $ 423.1 $ 353.7 $ 328.5 Energy Transfer Equity and subsidiaries 18.3 8.3 -- Cenac and affiliates 45.4 -- -- Unconsolidated affiliates (2.4 ) -- (5.2 ) Total $ 484.4 $ 362.0 $ 323.3 General and administrative expenses EPCO and affiliates $ 91.0 $ 82.6 $ 63.7 Cenac and affiliates 2.9 -- -- Unconsolidated affiliates (0.1 ) -- -- Total $ 93.8 $ 82.6 $ 63.7 Other income (expense) EPCO and affiliates $ (0.3 ) $ (0.2 ) $ 0.7 Unconsolidated affiliates -- -- 0.3 Total $ (0.3 ) $ (0.2 ) $ 1.0 We believe that the terms and provisions of our related party agreements are fair to us; however, such agreements and transactions may not be as favorable to us as we could have obtained from unaffiliated third parties. Relationship with EPCO and affiliates We have an extensive and ongoing relationship with EPCO and its affiliates, which include the following significant entities that are not a part of our consolidated group of companies: EPCO and its private company subsidiaries; EPGP, our sole general partner; Enterprise GP Holdings, which owns and controls our general partner; and the Employee Partnerships (see Note 5). We also have an ongoing relationship with Duncan Energy Partners, the financial statements of which are consolidated with those of our own.Our transactions with Duncan Energy Partners are eliminated in the preparation of our consolidated financial statements.A description of our relationship with Duncan Energy Partners is presented within this Note 17. EPCO is a private company controlled by Dan L. Duncan, who is also a Director and Chairman of EPGP, our general partner.At December 31, 2008, EPCO and its affiliates beneficially owned 152,506,527 (or 34.5%) of our outstanding common units, which includes 13,670,925 of our common units owned by Enterprise GP Holdings.At December 31, 2008, EPCO and affiliates beneficially owned 85 ENTERPRISE PRODUCTS PARTNERS L.P. NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS 17,073,315 (or 16.3%) of TEPPCOs common units, including 4,400,000 common units owned by E

Provision for Income Taxes

Provision for Income Taxes
	12 Months Ended Dec. 31, 2008 USD / shares
Notes To Financial Statements [Abstract]
Provision for Income Taxes	Note 18.Provision for Income Taxes Our provision for income taxes relates primarily to federal and state income taxes of Seminole and Dixie, our two largest corporations subject to such income taxes.In addition, with the amendment of the Texas Franchise Tax in 2006, we have become a taxable entity in the state of Texas.Our federal and state income tax provision is summarized below: For the Year Ended December 31, 2008 2007 2006 Current: Federal $ 4.9 $ 4.7 $ 7.7 State 23.9 5.1 1.2 Foreign 0.4 0.1 -- Total current 29.2 9.9 8.9 Deferred: Federal 0.8 2.7 6.1 State 1.0 3.1 7.0 Foreign -- -- -- Total deferred 1.8 5.8 13.1 Total provision for income taxes $ 31.0 $ 15.7 $ 22.0 94 ENTERPRISE PRODUCTS PARTNERS L.P. NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS A reconciliation of the provision for income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows: For the Year Ended December 31, 2008 2007 2006 Pre Tax Net Book Income (NBI) $ 1,219.9 $ 853.7 $ 808.1 Revised Texas franchise tax 23.9 7.7 8.8 State income taxes (net of federal benefit) 0.5 0.3 (0.4 ) Federal income taxes computed by applying the federal statutory rate to NBI of corporate entities 6.3 5.3 13.4 Taxes charged to cumulative effect of change in accounting principle -- -- -- Valuation allowance (1.4 ) 2.3 0.1 Other permanent differences 1.7 0.1 0.1 Provision for income taxes $ 31.0 $ 15.7 $ 22.0 Effective income tax rate 2.5 % 1.8 % 2.7 % Significant components of deferred tax assets and deferred tax liabilities as of December 31, 2008 and 2007 are as follows: December 31, 2008 2007 Deferred tax assets: Net operating loss carryovers $ 26.3 $ 23.3 Property, plant and equipment 0.8 -- Credit carryover -- -- Charitable contribution carryover -- -- Employee benefit plans 2.6 3.2 Deferred revenue 1.0 0.6 Reserve for legal fees and damages 0.3 0.4 Equity investment in partnerships 0.6 0.4 AROs 0.1 0.1 Accruals 0.9 1.1 Total deferred tax assets 32.6 29.1 Valuationallowance 3.9 5.3 Net deferred tax assets 28.7 23.8 Deferred tax liabilities: Property, plant and equipment 92.9 40.5 Other 0.1 0.1 Total deferred tax liabilities 93.0 40.6 Total net deferred tax liabilities (64.3 ) (16.8 ) Current portion of total net deferred tax assets 1.4 1.1 Long-term portion of total net deferr

Earnings Per Unit

Earnings Per Unit
	9 Months Ended Sep. 30, 2009 USD / shares	12 Months Ended Dec. 31, 2008 USD / shares
Notes To Financial Statements [Abstract]
Earnings Per Unit	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	Note 19.Earnings Per Unit Basic earnings per unit is computed by dividing net income or loss available to limited partner interests by the weighted-average number of distribution-bearing units outstanding during a period.Diluted earnings per unit is computed by dividing net income or loss available to limited partner interests by the sum of (i) the weighted-average number of distribution-bearing units outstanding during a period (as used in determining basic earnings per unit); (ii) the weighted-average number of performance-based phantom units outstanding during a period; and (iii) the number of incremental common units resulting from the assumed exercise of dilutive unit options outstanding during a period (the incremental option units). In a period of net losses, restricted units, phantom units and incremental option units are excluded from the calculation of diluted earnings per unit due to their antidilutive effect.The dilutive incremental option units are calculated using the treasury stock method, which assumes that proceeds from the exercise of all in-the-money options at the end of each period are used to repurchase common units at an average market value during the period.The amount of common units remaining after the proceeds are exhausted represents the potentially dilutive effect of the securities. The amount of net income or loss available to limited partner interests is net of our general partners share of such earnings.The following table presents the net income available to EPGP for the periods indicated: For The Year Ended December 31, 2008 2007 2006 Net income attributable to Enterprise Products Partners L.P. $ 954.0 $ 533.6 $ 601.1 Less incentive earnings allocations to EPGP (125.9 ) (107.4 ) (86.7 ) Net income available after incentive earnings allocation 828.1 426.2 514.4 Multiplied by EPGP ownership interest 2.0 % 2.0 % 2.0 % Standard earnings allocation to EPGP $ 16.6 $ 8.5 $ 10.3 Incentive earnings allocation to EPGP $ 125.9 $ 107.4 $ 86.7 Standard earnings allocation to EPGP 16.6 8.5 10.3 Net income available to EPGP 142.5 115.9 97.0 Adjustment for EITF 07-4 (1) 5.2 4.5 6.0 Net income available to EPGP for EPU purposes $ 147.7 $ 120.4 $ 103.0 (1)For purposes of computing basic and diluted earnings per unit, we used the provisions of EITF 07-4. 96 ENTERPRISE PRODUCTS PARTNERS L.P. NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS 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 Year Ended December 31, 2008 2007 2006 BASIC EARNINGS PER UNIT Numerator Net income attributable to Enterprise Products Partners L.P. $ 954.0 $ 533.6 $ 601.1 Net income available to EPGP for EPU purposes

Commitments and Contingencies

Commitments and Contingencies
	9 Months Ended Sep. 30, 2009 USD / shares	12 Months Ended Dec. 31, 2008 USD / shares
Notes To Financial Statements [Abstract]
Commitments and Contingencies	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 TEPPCOs partnership agreement, including a reduction in the maximum tier of TEPPCOs incentive distribution rights in exchange for TEPPCO units.The amended complaint seeks (i) rescission of the amendments to TEPPCOs 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 co	Note 20.Commitments and Contingencies Litigation On occasion, we or our unconsolidated affiliates are named as a defendant in litigation relating to our normal business activities, including regulatory and environmental matters.Although we are insured against various business risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings as a result of our ordinary business activities.We are unaware of any significant litigation, pending or threatened, that could have a significant adverse effect on our financial position, results of operations or cash flows. On September 18, 2006, Peter Brinckerhoff, a purported unitholder of TEPPCO, filed a complaint in the Court of Chancery of New Castle County in the State of Delaware, in his individual capacity, as a putative class action on behalf of other unitholders of TEPPCO and derivatively on behalf of TEPPCO, concerning, among other things, certain transactions involving TEPPCO and us or our affiliates. Mr. Brinkerhoff filed an amended complaint on July 12, 2007. The amended complaint names as defendants (i) TEPPCO, its current and certain former directors, and certain of its affiliates; (ii) us and certain of our affiliates; (iii) EPCO.; and (iv) Dan L. Duncan. 97 ENTERPRISE PRODUCTS PARTNERS L.P. NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS The amended complaint alleges, among other things, that the defendants caused TEPPCO to enter into certain transactions that were unfair to TEPPCO or otherwise unfairly favored Enterprise Products Partners or its affiliates over TEPPCO.These transactions are alleged to include: (i) the joint venture to further expand the Jonah system entered into by TEPPCO and Enterprise Products Partners in August2006; (ii) the sale by TEPPCO of its Pioneer natural gas processing plant to Enterprise Products Partners in March2006; and (iii) certain amendments to TEPPCOs partnership agreement, including a reduction in the maximum tier of TEPPCOs IDRs in exchange for TEPPCO units.The amended complaint seeks (i)rescission of the amendments to TEPPCOs partnership agreement; (ii)damages for profits and special benefits allegedly obtained by defendants as a result of the alleged wrongdoings in the amended complaint; and (iii)awarding plaintiff costs of the action, including fees and expenses of his attorneys and experts. We believe this lawsuit is without merit and intend to vigorously defend against it. On February 14, 2007, EPO received a letter from the Environment and Natural Resources Division (ENRD) of the U.S. Department of Justice (DOJ) related to an ammonia release in Kingman County, Kansas on October 27, 2004 from a pressurized anhydrous ammonia pipeline owned by a third party, Magellan Ammonia Pipeline, L.P. (Magellan) and a previous release of ammonia on September 27, 2004 from the same pipeline.EPO was the operator of this pipeline until July 1, 2008. The ENRD has indicated that it may pursue civil damages against EPO and Magellan as a result of these incidents. Based on th

Significant Risks and Uncertain

Significant Risks and Uncertainties
	9 Months Ended Sep. 30, 2009 USD / shares	12 Months Ended Dec. 31, 2008 USD / shares
Notes To Financial Statements [Abstract]
Significant Risks and Uncertainties	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. EPCOs deductible for onshore physical damage from windstorms increased from $10.0 million per storm to $25.0 million per storm.EPCOs 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.EPCOs 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, EPCOs 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. 52 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 EPCOs 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	Note 21.Significant Risks and Uncertainties Nature of Operations in Midstream Energy Industry Our operations are within the midstream energy industry, which includes gathering, transporting, processing, fractionating and storing natural gas, NGLs, crude oil, refined products and certain petrochemicals.We also market natural gas, NGLs, crude oil and other hydrocarbon products.As such, our financial position, results of operations and cash flows may be affected by changes in the commodity prices of these hydrocarbon products, including changes in the relative price levels among these products (e.g., natural gas processing margins are influenced by the ratio of natural gas prices to crude oil prices).The prices of hydrocarbon products are subject to fluctuation in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control. Our profitability could be impacted by a decline in the volume of hydrocarbon products transported, gathered, processed or stored at our facilities.A material decrease in natural gas or crude oil production or crude oil refining, for reasons such as depressed commodity prices or a decrease in exploration and development activities, could result in a decline in the volume of natural gas, NGLs, refined products and crude oil handled by our facilities. A reduction in demand for natural gas, crude oil, NGL and other hydrocarbon products by the petrochemical, refining or heating industries, whether because of (i) general economic conditions, (ii) reduced demand by consumers for the end products made using such products, (iii) increased competition from other products due to pricing differences, (iv) adverse weather conditions, (v) government regulations affecting energy commodity prices, production levels of hydrocarbons or the content of motor gasoline or (vi) other reasons, could adversely affect our financial position, results of operations and cash flows. Credit Risk due to Industry Concentrations A substantial portion of our revenues are derived from companies in the domestic natural gas, NGL and petrochemical industries.This concentration could affect our overall exposure to credit risk since these customers may be affected by similar economic or other conditions.We generally do not require collateral for our accounts receivable; however, we do attempt to negotiate offset, prepayment, or automatic debit agreements with customers that are deemed to be credit risks in order to minimize our potential exposure to any defaults. Our revenues are derived from a wide customer base. During 2008, 2007 and 2006, our largest customer was Valero Energy Corporation and its affiliates, which accounted for 11.2%, 8.9% and 9.3%, respectively, of our revenues. On January 6, 2009, LyondellBasell Industries (LBI) announced that its U.S. operations had voluntarily filed to reorganize under Chapter 11 of the U.S. Bankruptcy Code.For 2008, LBI accounted for 5.9% of consolidated revenues.At the time of the bankruptcy filing, we had approximately $17.3 million of credit exposure to LBI, which was reduced to approximately $10.0 million through remedies provided under cer

Supplemental Cash Flow Informat

Supplemental Cash Flow Information
	9 Months Ended Sep. 30, 2009 USD / shares	12 Months Ended Dec. 31, 2008 USD / shares
Notes To Financial Statements [Abstract]
Supplemental Cash Flow Information	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 22.Supplemental Cash Flow Information We determine net cash flows provided by operating activities using the indirect method, which adjusts net income for items that did not affect cash.Under GAAP, we use the accrual basis of accounting to determine net income.This basis of accounting requires that we record revenue when earned and expenses when incurred.Earned revenues may include credit sales that have not been collected in cash and expenses incurred that may not have been paid in cash.The extent to which changes in operating accounts influence net cash flows provided by operating activities generally depends on the following: The timing of cash receipts from revenue transactions and cash payments for expense transactions near the end of each reporting period.For example, if significant cash receipts are posted on the last day of the current reporting period, but subsequent payments on expense invoices are made on 104 ENTERPRISE PRODUCTS PARTNERS L.P. NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS the first day of the next reporting period, net cash flows provided by operating activities will reflect an increase in the current reporting period that will be reduced as payments are made in the next period.We employ prudent cash management practices and monitor our daily cash requirements to meet our ongoing liquidity needs. If commodity or other prices increase between reporting periods, changes in accounts receivable and accounts payable and accrued expenses may appear larger than in previous periods; however, overall levels of receivables and payables may still reflect normal ranges.From a receivables standpoint, we monitor the amount of credit extended to customers. Additions to inventory for forward sales transactions or other reasons or increased expenditures for prepaid items would be reflected as a use of cash and reduce overall cash provided by operating activities in a given reporting period.As these assets are charged to expense in subsequent periods, the expense amount is reflected as a positive change in operating accounts; however, there is no impact on operating cash flows. In addition to the adjustments noted above, non-cash charges in the income statement are added back to net income and non-cash credits are deducted to compute net cash flows provided by operating activities.Examples of non-cash charges include depreciation and amortization. The following table provides information regarding (i) the net effect of changes in our operating assets and liabilities; (ii) cash payments for interest and (iii) cash payments for federal and state income taxes for the periods indicated. For the Year Ended December 31, 2008 2007 2006 Decrease (increase) in: Accounts and notes receivable trade $ 1,333.9 $ (1,175.8 ) $ 97.6 Accounts receivable related party 3.6 (37.0 ) 5.3 Inventories 14.9 (20.4 ) (110.5 ) Prepaid and other current assets (26.9 ) 36.6 25.0 Other assets (11.7 ) (6.7 ) (34.9 ) Increase (decrease) in:

Quarterly Financial Information

Quarterly Financial Information (Unaudited)
	12 Months Ended Dec. 31, 2008 USD / shares
Notes To Financial Statements [Abstract]
Quarterly Financial Information (Unaudited)	Note 23.Quarterly Financial Information (Unaudited) The following table presents selected quarterly financial data for the years ended December 31, 2008 and 2007: First Second Third Fourth Quarter Quarter Quarter Quarter For the Year Ended December 31, 2008: Revenues $ 8,506.4 $ 10,538.6 $ 10,499.1 $ 5,925.5 Operating income 469.7 454.6 401.0 423.1 Income before the cumulative effect of change in accounting principle 336.0 320.0 258.1 274.8 Net income 336.0 320.0 258.1 274.8 Net income attributable to Enterprise Products Partners L.P. 259.6 263.3 203.1 228.0 Earnings per unit before the cumulative effect of change in accounting principle: Basic $ 0.51 $ 0.52 $ 0.38 $ 0.43 Diluted $ 0.51 $ 0.52 $ 0.38 $ 0.43 Earnings per unit: Basic $ 0.51 $ 0.52 $ 0.38 $ 0.43 Diluted $ 0.51 $ 0.52 $ 0.38 $ 0.43 For the Year Ended December 31, 2007: Revenues $ 5,340.2 $ 6,294.4 $ 6,721.7 $ 8,357.5 Operating income 342.5 284.1 284.3 284.1 Income before the cumulative effect of change in accounting principle 250.8 195.7 172.9 218.6 Net income 250.8 195.7 172.9 218.6 Net income attributable to Enterprise Products Partners L.P. 112.0 142.2 117.6 161.8 Earnings per unit before the cumulative effect of change in accounting principle: Basic $ 0.19 $ 0.26 $ 0.20 $ 0.30 Diluted $ 0.19 $ 0.26 $ 0.20 $ 0.30 Earnings per unit: Basic $ 0.19 $ 0.26 $ 0.20 $ 0.30 Diluted $ 0.19 $ 0.26 $ 0.20 $ 0.30

Supplemental Condensed Consolid

Supplemental Condensed Consolidated Financial Information of EPO
	9 Months Ended Sep. 30, 2009 USD / shares	12 Months Ended Dec. 31, 2008 USD / shares
Notes To Financial Statements [Abstract]
Condensed Consolidated Financial Information of EPO	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. 54 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, December31, 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 guaranteedEnterprise 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 a	Note 24.Supplemental Condensed Consolidated Financial Information of EPO EPO conducts substantially all of our business.Currently, we have no independent operations and no material assets outside those of EPO.EPO consolidates the financial statements of Duncan Energy Partners with those of its own. 106 ENTERPRISE PRODUCTS PARTNERS L.P. NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS Immediately after the closing of the TEPPCO Merger, 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 the Dixie revolving credit facility (terminated January 2009) and the 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 14 for additional information regarding our consolidated debt obligations. The reconciling items between our supplemental consolidated financial statements and those of EPO are insignificant.The following table presents supplemental condensed consolidated balance sheet data for EPO at the dates indicated: December 31, 2008 2007 ASSETS Current assets $ 3,114.6 $ 4,068.4 Property, plant and equipment, net 16,732.8 14,309.1 Investments in and advances to unconsolidated affiliates, net 911.9 885.6 Intangible assets, net 1,182.9 1,214.1 Goodwill 2,019.6 1,813.3 Other assets 261.1 232.0 Total $ 24,222.9 $ 22,522.5 LIABILITIES AND EQUITY Current liabilities $ 3,100.8 $ 4,958.6 Long-term debt 11,637.9 8,417.2 Other long-term liabilities 176.5 122.5 Equity 9,307.7 9,024.2 Total $ 24,222.9 $ 22,522.5 Total EPO debt obligations guaranteed by Enterprise Products Partners L.P. $ 8,561.8 $ 6,686.5 The following table presents supplemental condensed consolidated statements of operations data for EPO for the periods indicated: For the Year Ended December 31, 2008 2007 2006 Revenues $ 35,469.6 $ 26,713.8 $ 23,612.2 Costs and expenses 33,753.4 25,526.8 22,512.3 Equity in earnings of unconsolidated affiliates 34.9 10.5 25.2 Operating income 1,751.1 1,197.5 1,125.1 Other expense (528.6 ) (343.0 ) (315.0 ) Income before provision for income taxes and the cumulative effect of change in accounting principle 1,222.5 854.5 810.1 Provision for income taxes (31.0 ) (15.8 ) (21.9 ) Income before the cumulative effect of change in accounting principle 1,191.5 838.7 788.2 Cumulative effect of change i

Subsequent Events

Subsequent Events
	9 Months Ended Sep. 30, 2009 USD / shares	12 Months Ended Dec. 31, 2008 USD / shares
Notes To Financial Statements [Abstract]
Subsequent Events	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 EPOs Multi-Year Revolving Credit Facility and (iii) for general partnership purposes. Senior Notes Q and R rank equal with EPOs 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 55 ENTERPRISE PRODUCTS PARTNERS L.P. NOTES TO UNAUDITED SUPPLEMENTAL CONDENSED CONSOLIDATED FINANCIAL STATEMENTS covenants, which generally restrict EPOs 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.TEPPCOs 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 Mer	Note 25.Subsequent Events We have evaluated subsequent events through December 4, 2009, which is the date we filed this Exhibit 99.2 to Current Report on Form 8-K with the SEC. TOPS Matters - April and September 2009 In April 2009, we dissociated (or exited) from TOPS (see Note 10).As a result, net income for the second quarter of 2009 reflects a non-cash charge of $68.4 million, which represented our cumulative investment in TOPS through the date of dissociation.In addition, in September 2009, we entered into a settlement agreement with certain affiliates of Oiltanking that resolved all disputes between the parties related to the business and affairs of TOPS.We recognized approximately $67.0 million of expense during the third quarter of 2009 in connection with this cash settlement.Of the $135.4 million in expense recognized during 2009, $67.7 million was allocated to noncontrolling interest. River Terminal Charges in September 2009 In September 2009, TEPPCO determined that its Aberdeen and Boligee river terminals were impaired due to the current level of throughput volumes at the terminals and the indefinite suspension of construction projects for three new proposed river terminals. As a result, TEPPCO recorded a $17.6 million non-cash asset impairment charge during the third quarter of 2009. The assets and operations related to TEPPCOs river terminals are part of our Petrochemical Refined Products Services business segment. These charges relating to the river terminals are allocated to former owners of TEPPCO within noncontrolling interst. Also, TEPPCO is party to a 10-year throughput and deficiency agreement with Colonial Pipeline Company (Colonial) whereby Colonial agreed to provide transportation services to TEPPCOs Boligee river terminal.The agreement provided for minimum annual throughput commitments.As a result of TEPPCOs decision to indefinitely suspend the three new proposed river terminal construction projects, TEPPCO accrued a liability of $28.7 million for deficiency fees that it reasonably estimated would be incurred over the term of the Colonial contract since the minimum throughput volumes were no longer expected to be achieved.

Document Information

Document Information
	0 Months Ended Oct. 26, 2009
Document Information [Line Items]
Document Type	8-K
Document Period End Date	2009-10-26
Amendment Flag	false

Entity Information

Entity Information
	0 Months Ended Oct. 26, 2009
Entity Information [Line Items]
Entity Registrant Name	ENTERPRISE PRODUCTS PARTNERS L P
Entity Central Index Key	0001061219