Enterprise Products Partners (EPD) 10-K 1 Mar 10 2009 FY Annual report Financial data

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)
In Millions	12 Months Ended Dec. 31, 2009	12 Months Ended Dec. 31, 2008
Current assets:
Cash and cash equivalents	54.7	61.7
Restricted cash	63.6	203.8
Accounts and notes receivable - trade, net of allowance for doubtful accounts	3,099	2028.5
Accounts receivable - related parties	38.4	35.3
Inventories	711.9	405
Derivative assets	113.8	218.6
Prepaid and other current assets	165.5	149.8
Total current assets	4246.9	3102.7
Property, plant and equipment, net	17689.2	16732.8
Investments in unconsolidated affiliates	890.6	911.9
Intangible assets, net of accumulated amortization	1064.8	1182.9
Goodwill	2018.3	2019.6
Other assets	241.8	261.7
Total assets	26151.6	24211.6
Current liabilities:
Accounts payable - trade	410.6	388.9
Accounts payable - related parties	69.8	17.4
Accrued product payables	3,393	1845.7
Accrued expenses	108.5	65.7
Accrued interest	228	188.3
Derivative liabilities	93	302.9
Other current liabilities	233.1	292.3
Total current liabilities	4,536	3101.2
Long-term debt:
Senior debt obligations - principal	9764.3	10030.1
Junior subordinated notes - principal	1532.7	1532.7
Other	49.4	75.1
Total long-term debt	11346.4	11637.9
Deferred tax liabilities	71.7	66.1
Other long-term liabilities	155.2	110.5
Commitments and contingencies	-	-
Limited Partners:
Common units	9173.5	6036.9
Restricted common units	37.7	26.2
Class B Units	118.5	0
General partner	190.8	123.6
Accumulated other comprehensive loss	-8.4	-97.2
Total Enterprise Products Partners L.P. partners' equity	9512.1	6089.5
Noncontrolling interest	530.2	3206.4
Total equity	10042.3	9295.9
Total liabilities and equity	26151.6	24211.6

PARENTHETICAL DATA TO THE CONSO

PARENTHETICAL DATA TO THE CONSOLIDATED BALANCE SHEETS (USD $)
In Millions, except Share data	Dec. 31, 2009	Dec. 31, 2008
Current assets:
Allowance for doubtful accounts	16.8	17.7
Accumulated amortization	$795	675.1
Limited Partners:
Common units outstanding	603,202,828	439,354,731
Restricted common units outstanding	2,720,882	2,080,600
Class B Units Outstanding	4,520,431	0

STATEMENTS OF CONSOLIDATED OPER

STATEMENTS OF CONSOLIDATED OPERATIONS (USD $)
In Millions, except Per Share data	12 Months Ended Dec. 31, 2009	12 Months Ended Dec. 31, 2008	12 Months Ended Dec. 31, 2007
Revenues:
Third parties	24911.9	34454.2	26128.6
Related parties	599	1015.4	585.2
Total revenues (see Note 14)	25510.9	35469.6	26713.8
Operating costs and expenses:
Third parties	22547.6	32861.9	24938.2
Related parties	1018.2	757	463.9
Total operating costs and expenses	23565.8	33618.9	25402.1
General and administrative costs:
Third parties	77.3	43.4	44.6
Related parties	95	93.8	82.6
Total general and administrative costs	172.3	137.2	127.2
Total costs and expenses	23738.1	33756.1	25529.3
Equity in income of unconsolidated affiliates	51.2	34.9	10.5
Operating income	1,824	1748.4	1,195
Other income (expense):
Interest expense	-641.8	-540.7	(413)
Interest income	2.3	7.4	11.1
Other, net	-4.1	4.8	60.6
Total other expense, net	-643.6	-528.5	-341.3
Income before provision for income taxes	1180.4	1219.9	853.7
Provision for income taxes	-25.3	(31)	-15.7
Net income	1155.1	1188.9	838
Net income attributable to noncontrolling interest (see Note 13)	-124.2	-234.9	-304.4
Net income attributable to Enterprise Products Partners L.P.	1030.9	954	533.6
Net income allocated to: (see Note 13)
Limited partners	852.2	811.5	417.7
General partner	178.7	142.5	115.9
Earnings per unit: (see Note 17)
Basic and diluted earnings per unit	1.73	1.84	0.95

STATEMENTS OF CONSOLIDATED COMP

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (USD $)
In Millions	12 Months Ended Dec. 31, 2009	12 Months Ended Dec. 31, 2008	12 Months Ended Dec. 31, 2007
Statement of Income and Comprehensive Income [Abstract]
Net income	1155.1	1188.9	$838
Cash flow hedges:
Commodity derivative instrument losses during period	-179.6	-170.2	-46.9
Reclassification adjustment for losses included in net income related to commodity derivative instruments	294.2	96.3	9.5
Interest rate derivative instrument gains (losses) during period	18.6	(52)	-8.9
Reclassification adjustment for (gains) losses included in net income related to interest rate derivative instruments	10.8	-1.1	-5.8
Foreign currency derivative gains (losses)	-10.2	9.3	1.3
Total cash flow hedges	133.8	-117.7	-50.8
Foreign currency translation adjustment	2.1	-2.5	2
Change in funded status of pension and postretirement plans, net of tax	0	-1.3	0
Total other comprehensive income (loss)	135.9	-121.5	-48.8
Comprehensive income	1,291	1067.4	789.2
Comprehensive income attributable to noncontrolling interest	-130.2	-229.7	-258.8
Comprehensive income attributable to Enterprise Products Partners L.P.	1160.8	837.7	530.4

STATEMENTS OF CONSOLIDATED CASH

STATEMENTS OF CONSOLIDATED CASH FLOWS (USD $)
In Millions	12 Months Ended Dec. 31, 2009	12 Months Ended Dec. 31, 2008	12 Months Ended Dec. 31, 2007
Operating activities:
Net income	1155.1	1188.9	$838
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion	833.4	737.8	658.4
Non-cash impairment charges	33.5	0	0
Equity in income of unconsolidated affiliates	-51.2	-34.9	-10.5
Distributions received from unconsolidated affiliates	86.6	80.8	87
Operating lease expenses paid by EPCO	0.7	2	2.1
Gain from asset sales and related transactions	0	(4)	-67.4
Loss on forfeiture of investment in Texas Offshore Port System	68.4	0	0
Loss on early extinguishment of debt	0	1.6	1.6
Deferred income tax expense	4.5	6.2	7.6
Changes in fair market value of derivative instruments	0.4	-0.1	1.3
Effect of pension settlement recognition	-0.1	-0.1	0.6
Net effect of changes in operating accounts (see Note 20)	245.9	-411.1	434.9
Net cash flows provided by operating activities	2377.2	1567.1	1953.6
Investing activities:
Capital expenditures	-1584.3	-2539.6	(2,764)
Contributions in aid of construction costs	17.8	27.2	57.6
Decrease (increase) in restricted cash	140.2	-132.8	-47.3
Cash used for business combinations (see Note 10)	-107.3	-553.5	-35.9
Acquisition of intangible assets	-1.4	-5.8	-14.5
Investments in unconsolidated affiliates	-18.8	-64.7	-236.8
Proceeds from asset sales and related transactions	3.6	22.3	169.1
Other investing activities	3.3	0	0
Cash used in investing activities	-1546.9	-3246.9	-2871.8
Financing activities:
Borrowings under debt agreements	7376.6	13,188	7629.8
Repayments of debt	-7653.5	-10434.3	-5799.9
Debt issuance costs	-14.9	-27.6	-20.6
Cash distributions paid to partners	-1254.8	-1037.4	-957.7
Cash distributions paid to noncontrolling interest	(340)	-383.9	-326.8
Cash contributions from noncontrolling interest	138.7	311.5	304.7
Net cash proceeds from issuance of common units	912.7	142.8	69.2
Repurchase of restricted units and options	0	0	-1.5
Acquisition of treasury units	-2.1	-1.9	0
Monetization of interest rate derivative instruments (see Note 6)	0.2	-66.5	49.1
Cash provided by (used in) financing activities	-837.1	1690.7	946.3
Effect of exchange rate changes on cash	-0.2	-0.5	0.4
Net change in cash and cash equivalents	-6.8	10.9	28.1
Cash and cash equivalents, January 1	61.7	51.3	22.8
Cash and Cash Equivalents, December 31	54.7	61.7	51.3

STATEMENTS OF CONSOLIDATED EQUI

STATEMENTS OF CONSOLIDATED EQUITY (USD $)
In Millions	12 Months Ended Dec. 31, 2009	12 Months Ended Dec. 31, 2008	12 Months Ended Dec. 31, 2007
Partners' Capital, Beginning Balance	9295.9	9016.5	9124.9
Net income	1155.1	1188.9	838
Operating lease expenses paid by EPCO	0.7	2	2.1
Cash distributions paid to partners	-1252.4	-1036.8	-958.2
Unit option reimbursements to EPCO	-2.4	-0.6	(3)
Cash distributions paid to noncontrolling interest	(340)	-383.9	-326.8
Acquisition of treasury units	-2.1	-1.9	0
Net cash proceeds from issuance of common units	911	142.1	61.6
Cash proceeds from exercise of unit options	1.7	0.7	7.6
Cash contributions from noncontrolling interest	138.7	311.5	304.7
Common units issued in connection with acquisitions	0.3	186.6
Deconsolidation of Texas Offshore Port System	-33.4
Repurchase of restricted units and options	0	0	-1.5
Amortization of equity awards	23.3	14.1	14.7
Acquisition of interest in subsidiary	10.3	-22.3
Change in funded status of pension and postretirement plans		-1.3	1.2
Foreign currency translation adjustment	2.1	-2.5	2
Cash flow hedges	133.8	-117.7	-50.8
Other	-0.3	0.5
Partners' Capital, Ending Balance	10042.3	9295.9	9016.5
Limited Partner [Member]
Partners' Capital, Beginning Balance	6063.1	5992.9	6329.8
Net income	852.2	811.5	417.7
Operating lease expenses paid by EPCO	0.7	2	2.1
Cash distributions paid to partners	-1069.3	-892.7	-833.8
Unit option reimbursements to EPCO	-2.4	-0.6	(3)
Cash distributions paid to noncontrolling interest	0	0	0
Acquisition of treasury units	-2.1	-1.9
Net cash proceeds from issuance of common units	892.8	139.3	60.4
Cash proceeds from exercise of unit options	1.7	0.7	7.5
Cash contributions from noncontrolling interest	0	0	0
Common units issued in connection with acquisitions	2574.1	0
Deconsolidation of Texas Offshore Port System	0
Repurchase of restricted units and options			-1.5
Amortization of equity awards	18.9	11.9	13.7
Acquisition of interest in subsidiary	0	0
Change in funded status of pension and postretirement plans		0	0
Foreign currency translation adjustment	0	0	0
Cash flow hedges	0	0	0
Other	0	0
Partners' Capital, Ending Balance	9329.7	6063.1	5992.9
General Partner [Member]
Partners' Capital, Beginning Balance	123.6	122.3	129.3
Net income	178.7	142.5	115.9
Operating lease expenses paid by EPCO	0	0	0
Cash distributions paid to partners	-183.1	-144.1	-124.4
Unit option reimbursements to EPCO	0	0	0
Cash distributions paid to noncontrolling interest	0	0	0
Acquisition of treasury units	0	0
Net cash proceeds from issuance of common units	18.2	2.8	1.2
Cash proceeds from exercise of unit options	0	0	0.1
Cash contributions from noncontrolling interest	0	0	0
Common units issued in connection with acquisitions	53.1	0
Deconsolidation of Texas Offshore Port System	0
Repurchase of restricted units and options			0
Amortization of equity awards	0.3	0.1	0.2
Acquisition of interest in subsidiary	0	0
Change in funded status of pension and postretirement plans		0	0
Foreign currency translation adjustment	0	0	0
Cash flow hedges	0	0	0
Other	0	0
Partners' Capital, Ending Balance	190.8	123.6	122.3
Accumulated Other Comprehensive Income [Member]
Partners' Capital, Beginning Balance	-97.2	19.1	21.1
Net income	0	0	0
Operating lease expenses paid by EPCO	0	0	0
Cash distributions paid to partners	0	0	0
Unit option reimbursements to EPCO	0	0	0
Cash distributions paid to noncontrolling interest	0	0	0
Acquisition of treasury units	0	0
Net cash proceeds from issuance of common units	0	0	0
Cash proceeds from exercise of unit options	0	0	0
Cash contributions from noncontrolling interest	0	0	0
Common units issued in connection with acquisitions	-41.1	0
Deconsolidation of Texas Offshore Port System	0
Repurchase of restricted units and options			0
Amortization of equity awards	0	0	0
Acquisition of interest in subsidiary	0	0
Change in funded status of pension and postretirement plans		-1.3	1.2
Foreign currency translation adjustment	2.1	-2.5	2
Cash flow hedges	127.8	-112.5	-5.2
Other	0	0
Partners' Capital, Ending Balance	-8.4	-97.2	19.1
Noncontrolling Interest [Member]
Partners' Capital, Beginning Balance	3206.4	2882.2	2644.7
Net income	124.2	234.9	304.4
Operating lease expenses paid by EPCO	0	0	0
Cash distributions paid to partners	0	0	0
Unit option reimbursements to EPCO	0	0	0
Cash distributions paid to noncontrolling interest	(340)	-383.9	-326.8
Acquisition of treasury units	0	0
Net cash proceeds from issuance of common units	0	0	0
Cash proceeds from exercise of unit options	0	0	0
Cash contributions from noncontrolling interest	138.7	311.5	304.7
Common units issued in connection with acquisitions	-2585.8	186.6
Deconsolidation of Texas Offshore Port System	-33.4
Repurchase of restricted units and options			0
Amortization of equity awards	4.1	2.1	0.8
Acquisition of interest in subsidiary	10.3	-22.3
Change in funded status of pension and postretirement plans		0	0
Foreign currency translation adjustment	0	0	0
Cash flow hedges	6	-5.2	-45.6
Other	-0.3	0.5
Partners' Capital, Ending Balance	530.2	3206.4	2882.2

Partnership Organization and Ba

Partnership Organization and Basis of Presentation
	12 Months Ended Dec. 31, 2009 USD / shares
Notes To Financial Statements [Abstract]
Partnership Organization and Basis of Presentation	Note 1.Partnership Organization and Basis of Presentation We are a publicly traded Delaware limited partnership, the common units of which are listed on the NYSE under the ticker symbol EPD.We were formed in April 1998 to own and operate certain natural gas liquids (NGLs) related businesses of EPCO.We conduct substantially all of our business through our wholly owned subsidiary, EPO.We are owned 98% by our limited partners and 2% by our general partner, EPGP.Enterprise GP Holdings owns 100% of EPGP.The general partner of Enterprise GP Holdings is 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. On October 26, 2009, the related mergers of our wholly owned subsidiaries with TEPPCO and TEPPCO GP were completed.See TEPPCO Merger and Basis of Presentation within this Note 1 for additional information regarding the TEPPCO Merger. On February 5, 2007, Duncan Energy Partners, a consolidated subsidiary of ours, completed an initial public offering of its common units.Through its initial public offering and a subsequent drop down transaction on December 8, 2008, Duncan Energy Partners owns equity interests in certain of our midstream energy businesses.DEP GP, the general partner of Duncan Energy Partners, is wholly owned by EPO. For financial reporting purposes, we consolidate the financial statements of 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.Also, due to common control of the entities by Dan L. Duncan, the initial consolidated balance sheet of Duncan Energy Partners reflects our historical carrying basis in each of the subsidiaries contributed to Duncan Energy Partners.Public ownership of Duncan Energy Partners net assets and earnings are presented as a component of noncontrolling interest in our consolidated financial statements.The borrowings of Duncan Energy Partners are presented as part of our consolidated debt.However, neither Enterprise Products Partners L.P. nor EPO have any obligation for the payment of interest or repayment of borrowings incurred by Duncan Energy Partners. TEPPCO Merger and Basis of Presentation 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 TEPPCOs 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.On October 27, 2009, our TEP

Summary of Significant Accounti

Summary of Significant Accounting Policies
	12 Months Ended Dec. 31, 2009 USD / shares
Notes To Financial Statements [Abstract]
Summary of Significant Accounting Policies	Note 2.Summary of Significant Accounting Policies Allowance for Doubtful Accounts Our allowance for doubtful accounts is determined based on specific identification and estimates of future uncollectible accounts.Our procedure for determining the allowance for doubtful accounts is based on: (i) historical experience with customers, (ii) the perceived financial stability of customers based on our research and (iii) the levels of credit we grant to customers.In addition, we may increase the allowance account in response to the specific identification of customers involved in bankruptcy proceedings and similar financial difficulties.On a routine basis, we review estimates associated with the allowance for doubtful accounts to ensure that we have recorded sufficient reserves to cover potential losses.Our allowance also includes estimates for uncollectible natural gas imbalances based on specific identification of accounts. The following table presents the activity of our allowance for doubtful accounts for the periods indicated: For Year Ended December 31, 2009 2008 2007 Balance at beginning of period $ 17.7 $ 21.8 $ 23.5 Charges to expense 0.1 3.5 2.6 Payments (1.0 ) (7.6 ) (4.3 ) Balance at end of period $ 16.8 $ 17.7 $ 21.8 See Credit Risk Due to Industry Concentrations in Note 19 for additional information. Cash and Cash Equivalents Cash and cash equivalents represent unrestricted cash on hand and highly liquid investments with original maturities of less than three months from the date of purchase. Consolidation Policy Our 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 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 are the primary beneficiary.If such criteria are met, we consolidate the financial statements of such businesses with those of our own.Third-party or affiliate ownership interests in our controlled subsidiaries are presented as noncontrolling interests.See Note 13 for information regarding noncontrolling interest. If the entity is organized as a limited partnership or limited liability company and maintains separate ownership accounts, we account for our investment using the equity method if our ownership interest is between 3% and 50% and we exercise significant influence over the entitys operating and financial policies.For all other types of investments, we apply the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the entitys operating and financial policies.In consolidation, we eliminate our proportionate share of profits and losses from transactions with equity method unconsolidated affiliates to t

Recent Accounting Developments

Recent Accounting Developments
	12 Months Ended Dec. 31, 2009 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 guidance that will or may affect our future financial statements: Fair Value Measurements. In January 2010, the Financial Accounting Standards Board (FASB) issued new guidance to improve disclosures about fair value measurements. This new guidance requires the following: Effective with the first quarter of 2010, additional disclosures will be required regarding the reporting of transfers of fair value information between the three levels of the fair value hierarchy (i.e., Levels 1, 2 and 3). Effective with the first quarter of 2011, companies will need to present purchases, sales, issuances and settlements whose fair values are based on unobservable inputs on a gross basis. Other than requiring enhanced fair value disclosures, we do not expect our adoption of this guidance will have a material impact on our consolidated financial statements. Consolidation of Variable Interest Entities. In June 2009, the FASB amended its consolidation guidance regarding variable interest entities. In general, this new guidance places more emphasis on a qualitative analysis, rather than a purely quantitative approach, in determining which company should consolidate a variable interest entity.Our adoption of this guidance on January 1, 2010 did not have any impact on our consolidated financial statements.

Revenue Recognition

Revenue Recognition
	12 Months Ended Dec. 31, 2009 USD / shares
Notes To Financial Statements [Abstract]
Revenue Recognition	Note 4.Revenue Recognition The following information provides a general description of our underlying revenue recognition policies by business segment: NGL Pipelines Services Our NGL Pipelines Services include our (i) natural gas processing business and related NGL marketing activities; (ii) NGL pipelines aggregating approximately 16,300 miles; (iii) NGL and related product storage and terminal 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 percent-of-liquids contracts, percent-of-proceeds contracts, fee-based contracts, hybrid-contracts (i.e. a combination of percent-of-liquids and fee-based contract terms), keepwhole contracts and margin-band contracts.Under keepwhole and margin-band 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 and delivery of NGLs obtained through our processing activities and spot and contract purchases from third parties.Revenues from these sales contracts are recognized when the NGLs are delivered to customers.In general, sales prices referenced in these contracts are market-based and may 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 reserving storage capacity for certain customers in our underground storage wells.Under these agreements, revenue is recognized ratably over the specified reservation period.Excess storage fees are collected when customers exceed their reservation amounts and are recognized in the pe

Equity-based Awards

Equity-based Awards
	12 Months Ended Dec. 31, 2009 USD / shares
Notes To Financial Statements [Abstract]
Equity-based Awards	Note 5.Equity-based Awards The following table summarizes the expense we recognized in connection with equity-based awards for the periods presented: For Year Ended December 31, 2009 2008 2007 Restricted unit awards (1) $ 12.9 $ 10.9 $ 8.7 Unit option awards (1) 1.8 0.7 4.5 Unit appreciation rights (2) 0.1 -- 0.1 Phantom units (2) 0.2 (0.5 ) 2.3 Profits interests awards (1) 8.5 6.3 4.3 Total compensation expense $ 23.5 $ 17.4 $ 19.9 (1)Accounted for as equity-classified awards. (2)Accounted for as liability-classified awards. The fair value of an equity-classified award (e.g., 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 (e.g., 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. At December 31, 2009, our active long-term incentive plans are the Enterprise Products 1998 Long-Term Incentive Plan (1998 Plan), the TEPPCO 1999 Phantom Unit Retention Plan (1999 Plan), the Enterprise Products 2006 TPP Long-Term Incentive Plan (2006 Plan) and the Amended and Restated 2008 Enterprise Products Long-Term Incentive Plan (2008 Plan).Two plans were dissolved during 2009:TEPPCO 2000 Long-Term Incentive Plan (2000 Plan) and TEPPCO 2005 Phantom Unit Plan (2005 Plan). The 1998 Plan provides for awards of our common units and other rights to our non-employee directors and to employees of EPCO and its affiliates providing services to us.Awards under the 1998 Plan may be granted in the form of unit options, restricted units, phantom units, UARs and distribution equivalent rights (DERs).Up to 7,000,000 of our common units may be issued as awards under the 1998 Plan.After giving effect to awards granted under the plan through December 31, 2009, a total of 652,543 additional common units could be issued. The 1999 Plan provided key employees of EPCO who work on our behalf with phantom unit awards.This plan terminated in January 2010. The 2006 Plan currently provides for awards of our common units (formerly of TEPPCO units) and other rights to our non-employee directors and to employees of EPCO and its affiliates providing services to us.Awards under the 2006 Plan may be granted in the form of unit options, restricted units, phantom units, UARs and DERs.Effective upon the consummation of the TEPPCO Merger (see Note 1), we assumed the vested and unvested options, restricted units and UAR awards outstanding on October 26, 2009 under the 2006 Plan and converted them into our options, restricted units and UAR awards based on the TEPPCO Merger exchange ratio.The vesting terms of each award and other provisions of the plan remain unchanged. The 2008 Plan provides for awards of our common units and other rights to our non-employee directors and to consultants and employees o

Derivative Instruments, Hedging

Derivative Instruments, Hedging Activities and Fair Value Measurements
	12 Months Ended Dec. 31, 2009 USD / shares
Notes To Financial Statements [Abstract]
Derivative Instruments, Hedging Activities and Fair Value Measurements	Note 6.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 instruments whose fair value is determined by changes in a specified benchmark such as interest rates, commodity prices or currency values.Fair value is generally defined as the amount at which a derivative instrument could be exchanged in a current transaction between willing parties, not in a forced sale.Typical derivative instruments include futures, forward contracts, swaps, options 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 are 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, gains and losses for 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 or loss (OCI) and is reclassified into earnings when the forecasted transaction affects earnings. Foreign currency exposure - A foreign currency hedge can be treated as either a fair value hedge or a cash flow hedge depending on the risk being hedged. An effective hedge relationship 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 relationship 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 relationship 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. A contract designated as a cash flow hedge of an anticipated transaction that is probable of not occurring is immediately recognized in earnings. Interest Rate Derivative Instruments We utilize interest rate swaps,

Inventories

Inventories
	12 Months Ended Dec. 31, 2009 USD / shares
Notes To Financial Statements [Abstract]
Inventories	Note 7.Inventories Our inventory amounts were as follows at the dates indicated: December 31, 2009 2008 Working inventory (1) $ 466.4 $ 188.1 Forward sales inventory (2) 245.5 216.9 Total inventory $ 711.9 $ 405.0 (1) Working inventory is comprised of inventories of natural gas, NGLs, crude oil, refined products, lubrication oils 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, NGL, refined product and crude oil volumes dedicated to the fulfillment of forward sales contracts.In general, the increase in volumes dedicated to forward physical sales contracts improves the overall utilization and profitability of our fee-based assets.The cash invested in forward sales NGL inventories is expected to be recovered within the next twelve months as physical delivery from inventory occurs. 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-based prices during the month in which they are acquired. Due to fluctuating commodity prices, we recognize LCM adjustments when the carrying value of our inventories exceeds 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 are recorded as an expense related to our NGL marketing activities within our NGL Pipelines Services business segment; Write-downs of natural gas inventories are recorded as an expense related to our natural gas pipeline operations within our Onshore Natural Gas Pipelines Services business segment; Write-downs of crude oil inventories are recorded as an expense related to our crude oil operations within our Onshore Crude Oil Pipelines Services business segment; and Write-downs of petrochemical, refined products and related inventories are recorded as an expense related to our petrochemical and refined products marketing activities or octane additive production business, as applicable, within our Petrochemical Refined Products Services business segment. To the extent our commodity hedging strategies address inventory-related risks and are successful, these inventory valuation adjustments are mitigated or offset.See Note 6 for a description of our commodity hedging activities. The following table summarizes our cost of sales and LCM adjustment amounts for the periods indicated: For Year Ended December 31, 2009 2008 2007 Cost of sales (1) $ 20,921.8 $ 31,204.8 $ 23,494.0 LCM adjustments 6.3 63.0 14.1 (1) Cost of sales is included in operating costs and expenses, as presented on our Statements of Consolidated Operations.The fluctuation in this amount year-to-year is primarily due to changes in energy commodity prices as

Property, Plant and Equipment

Property, Plant and Equipment
	12 Months Ended Dec. 31, 2009 USD / shares
Notes To Financial Statements [Abstract]
Property, Plant and Equipment	Note 8.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 2009 2008 Plants and pipelines (1) 3-45 (5) $ 17,681.9 $ 15,444.7 Underground and other storage facilities (2) 5-40 (6) 1,280.5 1,203.9 Platforms and facilities (3) 20-31 637.6 634.8 Transportation equipment (4) 3-10 60.1 50.9 Marine vessels 20-30 559.4 453.0 Land 82.9 76.5 Construction in progress 1,207.2 2,015.4 Total 21,509.6 19,879.2 Less accumulated depreciation 3,820.4 3,146.4 Property, plant and equipment, net $ 17,689.2 $ 16,732.8 (1) Plants and pipelines include processing plants; NGL, petrochemical, crude oil and natural gas pipelines; terminal loading and unloading facilities; office furniture and equipment; buildings; laboratory and shop equipment and related assets. (2) Underground and other storage facilities include underground product storage caverns; above ground storage tanks; water wells and related assets. (3) Platforms and facilities include offshore platforms and related facilities and other associated assets. (4) Transportation equipment includes vehicles and similar assets used in our operations. (5) In general, the estimated useful lives of major components of this category are as follows:processing plants, 20-35 years; pipelines and related equipment, 5-45 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, 5-35 years; storage tanks, 10-40 years; and water wells, 5-35 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 year ended December 31, 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 18 for information regarding expense amounts recognized during 2009 in connection with a settlement agreement involving TOPS. In addition, we recorded $21.0 million, $4.3 million and $4.1 million of non-cash asset impairment charges with

Investments in Unconsolidated A

Investments in Unconsolidated Affiliates
	12 Months Ended Dec. 31, 2009 USD / shares
Notes To Financial Statements [Abstract]
Investments in Unconsolidated Affiliates	Note 9.Investments in Unconsolidated Affiliates We own interests in a number of related businesses that are accounted for using the equity method of accounting.We group our investments in unconsolidated affiliates according to the business segment to which they relate (see Note 14 for a general discussion of our business segments).The following table shows our investments in unconsolidated affiliates by business segment at the dates indicated: Ownership Percentage at December 31, December 31, 2009 2009 2008 NGL Pipelines Services: Venice Energy Service Company, L.L.C. 13.1% $ 32.6 $ 37.7 K/D/S Promix, L.L.C. 50% 48.9 46.4 Baton Rouge Fractionators LLC 32.2% 22.2 24.2 Skelly-Belvieu Pipeline Company, L.L.C. 49% 37.9 36.0 Onshore Natural Gas Pipelines Services: Evangeline (1) 49.5% 5.6 4.5 White River Hub, LLC 50% 26.4 21.4 Onshore Crude Oil Pipelines Services: Seaway Crude Pipeline Company 50% 178.5 186.2 Offshore Pipelines Services: Poseidon Oil Pipeline, L.L.C. 36% 61.7 60.2 Cameron Highway Oil Pipeline Company (Cameron Highway) 50% 239.6 250.9 Deepwater Gateway, L.L.C. 50% 101.8 104.8 Neptune Pipeline Company, L.L.C. 25.7% 53.8 52.7 Nemo Gas Gathering Company, LLC (Nemo) 33.9% -- 0.4 Petrochemical Refined Products Services: Baton Rouge Propylene Concentrator, LLC 30% 11.1 12.6 Centennial Pipeline LLC (Centennial) 50% 66.7 69.7 Other (2) Varies 3.8 4.2 Total $ 890.6 $ 911.9 (1) Evangeline refers to our ownership interests in Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp., collectively. (2) Other unconsolidated affiliates include a 50% interest in a propylene pipeline extending from Mont Belvieu, Texas to La Porte, Texas and a 25% interest in a company that provides logistics communications solutions between petroleum pipelines and their customers. 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.The following table summarizes the unamortized excess cost amounts by business segment at the dates indicated: December 31, 2009 2008 NGL Pipelines Services $ 27.1 $ 28.0 Onshore Crude Oil Pipelines Services 20.4 21.1 Offshore Pipelines Service 17.3 18.6 Petrochemical Refined Products Services 4.0 7.9 Total $ 68.8 $ 75.6 Such excess cost amounts were attributable to the underlying tangible and amortizable intangible assets of certain unconsolidated affiliates.We amortize such excess cost amounts as a reduction in equity

Business Combinations

Business Combinations
	12 Months Ended Dec. 31, 2009 USD / shares
Notes To Financial Statements [Abstract]
Business Combinations	Note 10. Business Combinations The following table presents our cash used for business combinations by segment for the periods indicated: For Year Ended December 31, 2009 2008 2007 NGL Pipelines Services $ 33.3 $ 77.0 $ 0.4 Onshore Natural Gas Pipelines Services 0.8 125.2 35.5 Petrochemical Refined Products Services 73.2 351.3 -- Total cash used for business combinations $ 107.3 $ 553.5 $ 35.9 The following table depicts the fair value allocation of assets acquired and liabilities assumed for our business combinations for the periods indicated: For Year Ended December 31, 2009 2008 2007 Assets acquired in business combination: Current assets $ 1.4 $ 6.6 $ -- Property, plant and equipment, net 115.9 549.6 44.5 Intangible assets 0.3 92.5 (8.5 ) Other assets (0.3 ) 0.4 -- Total assets acquired 117.3 649.1 36.0 Liabilities assumed in business combination: Current liabilities 0.3 (3.2 ) -- Long-term debt -- (2.6 ) -- Other long-term liabilities -- (109.5 ) (1.2 ) Total liabilities assumed 0.3 (115.3 ) (1.2 ) Total assets acquired plus liabilities assumed 117.6 533.8 34.8 Noncontrolling interest acquired 10.3 -- -- Fair value of 4,854,899 TEPPCO units -- 186.6 -- Total cash used for business combinations 107.3 553.5 35.9 Goodwill (1) $ -- $ 206.3 $ 1.1 (1)See Note 11 for additional information regarding goodwill. 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 2009, 2008 and 2007 due to the immaterial nature of our business combination transactions for those respective periods. 2009 Transactions Our business combinations during 2009 primarily consisted of: the acquisition of certain rail and truck terminal facilities located in Mont Belvieu, Texas from Martin Midstream Partners LP for $23.7 million in cash; the acquisition of tow boats and tank barges primarily based in Miami, Florida, with additional assets located in Mobile, Alabama and Houston, Texas from TransMontaigne Product Services Inc. for $50.0 million in cash; and the acquisition of a majority interest in the Rio Grande Pipeline Company (Rio Grande) purchased from HEP Navajo Southern L.P. for $32.8 million in cash.Rio Grande owns an NGL pipeline system in Texas. 2008 Transactions 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 G

Intangible Assets and Goodwill

Intangible Assets and Goodwill
	12 Months Ended Dec. 31, 2009 USD / shares
Notes To Financial Statements [Abstract]
Intangible Assets and Goodwill	Note 11.Intangible Assets and Goodwill Identifiable Intangible Assets The following table summarizes our intangible assets by segment at the dates indicated: December 31, 2009 December 31, 2008 Gross Accum. Carrying Gross Accum. Carrying Value Amort. Value Value Amort. Value NGL Pipelines Services: (1) Customer relationship intangibles $ 237.4 $ (86.5 ) $ 150.9 $ 237.4 $ (68.7 ) $ 168.7 Contract-based intangibles 321.4 (156.7 ) 164.7 320.3 (137.6 ) 182.7 Segment total 558.8 (243.2 ) 315.6 557.7 (206.3 ) 351.4 Onshore Natural Gas Pipelines Services: Customer relationship intangibles (2) 372.0 (124.3 ) 247.7 372.0 (103.2 ) 268.8 Contract-based intangibles 565.3 (285.8 ) 279.5 565.3 (249.7 ) 315.6 Segment total 937.3 (410.1 ) 527.2 937.3 (352.9 ) 584.4 Onshore Crude Oil Pipelines Services: Contract-based intangibles 10.0 (3.5 ) 6.5 10.0 (3.1 ) 6.9 Segment total 10.0 (3.5 ) 6.5 10.0 (3.1 ) 6.9 Offshore Pipelines Services: Customer relationship intangibles 205.8 (105.3 ) 100.5 205.8 (90.7 ) 115.1 Contract-based intangibles 1.2 (0.2 ) 1.0 1.2 (0.1 ) 1.1 Segment total 207.0 (105.5 ) 101.5 207.0 (90.8 ) 116.2 Petrochemical Refined Products Services: (3) Customer relationship intangibles 104.6 (18.8 ) 85.8 104.9 (13.8 ) 91.1 Contract-based intangibles 42.1 (13.9 ) 28.2 41.1 (8.2 ) 32.9 Segment total 146.7 (32.7 ) 114.0 146.0 (22.0 ) 124.0 Total all segments $ 1,859.8 $ (795.0 ) $ 1,064.8 $ 1,858.0 $ (675.1 ) $ 1,182.9 (1) In 2008, we acquired $6.0 million of certain permits related to our Mont Belvieu complex and had $12.7 million of purchase price allocation adjustmentsrelated to San Felipe customer relationships from a 2007 business combination. (2) In 2008, we acquired $9.8 million of customer relationships due to the Great Divide business combination. (3) Amount includes a non-cash impairment charge of $0.6 million in 2009 related to certain intangible assets, see Note 6 for additional information. The following table presents the amortization expense of our intangible assets by segment for the periods indicated: For Year Ended December 31, 2009 2008 2007 NGL Pipelines Services $ 36.9 $ 40.7 $ 38.2 Onshore Natural Gas Pipelines Services 57.2 61.7 64.4 Onshore Crude Oil Pipelines Services 0.4 0.5 0.5 Offshore Pipel

Debt Obligations

Debt Obligations
	12 Months Ended Dec. 31, 2009 USD / shares
Notes To Financial Statements [Abstract]
Debt Obligations	Note 12.Debt Obligations Our consolidated debt obligations consisted of the following at the dates indicated: December 31, 2009 2008 EPO senior debt obligations: Multi-Year Revolving Credit Facility, variable-rate, due November 2012 $ 195.5 $ 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 -- 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 -- 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, 4.95% 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 -- Senior Notes Q, 5.25% fixed-rate, due January 2020 500.0 -- Senior Notes R, 6.125% fixed-rate, due October 2039 600.0 -- Senior Notes S, 7.625% fixed-rate, due February 2012 (2) 490.5 -- Senior Notes T, 6.125% fixed-rate, due February 2013 (2) 182.5 -- Senior Notes U, 5.90% fixed-rate, due April 2013 (2) 237.6 -- Senior Notes V, 6.65% fixed-rate, due April 2018 (2) 349.7 -- Senior Notes W, 7.55% fixed-rate, due April 2038 (2) 399.6 -- TEPPCO senior debt obligations: TEPPCO Revolving Credit Facility, variable-rate, due December 2012 -- 516.7 TEPPCO Senior Notes (2) 40.1 1,700.0 Duncan Energy Partners debt obligations: DEP Revolving Credit Facility, variable-rate, due February 2011 175.0 202.0 DEP Term Loan, variable-rate, due December 2011 282.3 282.3 Total principal amount of senior debt obligations 9,764.3 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 EPO Junior Subordinated Notes C, fixed/variable-rate, due June 2067 (2) 285.8 -- TEPPCO Junior Subordinated Notes, fixed/variable-rate, due June 2067(2) 14.2 300.0 Total principal amount of senior and junior debt obligations 11,297.0 11,562.8 Other, non-principal amounts: Change in fair value of debt-related deriva

Equity and Distributions

Equity and Distributions
	12 Months Ended Dec. 31, 2009 USD / shares
Notes To Financial Statements [Abstract]
Equity and Distributions	Note 13.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 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 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, 2009 and 2008.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. Registration Statements and Equity Offerings 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). We have filed registration statements with the SEC authorizing the issuance of up to an aggregate 40,000,000 common units in connection with our distribution reinvestment plan (DRIP).The DRIP provides unitholders of record and beneficial owners of our common units a voluntary means by which they can increase the number of common units they own by reinvesting the quarterly cash distributions they would otherwise receive into the purchase of additional co

Business Segments

Business Segments
	12 Months Ended Dec. 31, 2009 USD / shares
Notes To Financial Statements [Abstract]
Business Segments	Note 14.Business Segments 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. 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 measure of total segment gross operating margin should not be considered an alternative to GAAP operating income. We define total segment gross operating margin as operating income before: (i) depreciation, amortization and accretion expense; (ii) non-cash consolidated asset impairment charges; (iii) operating lease expenses for which we do not have the payment obligation; (iv) gains and losses from asset sales and related transactions and (v) general and administrative costs.Gross operating margin by segment is calculated by subtracting segment operating costs and expenses (net of the adjustments noted above) from segment revenues, with both segment totals before the elimination of intercompany transactions.In accordance with GAAP, intercompany accounts and transactions are eliminated in consolidation.Gross operating margin is exclusive of other income and expense transactions, provision for income taxes, the cumulative effect of changes in accounting principles and extraordinary charges.Gross operating margin is presented on a 100% basis before the allocation of earnings to noncontrolling interests. Segment revenues include intersegment and intrasegment transactions, which are generally based on transactions made at market-based rates.Our consolidated revenues reflect the elimination of intercompany (both intersegment and intrasegment) transactions. We include equity in income of unconsolidated affiliates in our measurement of segment gross operating margin and operating income.Our equity investments with industry partners are a vital component of our business strategy.They are a means by which we conduct our operations to align our interests with those of our customers and/or suppliers.This method of operation enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed versus what we could accomplish on a standalone basis.Many of these businesses perform supporting or complementary roles to our other business operations. Our integrated midstream energy asset system (including the midstream ener

Related Party Transactions

Related Party Transactions
	12 Months Ended Dec. 31, 2009 USD / shares
Notes To Financial Statements [Abstract]
Related Party Transactions	Note 15.Related Party Transactions The following table summarizes our related party transactions for the periods indicated: For Year Ended December 31, 2009 2008 2007 Revenues related parties: EPCO and affiliates $ -- $ -- $ 0.2 Energy Transfer Equity and subsidiaries 423.1 618.5 294.5 Unconsolidated affiliates 175.9 396.9 290.5 Total revenue related parties $ 599.0 $ 1,015.4 $ 585.2 Costs and expenses related parties: EPCO and affiliates $ 590.3 $ 554.2 $ 470.3 Energy Transfer Equity and subsidiaries 443.8 192.2 35.2 Cenac and affiliates 40.9 48.3 -- Unconsolidated affiliates 38.2 56.1 41.0 Total costs and expenses related parties $ 1,113.2 $ 850.8 $ 546.5 Other expense related parties: EPCO and affiliates $ 4.1 $ 0.3 $ 0.2 The following table summarizes our related party receivable and payable amounts at the dates indicated: December 31, 2009 2008 Accounts receivable - related parties: EPCO and affiliates $ -- $ 0.2 Energy Transfer Equity and subsidiaries 28.2 35.0 Other 10.2 0.1 Total accounts receivable related parties $ 38.4 $ 35.3 Accounts payable - related parties: EPCO and affiliates $ 26.8 $ 14.1 Energy Transfer Equity and subsidiaries 33.4 0.1 Other 9.6 3.2 Total accounts payable related parties $ 69.8 $ 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. 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 privately held affiliates; EPGP, our sole general partner; Enterprise GP Holdings, which owns and controls our general partner; and the Employee Partnerships (see Note 5). EPCO is a privately held company controlled by Dan L. Duncan, who is also a Director and Chairman of EPGP, our general partner.At December 31, 2009, EPCO and its affiliates beneficially owned interests in the following entities: Percentage of Number of Units Outstanding Units Enterprise Products Partners (1) (2) 191,363,613 31.3% Enterprise GP Holdings (3) 108,503,133 78.0% (1) Includes 4,520,431 Class B units and 21,167,783 common units owned by Enterprise GP Holdings. (2) Enterprise GP Holdings owns 100% of our general partner, EPGP. (3) An affiliate of EPCO also owns 100% of the general partner of Enterprise GP Holdings, EPE Holdings. The principal business activity of EPGP is to act as our managing partner.The executive officers and certain of the directors of EPGP an

Provision for Income Taxes

Provision for Income Taxes
	12 Months Ended Dec. 31, 2009 USD / shares
Notes To Financial Statements [Abstract]
Provision for Income Taxes	Note 16.Provision for Income Taxes Our provision for income taxes relates primarily to federal and state income taxes of Seminole and Dixie, our two largest corporations subject to such income taxes.In addition, with the amendment of the TexasMargin Tax, we have become a taxable entity in the state of Texas.Our federal and state income tax provision is summarized below: For Year Ended December 31, 2009 2008 2007 Current: Federal $ 7.9 $ 4.9 $ 4.7 State 11.9 23.9 5.1 Foreign 1.0 0.4 0.1 Total current 20.8 29.2 9.9 Deferred: Federal 4.8 0.8 2.7 State (0.3 ) 1.0 3.1 Total deferred 4.5 1.8 5.8 Total provision for income taxes $ 25.3 $ 31.0 $ 15.7 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 Year Ended December 31, 2009 2008 2007 Pre Tax Net Book Income (NBI) $ 1,180.4 $ 1,219.9 $ 853.7 Texas Margin Tax $ 10.1 $ 23.9 $ 7.7 State income taxes (net of federal benefit) 1.3 0.5 0.3 Federal income taxes computed by applying the federal statutory rate to NBI of corporate entities 8.3 6.3 5.3 Valuation allowance (1.7 ) (1.4 ) 2.3 Expiration of tax net operating loss 1.7 -- -- Other permanent differences 5.6 1.7 0.1 Provision for income taxes $ 25.3 $ 31.0 $ 15.7 Effective income tax rate 2.1 % 2.5 % 1.8 % Significant components of deferred tax assets and deferred tax liabilities as of December 31, 2009 and 2008 are as follows: At December 31, 2009 2008 Deferred tax assets: Net operating loss carryovers (1) $ 24.6 $ 26.3 Property, plant and equipment -- 0.8 Employee benefit plans 2.8 2.6 Deferred revenue 1.1 1.0 Reserve for legal fees and damages -- 0.3 Equity investment in partnerships 1.0 0.6 AROs 0.1 0.1 Accruals 1.3 0.9 Total deferred tax assets 30.9 32.6 Valuation allowance (2) 2.2 3.9 Net deferred tax assets 28.7 28.7 Deferred tax liabilities: Property, plant and equipment 97.4 92.9 Other -- 0.1 Total deferred tax liabilities 97.4 93.0 Total net deferred tax liabilities $ (68.7 ) $ (64.3 ) Current portion of total net deferred tax assets $ 1.9 $ 1.4 Long-term portion of total net deferred tax liabilities $ (70.6 ) $ (65.7 ) (1) These losses expire in various years between 2010 and 2028 and are subject to limitations on their utilization. (2) We record a valuation allowance to reduce our deferred tax assets to the amount of future benefit that

Earnings Per Unit

Earnings Per Unit
	12 Months Ended Dec. 31, 2009 USD / shares
Notes To Financial Statements [Abstract]
Earnings Per Unit	Note 17.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 phantom units outstanding during a period; (iii) the weighted-average number of Class B units outstanding during a period and (iv) 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, Class B 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 Year Ended December 31, 2009 2008 2007 Net income attributable to Enterprise Products Partners L.P. $ 1,030.9 $ 954.0 $ 533.6 Less incentive earnings allocations to EPGP (161.3 ) (125.9 ) (107.4 ) Net income available after incentive earnings allocation 869.6 828.1 426.2 Multiplied by EPGP ownership interest 2.0 % 2.0 % 2.0 % Standard earnings allocation to EPGP $ 17.4 $ 16.6 $ 8.5 Incentive earnings allocation to EPGP $ 161.3 $ 125.9 $ 107.4 Standard earnings allocation to EPGP 17.4 16.6 8.5 Net income available to EPGP 178.7 142.5 115.9 Adjustment for master limited partnerships (1) 7.7 5.2 4.5 Net income available to EPGP for EPU purposes $ 186.4 $ 147.7 $ 120.4 (1)FASB guidance specific to master limited partnerships has been applied for purposes of computing basic and diluted earnings per unit. The following table presents our calculation of basic and diluted earnings per unit for the periods indicated: For Year Ended December 31, 2009 2008 2007 BASIC EARNINGS PER UNIT Numerator Net income attributable to Enterprise Products Partners L.P. $ 1,030.9 $ 954.0 $ 533.6 Net income available to EPGP for EPU purposes (186.4 ) (147.7 ) (120.4 ) Net income availa

Commitments and Contingencies

Commitments and Contingencies
	12 Months Ended Dec. 31, 2009 USD / shares
Notes To Financial Statements [Abstract]
Commitments and Contingencies	Note 18.Commitments and Contingencies Litigation On occasion, we or our unconsolidated affiliates are named as defendants in litigation and legal proceedings relating to our normal business activities, 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 not aware 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 financial 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)

Significant Risks and Uncertain

Significant Risks and Uncertainties
	12 Months Ended Dec. 31, 2009 USD / shares
Notes To Financial Statements [Abstract]
Significant Risks and Uncertainties	Note 19.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 gathered, transported, processed, fractionated 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.See Note 14 for information regarding our largest customer. Counterparty Risk with Respect to Derivative Instruments In those situations where we are exposed to credit risk in our derivative instrument transactions, we analyze the counterpartys financial condition prior to entering into an agreement, establish credit and/or margin limits and monitor the appropriateness of these limits on an ongoing basis.Generally, we do not require collateral nor do we anticipate nonperformance by our counterparties. Insurance-Related Risks We participate as a named insured in EPCOs insurance program, which provides us wit

Supplemental Cash Flow Informat

Supplemental Cash Flow Information
	12 Months Ended Dec. 31, 2009 USD / shares
Notes To Financial Statements [Abstract]
Supplemental Cash Flow Information	Note 20.Supplemental Cash Flow Information 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 Year Ended December 31, 2009 2008 2007 Decrease (increase) in: Accounts and notes receivable trade $ (1,069.1 ) $ 1,333.9 $ (1,175.8 ) Accounts receivable related party 7.2 3.6 (37.0 ) Inventories (317.4 ) 14.9 (20.4 ) Prepaid and other current assets 71.2 (26.9 ) 36.6 Other assets 15.0 (11.7 ) (6.7 ) Increase (decrease) in: Accounts payable trade (51.7 ) (9.1 ) 193.8 Accounts payable related party 44.3 1.2 (2.2 ) Accrued product payables 1,552.9 (1,722.0 ) 2,195.2 Accrued expenses 42.4 3.4 (809.3 ) Accrued interest 33.7 21.8 39.9 Other current liabilities (105.5 ) (27.7 ) 44.5 Other liabilities 22.9 7.5 (23.7 ) Net effect of changes in operating accounts $ 245.9 $ (411.1 ) $ 434.9 Cash payments for interest, net of $53.1, $90.7 and $86.5 capitalized in 2009, 2008 and 2007, respectively $ 651.5 $ 569.7 $ 429.5 Cash payments for federal and state income taxes $ 29.5 $ 6.8 $ 5.8 We incurred liabilities for construction in progress that had not been paid at December 31, 2009, 2008 and 2007 of $182.6 million, $107.9 million and $107.0 million, respectively.Such amounts are not included under the caption Capital expenditures on the Statements of Consolidated Cash Flows. Third parties may be obligated to reimburse us for all or a portion of expenditures on certain of our capital projects.The majority of such arrangements are associated with projects related to pipeline construction and production well tie-ins.These amounts are included under the caption Contributions in aid of construction costs on the Statements of Consolidated Cash Flows.

Quarterly Financial Information

Quarterly Financial Information (Unaudited)
	12 Months Ended Dec. 31, 2009 USD / shares
Notes To Financial Statements [Abstract]
Quarterly Financial Information (Unaudited)	Note 21.Quarterly Financial Information (Unaudited) The following table presents selected quarterly financial data for the years ended December 31, 2009 and 2008: First Second Third Fourth Quarter Quarter Quarter Quarter For the Year Ended December 31, 2009: Revenues $ 4,886.9 $ 5,434.3 $ 6,789.4 $ 8,400.3 Operating income 482.8 373.3 356.3 611.6 Net income 315.5 212.5 187.8 439.3 Net income attributable to Enterprise Products Partners L.P. 225.3 186.6 212.9 406.1 Earnings per unit: Basic $ 0.41 $ 0.32 $ 0.36 $ 0.60 Diluted $ 0.41 $ 0.32 $ 0.36 $ 0.60 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 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: Basic $ 0.51 $ 0.52 $ 0.38 $ 0.43 Diluted $ 0.51 $ 0.52 $ 0.38 $ 0.43

Condensed Consolidating Financi

Condensed Consolidating Financial Information
	12 Months Ended Dec. 31, 2009 USD / shares
Notes To Financial Statements [Abstract]
Condensed Consolidating Financial Information	Note 22.Condensed Consolidating Financial Information 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. EPO has issued publicly traded debt securities.Enterprise Products Partners L.P., as the parent company of EPO, 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.EPOs consolidated subsidiaries have no significant restrictions on their ability to pay distributions or make loans to Enterprise Products Partners L.P.See Note 12 for additional information regarding our consolidated debt obligations. 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 condensed consolidating 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. In preparing our 2009 consolidated financial statements, management reevaluated the disclosure requirements of S-X Rule 3-10, Financial Statements of Guarantors and Issuers of Guaranteed Securities Registered or Being Registered, and determined that the following Condensed Consolidating Financial Information, rather than the previously disclosed consolidated financial information of EPO, should be prospectively included herein. Enterprise Products Partners L.P. Condensed Consolidating Balance Sheet December 31, 2009 EPO and Subsidiaries Subsidiary Issuer (EPO) Other Subsidiaries (Non-guarantor) EPO and Subsidiaries Eliminations and Adjustments Consolidated EPO and Subsidiaries Parent Company (Guarantor) Eliminations and Adjustments Consolidated Total ASSETS Current assets: Cash and cash equivalents $ 14.4 $ 46.3 $ (6.2 ) $ 54.5 $ -- $ 0.2 $ 54.7 Restricted Cash 63.1 0.5 -- 63.6 -- -- 63.6 Accounts and notes receivable, net 509.6 2,674.0 (45.7 ) 3,137.9 (0.3 ) (0.2 ) 3,137.4 Inventories 595.4 120.3 (3.8 ) 711.9 -- -- 711.9 Prepaid and other current assets 185.4 100.6 (6.7 ) 279.3 -- -- 279.3 Total current assets 1,367.9 2,941.7 (62.4 ) 4,247.2 (0.3 ) -- 4,246.9 Property, plant and equipment, net 1,436.1 16,242.0 11.1 17,689.2 -- -- 17,689.2 Investments in unconsolidated affiliates 18,981.2 5,912.7 (24,003.3 ) 890.6 9,512.4 (9,512.4 ) 890.6 Intangible assets, net 170.0 910.3 (15.5 ) 1,064.8 -- -- 1,064.8 Goodw

Subsequent Event

Subsequent Event
	12 Months Ended Dec. 31, 2009 USD / shares
Notes To Financial Statements [Abstract]
Subsequent Event	Note 23.Subsequent Event Enterprise Products Partners Issues $343.1 Million of Common Units In January 2010, we issued 10,925,000 common units (including an over-allotment of 1,425,000 common units) to the public at an offering price of $32.42 per unit.We used the net cash proceeds of $343.1 million to temporarily reduce borrowings outstanding under EPOs Multi-Year Revolving Credit Facility, which may be reborrowed to fund capital expenditures and other growth projects, and for general partnership purposes.

Document Information

Document Information
	12 Months Ended Dec. 31, 2009 USD / shares
Document Information [Text Block]
Document Type	10-K
Document Period End Date	2009-12-31
Amendment Flag	false

Entity Information

Entity Information (USD $)
In Billions, except Share data	12 Months Ended Dec. 31, 2009	Feb. 01, 2010	Jun. 30, 2009
Entity [Text Block]
Entity Registrant Name	ENTERPRISE PRODUCTS PARTNERS L P
Entity Central Index Key	0001061219
Current Fiscal Year End Date	--12-31
Entity Well Known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			7.51
Entity Common Stock, Shares Outstanding		618,813,932