View Filing Data

537.7

484.8

14.5

0.0

Distributions received from unconsolidated affiliates

(21.2)

(27.3)

50.5

84.8

Deferred income tax expense (benefit)

(3.8)

(23.6)

(27.7)

0.0

^[1]

(68.8)

0.0

(64.9)

2.3

Changes in fair market value of derivative instruments

(21.6)

(10.7)

Net effect of changes in operating accounts (see Note 15)

(280.3)

361.4

Other operating activities

1.2

(0.2)

Net cash flows provided by operating activities

1,338.3

1,754.5

Investing activities:

Capital expenditures

(1,813.1)

(1,716.2)

Contributions in aid of construction costs

10.0

6.4

Decrease (increase) in restricted cash

38.5

(17.5)

Proceeds from asset sales (see Note 15)

(125.5)

(11.8)

1,129.0

250.5

Proceeds from property damage insurance recoveries (see Note 16)

27.7

0.0

Other investing activities

(16.4)

(3.6)

Cash used in investing activities

(749.8)

(1,492.2)

Financing activities:

Borrowings under debt agreements

2,414.6

3,791.1

Repayments of debt

(1,891.0)

(3,033.5)

Debt issuance costs

(7.5)

(12.8)

Monetization of interest rate derivative instruments (see Note 4)

(77.6)

(5.7)

Cash distributions paid to limited partners (see Note 10)

(1,068.6)

(966.5)

Cash distributions paid to noncontrolling interests (see Note 10)

(8.1)

(34.8)

Cash contributions from noncontrolling interests (see Note 10)

5.9

2.6

Other financing activities

57.7

45.1

(19.2)

(4.2)

Cash used in financing activities

(593.8)

(218.7)

Net change in cash and cash equivalents

(5.3)

43.6

Cash and cash equivalents, January 1

19.8

65.5

Cash and cash equivalents, June 30

$ 14.5

$ 109.1

[1]	See Note 7 for information regarding our previously held investment in Energy Transfer Equity.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY - USD ($) $ in Millions	Limited Partners [Member]	Accumulated Other Comprehensive Income Loss [Member]	Noncontrolling Interests [Member]	Total
Balance at Dec. 31, 2010	$ 11,406.7	$ (32.5)	$ 526.6	$ 11,900.8
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	854.4	0.0	28.6	883.0
Cash distributions paid to limited partners	(966.5)	0.0	0.0	(966.5)
Cash distributions paid to noncontrolling interests	0.0	0.0	(34.8)	(34.8)
Cash contributions from noncontrolling interests	0.0	0.0	2.6	2.6
Net cash proceeds from issuance of common units	45.1	0.0	0.0	45.1
Amortization of fair value of equity-based awards	25.2	0.0	0.1	25.3
Cash flow hedges	0.0	(72.4)	0.0	(72.4)
Other	(4.5)	(1.3)	(2.0)	(7.8)
Balance at Jun. 30, 2011	11,360.4	(106.2)	521.1	11,775.3
Balance at Dec. 31, 2011	12,464.8	(351.4)	105.9	12,219.3
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	1,217.6	0.0	5.1	1,222.7
Cash distributions paid to limited partners	(1,068.6)	0.0	0.0	(1,068.6)
Cash distributions paid to noncontrolling interests	0.0	0.0	(8.1)	(8.1)
Cash contributions from noncontrolling interests	0.0	0.0	5.9	5.9
Net cash proceeds from issuance of common units	57.7	0.0	0.0	57.7
Amortization of fair value of equity-based awards	31.8	0.0	0.0	31.8
Cash flow hedges	0.0	32.9	0.0	32.9
Other	(18.3)	(0.2)	1.0	(17.5)
Balance at Jun. 30, 2012	$ 12,685.0	$ (318.7)	$ 109.8	$ 12,476.1

Partnership Operations, Organization and Basis of Presentation	6 Months Ended
	Jun. 30, 2012
Partnership Operations, Organization and Basis of Presentation [Abstract]
Partnership Operations, Organization and Basis of Presentation	Note 1. Partnership Operations, Organization and Basis of Presentation General We are 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." We were formed in April 1998 to own and operate certain natural gas liquids ("NGLs") related businesses of EPCO and are now a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, refined products and petrochemicals. Our midstream energy asset network links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the United States ("U.S."), Canada and the Gulf of Mexico with domestic consumers and international markets. Our assets include approximately 50,700 miles of onshore and offshore pipelines; 190 million barrels ("MMBbls") of storage capacity for NGLs, crude oil, refined products and petrochemicals; and 14 billion cubic feet ("Bcf") of natural gas storage capacity. Our integrated midstream energy operations include: natural gas gathering, treating, processing, transportation and storage; NGL transportation, fractionation, storage, and import and export terminals; crude oil and refined products transportation, storage, and terminals; offshore production platforms; petrochemical transportation and services; and a marine transportation business that operates primarily on the U.S. inland and Intracoastal Waterway systems and in the Gulf of Mexico. We currently have five active reportable business segments: (i) NGL Pipelines & Services; (ii) Onshore Natural Gas Pipelines & Services; (iii) Onshore Crude Oil Pipelines & Services; (iv) Offshore Pipelines & Services; and (v) Petrochemical & Refined Products Services. All activities included in our sixth reportable business segment, Other Investments, ceased on January 18, 2012, which was the date we discontinued using the equity method to account for our previously held investment in Energy Transfer Equity (see "Liquidation of Investment in Energy Transfer Equity" under Note 7). We are 100% owned by our limited partners from an economic perspective. We are managed and controlled by Enterprise GP, which has a non-economic general partner interest in us. We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates and under the collective common control of the DD LLC Trustees and the EPCO Trustees. We have no employees. All of our operating functions and general and administrative support services are provided by employees of EPCO pursuant to an administrative services agreement (the "ASA") or by other service providers. See Note 12 for information regarding the ASA and other related party matters. Completion of Duncan Merger On September 7, 2011, the Duncan Merger Agreement was approved by the unitholders of Duncan Energy Partners and the merger of Duncan MergerCo and Duncan Energy Partners and related transactions were completed, with Duncan Energy Partners surviving such merger as our wholly owned subsidiary. Each issued and outstanding common unit of Duncan Energy Partners was cancelled and converted into the right to receive common units representing limited partner interests in Enterprise based on an exchange ratio of 1.01 Enterprise common units for each Duncan Energy Partners common unit. Enterprise issued 24,277,310 of its common units (net of fractional common units cashed out) as consideration in the Duncan Merger. No Enterprise common units were issued to Enterprise or its subsidiaries as merger consideration. Since we historically consolidated Duncan Energy Partners for financial reporting purposes, the Duncan Merger did not change the basis of presentation of our historical financial statements.

The entire disclosure for organization, consolidation and basis of presentation of financial statements disclosure.

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General Accounting Matters [Abstract]

General Accounting Matters

6 Months Ended

Jun. 30, 2012

General Accounting Matters

Note 2. General Accounting Matters

Our results of operations for the three and six months ended June 30, 2012 are not necessarily indicative of results expected for the full year of 2012. In our opinion, the accompanying Unaudited Condensed Consolidated Financial Statements include all adjustments consisting of normal recurring accruals necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles ("GAAP") have been condensed or omitted pursuant to the rules and regulations of the U.S. Securities and Exchange Commission ("SEC").

These Unaudited Condensed Consolidated Financial Statements and the Notes thereto should be read in conjunction with the Audited Consolidated Financial Statements and Notes thereto included in our annual report on Form 10-K for the year ended December 31, 2011 (the "2011 Form 10-K") filed with the SEC on February 29, 2012.

Contingencies

Certain conditions may exist as of the date our consolidated financial statements are issued, which may result in a loss to us but which will only be resolved when one or more future events occur or fail to occur. Management has regular quarterly litigation reviews, including updates from legal counsel, to assess the need for accounting recognition or disclosure of these contingencies, and such assessment inherently involves an exercise in judgment. In assessing loss contingencies related to legal proceedings that are pending against us or unasserted claims that may result in such proceedings, our management and legal counsel evaluate the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.

We accrue an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when it is believed to be only reasonably possible or remote.

For contingencies where an unfavorable outcome is reasonably possible and the impact would be material, we disclose the nature of the contingency and, if feasible, an estimate of the possible loss or range of loss.

Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed. See Note 14 for additional information regarding our contingencies.

Derivative Instruments

We use derivative instruments such as futures, swaps, options, forward contracts and other arrangements to manage price risks associated with inventories, firm commitments, interest rates, foreign currencies and certain anticipated future transactions. To qualify for hedge accounting, the hedged item must expose us to risk and the related derivative instrument must reduce that exposure and meet specific hedge documentation requirements related to designation dates, expectations for hedge effectiveness and the probability that hedged future transactions will occur as forecasted. We formally designate derivative instruments as hedges and document and assess their effectiveness at inception of the hedge and on a monthly or quarterly basis thereafter. Forecasted transactions are evaluated for the probability of occurrence and are periodically back-tested once the forecasted period has passed to determine whether similarly forecasted transactions are probable of occurring in the future.

For certain of our physical forward commodity derivative contracts, we apply the normal purchase/normal sale exception, whereby changes in the mark-to-market values of such contracts are not recognized in income. As a result, the revenues and expenses associated with such physical contract transactions are recognized during the period when volumes are physically delivered or received. Physical forward commodity contracts are evaluated for the probability of future delivery and are periodically back-tested once the forecasted period has passed to determine whether similar forward contracts are probable of physically delivering in the future.

See Note 4 for additional information regarding our derivative instruments and related interest rate and commodity hedging activities.

Estimates

Preparing our consolidated financial statements in conformity with GAAP requires us to make estimates that affect amounts presented in the financial statements. Our most significant estimates relate to (i) the useful lives and depreciation/amortization methods used for fixed and identifiable intangible assets; (ii) measurement of fair value and projections used in impairment testing of fixed and intangible assets (including goodwill); (iii) contingencies; and (iv) revenue and expense accruals.

Actual results could differ materially from our estimates. On an ongoing basis, we review our estimates based on currently available information. Any changes in the facts and circumstances underlying our estimates may require us to update such estimates, which could have a material impact on our consolidated financial statements.

Income Tax Benefit

For the six months ended June 30, 2012, we recognized a net income tax benefit of $25.9 million, which was primarily due to a $46.5 million net income tax benefit related to the conversion of certain of our subsidiaries to limited liability companies during the first quarter of 2012, partially offset by accruals for the Texas Margin Tax. The $46.5 million net income tax benefit is attributable to the difference between deferred income taxes accrued by the applicable subsidiaries through the date of conversion and any current income tax due in connection with the conversions.

Other Non-Operating Income

The following table presents the components of "Other, net" income for the periods presented:

	For the Three Months					For the Six Months
	Ended June 30,					Ended June 30,
	2012			2011		2012			2011
Gain on sales of Energy Transfer Equity common units (1)	$	15.5		$	--	$	68.8		$	--
Distribution income from Energy Transfer Equity		--			--		4.1			--
Other		(2.4	)		--		(1.4	)		0.2
Total	$	13.1		$	--	$	71.5		$	0.2

(1) See Note 7 for information regarding our previously held investment in Energy Transfer Equity.

Recent Accounting Developments

Accounting standard setting organizations have been very active in recent years. Recently, they issued new and revised accounting guidance on a number of topics, including disclosures related to offsetting assets and liabilities. We do not believe that adoption of this new guidance will have a material impact on our consolidated financial statements.

Equity-based Awards

6 Months Ended

Jun. 30, 2012

Equity-based Awards [Abstract]

Equity-based Awards

Note 3. Equity-based Awards

An allocated portion of the fair value of EPCO's equity-based awards is charged to us under the ASA. The following table summarizes the expense we recognized in connection with equity-based awards for the periods presented:

	For the Three Months				For the Six Months
	Ended June 30,				Ended June 30,
	2012		2011		2012		2011
Restricted common unit awards	$	15.7	$	12.1	$	30.5	$	23.5
Unit option awards		0.3		0.8		1.0		1.7
Other (1)		0.5		0.3		1.4		(0.2	)
Total compensation expense	$	16.5	$	13.2	$	32.9	$	25.0

(1) Primarily consists of unit appreciation rights ("UARs"), phantom units and similar awards.

The fair value of equity-classified awards (e.g., restricted common unit and unit option awards) is amortized to earnings over the requisite service or vesting period. Compensation expense for liability-classified awards (e.g., UARs and phantom units) is recognized over the requisite service or vesting period based on the fair value of the award remeasured at each reporting period. Liability-classified awards are settled in cash upon vesting.

At June 30, 2012, EPCO's significant long-term incentive plans applicable to us were the Enterprise Products 1998 Long-Term Incentive Plan ("1998 Plan") and the Amended and Restated 2008 Enterprise Products Long-Term Incentive Plan ("2008 Plan"). In addition, there were unvested awards outstanding under an inactive plan, the Enterprise Products 2006 TPP Long-Term Incentive Plan ("2006 Plan"). After giving effect to awards granted under the 1998 Plan and 2008 Plan through June 30, 2012, a total of 749,016 and 5,038,468 additional common units could be issued under these plans, respectively.

Restricted Common Unit Awards

Restricted common unit awards allow recipients to acquire our common units (at no cost to the recipient apart from service or other conditions) once a defined vesting period expires, subject to customary forfeiture provisions. As used in the context of EPCO's long-term incentive plans, the term "restricted common unit" represents a time-vested unit. Such awards are non-vested until the required service period expires. Restricted common unit awards issued in 2012 generally vest at a rate of 25% per year beginning one year after the grant date. Restricted common units are included in the number of common units presented on our Unaudited Condensed Consolidated Balance Sheets.

The fair value of a restricted common unit award is based on the market price per unit of the underlying security on the date of grant. Compensation expense is recognized based on the grant date fair value, net of an allowance for estimated forfeitures, over the requisite service or vesting period.

The following table presents information regarding restricted common unit awards for the period presented:

	Number of Units			Weighted- Average Grant Date Fair Value per Unit (1)
Restricted common units at December 31, 2011		3,868,216		$	34.22
Granted (2,3)		1,538,438		$	51.92
Vested (3)		(1,236,352	)	$	34.77
Forfeited		(95,575	)	$	38.43
Restricted common units at June 30, 2012		4,074,727		$	40.64

(1) Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued. (2) The aggregate grant date fair value of restricted common unit awards issued in 2012 was $79.9 million based on a grant date market price ranging from $51.92 to $52.26 per unit. An estimated annual forfeiture rate of 3.25% was applied to these awards. (3) Includes awards granted to the independent directors of the board of directors of Enterprise GP as part of their annual compensation for 2012. A total of 10,038 restricted common units were issued in February 2012 to the independent directors of Enterprise GP that immediately vested upon issuance.

Typically, each recipient is also entitled to nonforfeitable cash distributions equal to the product of the number of restricted common units outstanding for the participant and the cash distribution per unit paid to limited partners. Since these restricted common units are participating securities, such distributions are included in "Cash distributions paid to limited partners" as presented on our Unaudited Condensed Statements of Consolidated Cash Flows.

The following table presents supplemental information regarding our restricted common unit awards for the periods presented:

	For the Three Months				For the Six Months
	Ended June 30,				Ended June 30,
	2012		2011		2012		2011
Cash distributions paid to restricted common unit holders	$	3.0	$	2.7	$	5.4	$	4.8
Total intrinsic value of our restricted common unit awards vesting during period		30.1		20.5		62.7		35.2

For the EPCO group of companies, the unrecognized compensation cost associated with restricted common unit awards was an aggregate $90.3 million at June 30, 2012, of which our allocated share of the cost is currently estimated to be $85.7 million. We expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 2.0 years.

Unit Option Awards

EPCO's long-term incentive plans provide for the issuance of non-qualified incentive options. These unit option awards are denominated in our common units. When issued, the exercise price of each unit option grant may be no less than the market price of our common units on the date of grant. In general, option grants have a vesting period of four years from the date of grant and expire at the end of the calendar year following the year of vesting (e.g., an option vesting on May 29, 2011 will expire on December 31, 2012). However, unit options only become exercisable at certain times during the calendar year following the year in which they vest (typically the months of February, May, August and November).

The fair value of each unit option is estimated on the date of grant using a Black-Scholes option pricing model. Compensation expense recorded in connection with unit options is based on the grant date fair value of such awards, net of an allowance for estimated forfeitures, over the requisite service or vesting period. The following table presents unit option activity for the period presented:

	Number of Units			Weighted- Average Strike Price (dollars/unit)		Weighted- Average Remaining Contractual Term (in years)		Aggregate Intrinsic Value (1)
Unit options at December 31, 2011		3,753,420		$	28.08		2.6	$	11.1
Exercised		(712,280	)	$	30.76
Forfeited		(130,000	)	$	27.12
Unit options at June 30, 2012		2,911,140		$	27.46		2.5	$	14.4
Options exercisable at June 30, 2012		--					--		--

(1) Aggregate intrinsic value reflects fully vested unit options at the date indicated.

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

The following table presents supplemental information regarding our unit options during the periods presented:

	For the Three Months				For the Six Months
	Ended June 30,				Ended June 30,
	2012		2011		2012		2011
Total intrinsic value of unit option awards exercised during period	$	--	$	--	$	14.0	$	--
Cash received from EPCO in connection with the exercise of unit option awards		--		--		10.2		--
Unit option-related reimbursements to EPCO		--		--		14.0		--

For the EPCO group of companies, the unrecognized compensation cost associated with unit option awards was an aggregate $2.2 million at June 30, 2012, of which our allocated share of the cost is currently estimated to be $2.0 million. We expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 1.1 years.

Unit Appreciation Rights

At December 31, 2011, there were 107,328 UARs outstanding that had been granted under the 2006 Plan. The accrued liability for UARs at December 31, 2011 was $0.5 million. All of these awards vested in May 2012. The accrued liability for UARs in May 2012 (i.e., immediately before vesting) was $1.4 million. While these awards were outstanding, they were accounted for as liability awards.

The entire disclosure for compensation-related costs for equity-based compensation, which may include disclosure of policies, compensation plan details, allocation of equity compensation, incentive distributions, equity-based arrangements to obtain goods and services, deferred compensation arrangements, employee stock ownership plan details and employee stock purchase plan details.

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-Name Staff Accounting Bulletin (SAB)
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-Number 123R
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Derivative Instruments, Hedging Activities and Fair Value Measurements [Abstract]

Derivative Instruments, Hedging Activities and Fair Value Measurements

6 Months Ended

Jun. 30, 2012

Derivative Instruments, Hedging Activities and Fair Value Measurements

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

In the normal course of our business operations, we are exposed to certain risks, including changes in interest rates and commodity prices. In order to manage risks associated with certain anticipated future transactions, we use derivative instruments. 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 our balance sheet unless such instruments meet certain normal purchase/normal sale criteria. While all derivatives are required to be reported at fair value on the balance sheet, changes in fair value of derivative instruments are reported in different ways, depending on the nature and effectiveness of the hedging activities to which they relate. 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 the changes in fair value of a hedged item at inception and throughout the life of the hedging relationship. 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 not probable of occurring is immediately recognized in earnings.

Certain of our derivative instruments do not qualify for hedge accounting treatment; therefore, they are accounted for using mark-to-market accounting.

Interest Rate Hedging Activities

We may utilize interest rate swaps, forward starting swaps and similar derivative instruments to manage our exposure to changes in interest rates charged on borrowings under certain consolidated debt agreements. The following table summarizes our portfolio of interest rate swaps at June 30, 2012:

Hedged Transaction	Number and Type of Derivatives Outstanding	Notional Amount	Period of Hedge	Rate Swap	Accounting Treatment
Senior Notes AA	10 fixed-to-floating swaps	$750.0	1/2011 to 2/2016	3.2% to 1.5%	Fair value hedge
Undesignated swaps	6 floating-to-fixed swaps	$600.0	5/2010 to 7/2014	0.5% to 2.0%	Mark-to-market

Interest expense for the three months ended June 30, 2012 and 2011 reflects a benefit of $2.2 million and an expense of $2.2 million, respectively, attributable to interest rate swaps. For the six months ended June 30, 2012 and 2011, such swaps resulted in a benefit in interest expense of $5.0 million and $7.5 million, respectively.

In February 2012, we settled 11 fixed-to-floating interest rate swaps having an aggregate notional amount of $800.0 million, resulting in gains totaling $37.7 million. As fair value hedges, the unamortized portion of these gains are a component of long-term debt (see Note 9) and are being amortized to earnings (as a decrease in interest expense) using the effective interest method over the forecasted hedged period of approximately three years.

The following table summarizes our portfolio of forward starting swaps outstanding at June 30, 2012. Forward starting swaps hedge the expected underlying benchmark interest rates related to future issuances of debt.

Hedged Transaction	Number and Type of Derivatives Outstanding	Notional Amount	Expected Termination Date	Average Rate Locked	Accounting Treatment
Future debt offering	7 forward starting swaps	$350.0	8/2012	3.7%	Cash flow hedge
Future debt offering	16 forward starting swaps	$1,000.0	3/2013	3.7%	Cash flow hedge

In connection with the issuance of Senior Notes EE in February 2012 (see Note 9), we settled ten forward starting swaps having an aggregate notional amount of $500.0 million, resulting in cash losses totaling $115.3 million. These losses are reflected in other comprehensive income and are being amortized to earnings (as an increase in interest expense) over the forecasted hedge period of ten years using the effective interest method.

In connection with EPO's agreement to issue Senior Notes FF and Senior Notes GG in August 2012 (see Note 18), we settled seven forward starting swaps having an aggregate notional amount of $350.0 million, resulting in cash losses of $70.2 million. Accumulated other comprehensive income as of June 30, 2012 includes $63.9 million of the loss, with the remaining $6.3 million of loss attributable to the period June 30, 2012 through the settlement date of August 1, 2012. The total loss recorded in accumulated other comprehensive income will be amortized to earnings (as an increase in interest expense) over the forecasted hedged period of ten years using the effective interest method.

Although we incurred cash losses upon settlement of our forward starting swaps in February 2012 and August 2012, we benefited from the exceptionally low interest rate environment during these periods relative to the interest rates in effect at the time we entered into the swaps.

Commodity Hedging Activities

The prices of natural gas, NGLs, crude oil, refined products and certain petrochemical products are subject to fluctuations in response to changes in supply and demand, market conditions and a variety of additional factors that are beyond our control. In order to manage such price risks, we enter into commodity derivative instruments such as physical forward contracts, futures contracts, fixed-for-float swaps, basis swaps and options contracts. The following table summarizes our commodity derivative instruments outstanding at June 30, 2012:

	Volume (1)		Accounting
Derivative Purpose	Current (2)	Long-Term (2)	Treatment
Derivatives designated as hedging instruments:
Natural gas processing:
Forecasted natural gas purchases for plant thermal reduction ("PTR") (3)	15.3 Bcf	n/a	Cash flow hedge
Forecasted sales of NGLs (4)	1.6 MMBbls	n/a	Cash flow hedge
Octane enhancement:
Forecasted purchases of NGLs	0.2 MMBbls	n/a	Cash flow hedge
Forecasted sales of octane enhancement products	2.0 MMBbls	n/a	Cash flow hedge
Natural gas marketing:
Forecasted sales of natural gas	1.2 Bcf	n/a	Cash flow hedge
Natural gas storage inventory management activities (Bcf)	11.1 Bcf	n/a	Fair value hedge
NGL marketing:
Forecasted purchases of NGLs and related hydrocarbon products	3.2 MMBbls	0.5 MMBbls	Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products	3.7 MMBbls	0.5 MMBbls	Cash flow hedge
Refined products marketing:
Forecasted purchases of refined products	0.1 MMBbls	n/a	Cash flow hedge
Forecasted sales of refined products	0.5 MMBbls	n/a	Cash flow hedge
Refined products inventory management activities	0.2 MMBbls	n/a	Fair value hedge
Crude oil marketing:
Forecasted purchases of crude oil	2.8 MMBbls	n/a	Cash flow hedge
Forecasted sales of crude oil	4.1 MMBbls	n/a	Cash flow hedge
Derivatives not designated as hedging instruments:
Natural gas risk management activities (5,6)	241.0 Bcf	56.0 Bcf	Mark-to-market
Refined products risk management activities (6)	1.1 MMBbls	n/a	Mark-to-market
Crude oil risk management activities (6)	5.7 MMBbls	n/a	Mark-to-market
(1) Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes. (2) The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is December 2013, March 2013 and October 2015, respectively. (3) PTR represents the British thermal unit ("Btu") equivalent of the NGLs extracted from natural gas by a processing plant, and includes the natural gas used as plant fuel to extract those liquids, plant flare and other shortages. (4) Forecasted sales of NGL volumes under natural gas processing exclude 2.2 MMBbls of additional hedges executed under contracts that have been designated as normal sales agreements. (5) Current volumes include approximately 62.5 Bcf of physical derivative instruments that are predominantly priced at an index plus a premium or minus a discount related to location differences. (6) Reflects the use of derivative instruments to manage risks associated with transportation, processing and storage assets.

Our predominant commodity hedging strategies are: (i) hedging natural gas processing margins; (ii) hedging anticipated future contracted sales of NGLs, refined products and crude oil associated with volumes held in inventory; and (iii) hedging the fair value of natural gas in inventory. The following information summarizes these hedging strategies:

The objective of our natural gas processing strategy is to hedge an amount of gross margin associated with our natural gas processing activities. We achieve this objective by using physical and financial instruments to lock in the purchase prices of natural gas consumed as PTR and the sales prices of the related NGL products. This program consists of (i) the forward sale of a portion of our expected equity NGL production at fixed prices through December 2012, which is achieved through the use of forward physical sales contracts and commodity derivative instruments and (ii) the purchase of commodity derivative instruments having a notional amount based on the volume of natural gas expected to be consumed as PTR in the production of such equity NGL production.

§	The objective of our NGL, refined products and crude oil sales hedging program is to hedge the margins of anticipated future sales of inventory by locking in sales prices through the use of forward physical sales contracts and commodity derivative instruments.

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

Tabular Presentation of Fair Value Amounts, and Gains and Losses on

Derivative Instruments and Related Hedged Items

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

	Asset Derivatives						Liability Derivatives
	June 30, 2012			December 31, 2011			June 30, 2012			December 31, 2011
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments
Interest rate derivatives	Other current assets	$	18.6	Other current assets	$	43.7	Other current liabilities	$	230.6	Other current liabilities	$	163.6
Interest rate derivatives	Other assets		26.6	Other assets		44.2	Other liabilities		--	Other liabilities		127.1
Total interest rate derivatives			45.2			87.9			230.6			290.7
Commodity derivatives	Other current assets		127.4	Other current assets		20.3	Other current liabilities		74.6	Other current liabilities		30.3
Commodity derivatives	Other assets		4.8	Other assets		--	Other liabilities		2.1	Other liabilities		0.2
Total commodity derivatives (1)			132.2			20.3			76.7			30.5
Total derivatives designated as hedging instruments		$	177.4		$	108.2		$	307.3		$	321.2

Derivatives not designated as hedging instruments
Interest rate derivatives	Other current assets	$	--	Other current assets	$	--	Other current liabilities	$	11.0	Other current liabilities	$	10.1
Interest rate derivatives	Other assets		--	Other assets		--	Other liabilities		8.6	Other liabilities		10.6
Total interest rate derivatives			--			--			19.6			20.7
Commodity derivatives	Other current assets		26.0	Other current assets		34.4	Other current liabilities		19.4	Other current liabilities		32.5
Commodity derivatives	Other assets		4.4	Other assets		12.6	Other liabilities		1.8	Other liabilities		2.0
Total commodity derivatives			30.4			47.0			21.2			34.5
Total derivatives not designated as hedging instruments		$	30.4		$	47.0		$	40.8		$	55.2

(1) Represents commodity derivative instrument transactions that have either not settled or have settled and cash has not been paid or received. Settled and unpaid or unreceived amounts are reflected in either accounts receivable or accounts payable depending on the outcome of the transaction.

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

Derivatives in Fair Value Hedging Relationships	Location	Gain/(Loss) Recognized in Income on Derivative
		For the Three Months						For the Six Months
		Ended June 30,						Ended June 30,
		2012			2011			2012			2011
Interest rate derivatives	Interest expense	$	4.6		$	21.1		$	3.1		$	8.8
Commodity derivatives	Revenue		(16.4	)		(1.6	)		(15.7	)		(1.3	)
Total		$	(11.8	)	$	19.5		$	(12.6	)	$	7.5

Derivatives in Fair Value Hedging Relationships	Location	Gain/(Loss) Recognized in Income on Hedged Item
		For the Three Months						For the Six Months
		Ended June 30,						Ended June 30,
		2012			2011			2012			2011
Interest rate derivatives	Interest expense	$	(4.5	)	$	(21.0	)	$	(3.4	)	$	(9.7	)
Commodity derivatives	Revenue		15.9			0.2			16.3			(1.1	)
Total		$	11.4		$	(20.8	)	$	12.9		$	(10.8	)

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

Derivatives in Cash Flow Hedging Relationships	Change in Value Recognized in Other Comprehensive Income/(Loss) on Derivative (Effective Portion)
	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2012			2011			2012			2011
Interest rate derivatives	$	(84.0	)	$	(60.1	)	$	(55.1	)	$	(46.0	)
Commodity derivatives - Revenue		99.8			(19.4	)		60.2			(174.8	)
Commodity derivatives - Operating costs and expenses		5.2			(2.3	)		(14.8	)		1.7
Total	$	21.0		$	(81.8	)	$	(9.7	)	$	(219.1	)

Derivatives in Cash Flow Hedging Relationships	Location	Gain/(Loss) Reclassified from Accumulated Other Comprehensive Income/(Loss) to Income (Effective Portion)
		For the Three Months						For the Six Months
		Ended June 30,						Ended June 30,
		2012			2011			2012			2011
Interest rate derivatives	Interest expense	$	(3.7	)	$	(1.5	)	$	(6.4	)	$	(3.0	)
Commodity derivatives	Revenue		(2.6	)		(79.3	)		(12.6	)		(148.5	)
Commodity derivatives	Operating costs and expenses		(11.6	)		4.5			(23.6	)		4.8
Total		$	(17.9	)	$	(76.3	)	$	(42.6	)	$	(146.7	)

Derivatives in Cash Flow Hedging Relationships	Location	Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)
		For the Three Months				For the Six Months
		Ended June 30,				Ended June 30,
		2012		2011		2012		2011
Commodity derivatives	Revenue	$	0.9	$	0.3	$	0.9	$	0.2
Commodity derivatives	Operating costs and expenses		--		--		0.3		--
Total		$	0.9	$	0.3	$	1.2	$	0.2

Over the next twelve months, we expect to reclassify $26.2 million of losses attributable to interest rate derivative instruments from accumulated other comprehensive loss to earnings as an increase in interest expense. Likewise, we expect to reclassify $57.6 million of gains attributable to commodity derivative instruments from accumulated other comprehensive income (loss) to earnings, $59.4 million as an increase in revenue and $1.8 million as an increase in operating costs and expenses.

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

Derivatives Not Designated as Hedging Instruments	Location	Gain/(Loss) Recognized in Income on Derivative
		For the Three Months						For the Six Months
		Ended June 30,						Ended June 30,
		2012			2011			2012			2011
Interest rate derivatives	Interest expense	$	(1.1	)	$	(11.9	)	$	(3.3	)	$	(10.5	)
Commodity derivatives	Revenue		9.3			9.5			30.1			13.3
Commodity derivatives	Operating costs and expenses		--			--			(2.8	)		--
Total		$	8.2		$	(2.4	)	$	24.0		$	2.8

Fair Value Measurements

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

A three-tier hierarchy has been established that classifies fair value amounts recognized in the financial statements based on the observability of inputs used to estimate such fair values. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). At each balance sheet reporting date, we categorize our financial assets and liabilities using this hierarchy.

Recurring Fair Value Measurements

The following table sets forth, by level within the fair value hierarchy, the carrying values of our financial assets and liabilities at June 30, 2012. These assets and liabilities are measured on a recurring basis and are classified based on the lowest level of input that is significant to their respective fair value. Our assessment of the relative significance of such inputs requires judgment.

	Fair Value Measurements Using
	Quoted Prices
	in Active
	Markets for		Significant		Significant		Carrying
	Identical Assets		Observable		Unobservable		Value
	and Liabilities		Inputs		Inputs		at June 30,
	(Level 1)		(Level 2)		(Level 3)		2012
Financial assets:
Interest rate derivatives	$	--	$	45.2	$	--	$	45.2
Commodity derivatives		81.6		73.1		7.9		162.6
Total	$	81.6	$	118.3	$	7.9	$	207.8

Financial liabilities:
Interest rate derivatives	$	--	$	250.2	$	--	$	250.2
Commodity derivatives		39.1		55.8		3.0		97.9
Total	$	39.1	$	306.0	$	3.0	$	348.1

The following table sets forth a reconciliation of changes in the overall fair values of our recurring Level 3 financial assets and liabilities for the periods presented:

		For the Six Months
		Ended June 30,
	Location	2012			2011
Balance, January 1		$	0.4		$	(25.9	)
Total gains (losses) included in:
Net income (1)	Revenue		0.5			(0.5	)
Other comprehensive income (loss)	Commodity derivative instruments - changes in fair value of cash flow hedges		0.5			16.2
Settlements			(0.5	)		0.8
Transfers out of Level 3 (2)			--			9.8
Balance, March 31			0.9			0.4
Total gains (losses) included in:
Net income (1)	Revenue		(1.3	)		1.9
Other comprehensive income (loss)	Commodity derivative instruments - changes in fair value of cash flow hedges		6.0			--
Settlements			(0.7	)		(0.2	)
Balance, June 30		$	4.9		$	2.1

(1) There were $2.0 million and $1.9 million of unrealized losses included in these amounts for the three and six months ended June 30, 2012, respectively. There were $2.0 million and $1.8 million of unrealized gains included in these amounts for the three and six months ended June 30, 2011, respectively. (2) Transfers out of Level 3 into Level 2 during 2011 were primarily due to the change in observability of forward NGL prices.

The following table provides quantitative information about our recurring Level 3 fair value measurements at June 30, 2012:

	Fair Value
	Financial Assets		Financial Liabilities		Valuation Techniques	Unobservable Input	Range
Commodity derivatives - Propane	$	4.7	$	0.9	Discounted cash flow	Forward commodity price	$0.86-$0.92 /gallon
Commodity derivatives - Natural gasoline		2.7		--	Discounted cash flow	Forward commodity price	$1.83-$1.83 /gallon
Commodity derivatives - Crude oil		0.3		2.0	Discounted cash flow	Forward commodity price	$84.96-$88.71 /barrel
Commodity derivatives - Natural gas		0.2		0.1	Discounted cash flow	Forward commodity price	$3.90-$4.13 /million Btu
Total	$	7.9	$	3.0

We believe certain forward commodity prices are the most significant unobservable inputs in determining our recurring Level 3 fair value measurements at June 30, 2012. In general, changes in the price of the underlying commodity increases or decreases the fair value of a commodity derivative depending on whether the derivative was purchased or sold. We generally expect changes in the fair value of our derivative instruments to be offset by corresponding changes in the fair value of our hedged exposures.

We have a risk management policy that covers our Level 3 commodity derivatives. Governance and oversight of risk management activities for these commodities are provided by our CEO with guidance and support from a risk management committee ("RMC"), which meets quarterly (or on a more frequent basis if needed). Members of executive management attend the RMC meetings, which are chaired by the head of our commodities risk control group. This group is responsible for preparing and distributing daily reports and risk analysis to members of the RMC and other appropriate members of management. These reports include mark-to-market valuations with the one-day and month-to-date changes in fair values. This group also develops and validates forward curves used to determine the fair values of our Level 3 commodity derivatives. These forward curves are based on published indexes, market quotes or are derived from other available inputs.

Nonrecurring Fair Value Measurements

The following table presents information regarding certain long-lived asset amounts measured at fair value on a nonrecurring basis during the six months ended June 30, 2012. The estimated fair values are based on the present value of expected future cash flows (Level 3).

	Fair Value Measurements Using								Total
									Non-Cash Asset
	Quoted Prices								Impairment
	in Active		Significant		Significant		Carrying		Charges for the
	Markets for		Observable		Unobservable		Value at		Six Months
	Identical Assets		Inputs		Inputs		June 30,		Ended
	(Level 1)		(Level 2)		(Level 3)		2012		June 30, 2012
NGL Pipelines & Services
Property, plant and equipment, net	$	--	$	--	$	--	$	--	$	8.0
Onshore Crude Oil Pipelines & Services
Property, plant and equipment, net		--		--		--		--		6.2
Petrochemical & Refined Products Services
Long-lived fixed assets held for sale		--		--		0.5		0.5		0.3
Total	$	--	$	--	$	0.5	$	0.5	$	14.5

During the six months ended June 30, 2012, property, plant and equipment with no future value and a carrying amount of $14.2 million was written-off, resulting in non-cash asset impairment charges for the period. In addition, long-lived assets held for sale with a carrying value of $0.8 million were written down to their fair value of $0.5 million, resulting in non-cash asset impairment charges of $0.3 million, which were included in earnings for the period. Long-lived assets held for sale are a component of "Other assets" as presented on our Unaudited Condensed Consolidated Balance Sheets. We did not record any non-cash asset impairment charges during the six months ended June 30, 2011.

Forecast data and other assumptions supporting the fair value of long-lived assets being tested for impairment are based on the nonfinancial assets' highest and best use, which includes estimated probabilities where multiple cash flow outcomes are possible. Such probability weights are generally obtained from business management personnel having oversight responsibilities for the assets in question. Key commercial assumptions (e.g., anticipated operating margins, throughput or processing volume growth rates and timing of cash flows) that represent Level 3 unobservable inputs and test results are reviewed and certified by members of senior management.

Other Fair Value Information

The carrying amounts of cash and cash equivalents (including restricted cash balances), accounts receivable and accounts payable approximate their fair values based on their short-term nature. The estimated total fair value of our fixed-rate debt obligations was approximately $16.27 billion and $15.76 billion at June 30, 2012 and December 31, 2011, respectively. The aggregate carrying value of these debt obligations was $14.58 billion and $14.33 billion at June 30, 2012 and December 31, 2011, respectively. These values are based on quoted market prices for such debt or debt of similar terms and maturities (Level 2), our credit standing and the credit standing of our counterparties. Changes in market rates of interest affect the fair value of our fixed-rate debt. The carrying values of our variable-rate long-term debt obligations approximate their fair values since the associated interest rates are market-based. We do not have any long-term investments in debt or equity securities recorded at fair value.

Inventories

6 Months Ended

Jun. 30, 2012

Inventories [Abstract]

Inventories

Note 5. Inventories

Our inventory amounts by product type were as follows at the dates indicated:

Available-for-Sale Inventory by Product Type	June 30, 2012		December 31, 2011
NGLs	$	553.4	$	563.6
Petrochemicals and refined products		246.1		443.4
Crude oil		46.5		39.2
Natural gas		46.9		65.5
Total	$	892.9	$	1,111.7

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

Due to fluctuating commodity prices, we recognize lower of cost or market adjustments when the carrying value of our available-for-sale inventories exceeds their net realizable value. These non-cash charges are a component of cost of sales in the period they are recognized. To the extent our commodity hedging strategies address inventory-related price risks and are successful, these inventory valuation adjustments are mitigated or offset. See Note 4 for a description of our commodity hedging activities.

The following table presents our total cost of sales amounts and lower of cost or market adjustments for the periods indicated:

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2012		2011		2012		2011
Cost of sales (1)	$	8,195.2	$	9,790.3	$	17,861.0	$	18,609.6
Lower of cost or market adjustments		8.0		0.5		13.9		1.7
(1) Cost of sales is a component of "Operating costs and expenses," as presented on our Unaudited Condensed Statements of Consolidated Operations. Period-to-period fluctuations in these amounts are primarily due to changes in energy commodity prices and sales volumes associated with our marketing activities.

Property, Plant and Equipment

6 Months Ended

Jun. 30, 2012

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Note 6. Property, Plant and Equipment

The historical costs of our property, plant and equipment and related accumulated depreciation balances were as follows at the dates indicated:

	Estimated Useful Life in Years	June 30, 2012		December 31, 2011
Plants, pipelines and facilities (1)	3-45 (6)	$	24,105.7	$	22,354.4
Underground and other storage facilities (2)	5-40 (7)		1,455.9		1,388.6
Platforms and facilities (3)	20-31		637.5		637.5
Transportation equipment (4)	3-10		158.4		151.5
Marine vessels (5)	15-30		660.3		615.9
Land			141.7		136.1
Construction in progress			2,275.7		2,145.6
Total			29,435.2		27,429.6
Less accumulated depreciation			5,674.6		5,238.0
Property, plant and equipment, net		$	23,760.6	$	22,191.6

(1) Plants and pipelines include processing plants; NGL, natural gas, crude oil and petrochemical and refined products 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 located in the Gulf of Mexico. (4) Transportation equipment includes tractor-trailer tank trucks and other vehicles and similar assets used in our operations. (5) Marine vessels include tow boats, barges and related equipment used in our marine transportation business. (6) In general, the estimated useful lives of major assets within this category are: processing plants, 20-35 years; pipelines and related equipment, 5-45 years; terminal facilities, 10-35 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 assets within this category are: 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 presented:

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2012		2011		2012		2011
Depreciation expense (1)	$	222.0	$	189.8	$	434.0	$	376.3
Capitalized interest (2)		29.5		24.8		60.1		42.0
(1) Depreciation expense is a component of "Costs and expenses" as presented on our Unaudited Condensed Statements of Consolidated Operations. (2) We capitalize interest cost incurred on funds used to construct property, plant and equipment. The capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset's estimated useful life as a component of depreciation expense. Capitalized interest reduces interest expense during the period it is recorded.

Asset Retirement Obligations

We record asset retirement obligations ("AROs") related to legal requirements to perform retirement activities as specified in contractual arrangements and/or governmental regulations. When an ARO is incurred, we record a liability for the ARO and capitalize an equal amount as an increase in the carrying value of the related long-lived asset. Over time, the ARO liability is accreted to its present value (through accretion expense) and the capitalized amount is depreciated over the remaining useful life of the related long-term asset. Property, plant and equipment at June 30, 2012 and December 31, 2011 includes $42.5 million and $37.7 million, respectively, of asset retirement costs capitalized as an increase in the associated long-lived asset.

The following table summarizes changes in our ARO liability balance during the six months ended June 30, 2012:

ARO liability balance, December 31, 2011	$	112.0
Liabilities incurred during period		1.1
Liabilities settled during period		(5.9	)
Revisions in estimated cash flows		8.9
Accretion expense		2.7
ARO liability balance, June 30, 2012	$	118.8

The following table presents our forecast of accretion expense for the periods indicated:

Remainder of 2012				2013				2014				2015				2016
$	2.8			$	6.0			$	6.5			$	6.2			$	6.5

The entire disclosure for long-lived, physical assets that are used in the normal conduct of business to produce goods and services and not intended for resale. Examples include land, buildings, machinery and equipment, and other types of furniture and equipment including, but not limited to, office equipment, furniture and fixtures, and computer equipment and software. This disclosure may include property plant and equipment accounting policies and methodology, a schedule of property, plant and equipment gross, additions, deletions, transfers and other changes, depreciation, depletion and amortization expense, net, accumulated depreciation, depletion and amortization expense and useful lives, income statement disclosures, assets held for sale and public utility disclosures.

Investments in Unconsolidated Affiliates [Abstract]

Investments in Unconsolidated Affiliates

6 Months Ended

Jun. 30, 2012

Investments in Unconsolidated Affiliates

Note 7. Investments in Unconsolidated Affiliates

The following table presents our investments in unconsolidated affiliates by business segment at the dates indicated. Unless noted otherwise, we account for these investments using the equity method.

	Ownership Interest at June 30, 2012	June 30, 2012		December 31, 2011
NGL Pipelines & Services:
Venice Energy Service Company, L.L.C.	13.1%	$	31.1	$	35.5
K/D/S Promix, L.L.C.	50%		40.9		40.7
Baton Rouge Fractionators LLC	32.2%		20.6		21.0
Skelly-Belvieu Pipeline Company, L.L.C.	50%		37.4		35.0
Texas Express Pipeline LLC ("Texas Express")	35%		39.2		13.9
Texas Express Gathering LLC ("TEG") (1)	45%		8.9		--
Front Range Pipeline LLC ("Front Range")	33.3%		6.3		--
Onshore Natural Gas Pipelines & Services:
Evangeline (2)	--		--		4.4
White River Hub, LLC	50%		25.5		25.7
Onshore Crude Oil Pipelines & Services:
Seaway Crude Pipeline LLC	50%		179.2		170.7
Offshore Pipelines & Services:
Poseidon Oil Pipeline Company, L.L.C. ("Poseidon")	36%		50.6		55.4
Cameron Highway Oil Pipeline Company	50%		218.2		222.8
Deepwater Gateway, L.L.C.	50%		93.7		94.6
Neptune Pipeline Company, L.L.C.	25.7		48.3		51.1
Southeast Keathley Canyon Pipeline Company L.L.C.	50%		51.7		1.0
Petrochemical & Refined Products Services:
Baton Rouge Propylene Concentrator, LLC	30%		8.9		9.5
Centennial Pipeline LLC ("Centennial")	50%		49.4		51.8
Other (3)	Various		3.3		3.4
Other Investments:
Energy Transfer Equity (4)	--		--		1,023.1
Total		$	913.2	$	1,859.6

(1) In April 2012, we, along with Enbridge Midcoast Energy, LP ("Enbridge") and WGR Asset Holding Company LLC formed a new joint venture, TEG, to design and construct two gas gathering systems to complement the Texas Express Pipeline. Enbridge will construct and operate the systems, which are expected to begin service in the second quarter of 2013. (2) In June 2012, we acquired the remaining ownership interests in Evangeline and it became a wholly owned subsidiary of ours. (3) 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. (4) We ceased using the equity method to account for our investment in Energy Transfer Equity limited partner units effective January 18, 2012 and began accounting for them as available-for-sale securities. We completed the sale of the remaining Energy Transfer Equity units in April 2012 (see below).

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

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2012			2011			2012			2011
NGL Pipelines & Services	$	3.8		$	6.2		$	9.0		$	12.1
Onshore Natural Gas Pipelines & Services		1.2			1.5			2.6			2.7
Onshore Crude Oil Pipelines & Services		3.6			(1.6	)		4.1			(2.1	)
Offshore Pipelines & Services		4.1			6.6			11.0			14.9
Petrochemical & Refined Products Services		(1.4	)		(4.3	)		(7.9	)		(9.3	)
Other Investments (1)		--			2.7			2.4			9.0
Total	$	11.3		$	11.1		$	21.2		$	27.3

(1) With respect to the six months ended June 30, 2012, the amount presented reflects our equity in the income of Energy Transfer Equity from January 1, 2012 to January 18, 2012.

The following table presents unamortized excess cost amounts by business segment at the dates indicated:

	June 30, 2012		December 31, 2011
NGL Pipelines & Services	$	24.2	$	24.7
Onshore Crude Oil Pipelines & Services		18.9		19.2
Offshore Pipelines & Services		14.2		14.8
Petrochemical & Refined Products Services		2.8		2.9
Other Investments (1)		--		1,119.0
Total	$	60.1	$	1,180.6

(1) On January 18, 2012, we discontinued using the equity method to account for our investment in Energy Transfer Equity common units and began accounting for this investment as an available-for-sale security. As a result, we no longer recognized any excess cost amounts associated with this investment.

The following table presents our amortization of excess cost amounts by business segment for the periods presented:

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2012		2011		2012		2011
NGL Pipelines & Services	$	0.3	$	0.2	$	0.5	$	0.5
Onshore Crude Oil Pipelines & Services		0.1		0.2		0.3		0.4
Offshore Pipelines & Services		0.3		0.3		0.6		0.6
Petrochemical & Refined Products Services		--		--		0.1		--
Other Investments (1)		--		8.4		0.3		17.5
Total	$	0.7	$	9.1	$	1.8	$	19.0

(1) Reflects amortization of excess cost amounts related to our investment in Energy Transfer Equity from January 1, 2012 through January 18, 2012, which is the date we ceased using the equity method to account for this investment.

Liquidation of Investment in Energy Transfer Equity

The Other Investments segment included our noncontrolling ownership interest in Energy Transfer Equity, which was accounted for using the equity method until January 18, 2012. We sold 4,450,000 Energy Transfer Equity common units during the second quarter of 2011 for net cash proceeds of $165.8 million and recorded a gain of $5.4 million on the sale. Since our ownership interest in Energy Transfer Equity exceeded 3% throughout calendar year 2011, we accounted for our investment in Energy Transfer Equity using the equity method and included gains on the sale of this asset in operating income. At December 31, 2011, we owned 29,303,514 common units of Energy Transfer Equity.

On January 18, 2012, we sold 22,762,636 of these common units in a private transaction, which generated cash proceeds of approximately $825.1 million and a gain on the sale of $27.5 million. Following completion of the January 18 transaction, our ownership interest in Energy Transfer Equity was below 3%, and we discontinued using the equity method to account for this investment and began accounting for it as an investment in available-for-sale equity securities. For the period January 1, 2012 to January 18, 2012, we recorded $2.4 million of equity earnings from Energy Transfer Equity, which is reflected in our Other Investments segment.

The remaining 6,540,878 units were sold systematically through April 27, 2012 until completely liquidated. These post-January 18 sales generated total cash proceeds of approximately $270.2 million and gains of $41.3 million. The aggregate $68.8 million in gains on the 2012 sales, of which $15.5 million are attributed to sales during the second quarter of 2012, are presented as a component of "Other income." Proceeds from these sales were used for general company purposes, including funding capital expenditures.

All activities included in our sixth reportable business segment, Other Investments, ceased on January 18, 2012, which was the date we discontinued using the equity method to account for our previously held investment in Energy Transfer Equity. See Note 11 for additional information regarding our business segments.

Formation of Front Range Joint Venture

In April 2012, we, along with Anadarko Petroleum Corporation and DCP Midstream, LLC formed a new joint venture, Front Range, to design and construct a new NGL pipeline that will originate in the Denver-Julesburg Basin (the "DJ Basin") in Weld County, Colorado and extend approximately 435 miles to Skellytown in Carson County, Texas. Each party holds a one-third ownership interest in the joint venture. The Front Range Pipeline, with connections to our Mid-America Pipeline System and the Texas Express Pipeline, is expected to provide producers in the DJ Basin with access to the Gulf Coast, the largest NGL market in the U.S. Depending on shipper interest in a binding open commitment period that commenced in April 2012, initial capacity on the Front Range Pipeline is expected to be approximately 150 MBPD, which can be readily expanded to approximately 230 MBPD. We will construct and operate the pipeline, which is expected to begin service in the fourth quarter of 2013.

Summarized Income Statement Information of Unconsolidated Affiliates

The following table presents unaudited income statement information (on a 100% basis for the periods presented) of our unconsolidated affiliates, aggregated by the business segments to which they relate:

	Summarized Income Statement Information for the Three Months Ended
	June 30, 2012								June 30, 2011
	Revenues		Operating Income (Loss)			Net Income (Loss)			Revenues		Operating Income (Loss)			Net Income (Loss)
NGL Pipelines & Services	$	71.5	$	15.3		$	15.2		$	116.4	$	30.5		$	30.6
Onshore Natural Gas Pipelines & Services		2.9		1.9			1.9			54.7		2.7			2.7
Onshore Crude Oil Pipelines & Services		21.5		7.4			7.3			9.6		(2.1	)		(2.1	)
Offshore Pipelines & Services		39.1		12.8			12.5			43.7		17.7			17.5
Petrochemical & Refined Products Services		5.9		(0.3	)		(2.4	)		9.2		(5.4	)		(7.6	)
Other Investments		--		--			--			1,974.9		260.6			66.3

	Summarized Income Statement Information for the Six Months Ended
	June 30, 2012								June 30, 2011
	Revenues		Operating Income (Loss)			Net Income (Loss)			Revenues		Operating Income			Net Income (Loss)
NGL Pipelines & Services	$	182.4	$	42.3		$	42.2		$	216.5	$	53.9		$	54.0
Onshore Natural Gas Pipelines & Services		5.7		3.7			3.7			90.2		5.3			5.3
Onshore Crude Oil Pipelines & Services		33.8		8.2			8.1			20.8		(1.6	)		(1.6	)
Offshore Pipelines & Services		80.2		31.9			30.9			90.0		36.6			36.2
Petrochemical & Refined Products Services		11.3		(9.7	)		(13.8	)		19.3		(12.4	)		(16.8	)
Other Investments		--		--			--			3,964.0		624.8			154.9

We discontinued using the equity method to account for our investment in Energy Transfer Equity common units on January 18, 2012 (see "Liquidation of Investment in Energy Transfer Equity" within this Note 7). As a result, income statement data for Energy Transfer Equity, which was presented within the Other Investments segment in the table above, is not presented for the three and six months ended June 30, 2012. For the three and six months ended June 30, 2011, net income amounts presented for Energy Transfer Equity represents net income attributable to their partners.

Other

The credit agreements of Poseidon and Centennial restrict their ability to pay cash dividends if a default or event of default (as defined in each credit agreement) has occurred and is continuing at the time such payments are scheduled to be paid. These businesses were in compliance with the terms of their credit agreements at June 30, 2012.

The entire disclosure for equity method investments and joint ventures. Equity method investments are investments that give the investor the ability to exercise significant influence over the operating and financial policies of an investee. Joint ventures are entities owned and operated by a small group of businesses as a separate and specific business or project for the mutual benefit of the members of the group.

Intangible Assets and Goodwill [Abstract]

Intangible Assets and Goodwill

6 Months Ended

Jun. 30, 2012

Intangible Assets and Goodwill

Note 8. Intangible Assets and Goodwill

Identifiable Intangible Assets

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

	June 30, 2012							December 31, 2011
	Gross Value		Accum. Amort.			Carrying Value		Gross Value		Accum. Amort.			Carrying Value
NGL Pipelines & Services:
Customer relationship intangibles	$	340.8	$	(138.0	)	$	202.8	$	340.8	$	(128.2	)	$	212.6
Contract-based intangibles		284.7		(147.1	)		137.6		298.4		(169.7	)		128.7
Segment total		625.5		(285.1	)		340.4		639.2		(297.9	)		341.3
Onshore Natural Gas Pipelines & Services:
Customer relationship intangibles		1,163.6		(230.5	)		933.1		1,163.6		(209.7	)		953.9
Contract-based intangibles		468.3		(301.7	)		166.6		464.8		(290.9	)		173.9
Segment total		1,631.9		(532.2	)		1,099.7		1,628.4		(500.6	)		1,127.8
Onshore Crude Oil Pipelines & Services:
Customer relationship intangibles		9.7		(4.4	)		5.3		9.7		(4.1	)		5.6
Contract-based intangibles		0.4		(0.2	)		0.2		0.4		(0.2	)		0.2
Segment total		10.1		(4.6	)		5.5		10.1		(4.3	)		5.8
Offshore Pipelines & Services:
Customer relationship intangibles		205.8		(134.3	)		71.5		205.8		(129.2	)		76.6
Contract-based intangibles		1.2		(0.4	)		0.8		1.2		(0.3	)		0.9
Segment total		207.0		(134.7	)		72.3		207.0		(129.5	)		77.5
Petrochemical & Refined Products Services:
Customer relationship intangibles		104.3		(30.9	)		73.4		104.3		(28.4	)		75.9
Contract-based intangibles		59.7		(31.8	)		27.9		57.6		(29.7	)		27.9
Segment total		164.0		(62.7	)		101.3		161.9		(58.1	)		103.8
Total all segments	$	2,638.5	$	(1,019.3	)	$	1,619.2	$	2,646.6	$	(990.4	)	$	1,656.2

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

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2012		2011		2012		2011
NGL Pipelines & Services	$	9.6	$	10.0	$	19.8	$	20.4
Onshore Natural Gas Pipelines & Services		15.8		20.2		31.6		40.1
Onshore Crude Oil Pipelines & Services		0.1		0.1		0.3		0.2
Offshore Pipelines & Services		2.6		2.8		5.2		5.8
Petrochemical & Refined Products Services		3.2		4.3		6.7		8.6
Total	$	31.3	$	37.4	$	63.6	$	75.1

The following table presents our forecast of amortization expense associated with existing intangible assets for the periods indicated:

Remainder of 2012				2013				2014				2015				2016
$	60.0			$	111.6			$	107.1			$	106.6			$	107.8

Goodwill

Goodwill represents the excess of the purchase price of an acquired business over the amounts assigned to assets acquired and liabilities assumed in the transaction. There have been no changes to our goodwill amounts since those reported in our 2011 Form 10-K.

The entire disclosure for the aggregate amount of goodwill and a description of intangible assets, which may include (a) for amortizable intangible assets (also referred to as finite-lived intangible assets), the carrying amount, the amount of any significant residual value, and the weighted-average amortization period, (b) for intangible assets not subject to amortization (also referred to as indefinite-lived intangible assets), the carrying amount, and (c) the amount of research and development assets acquired and written off in the period, including the line item in the income statement in which the amounts written off are aggregated, if not readily apparent from the income statement. Also discloses (a) for amortizable intangibles assets in total and by major class, the gross carrying amount and accumulated amortization, the total amortization expense for the period, and the estimated aggregate amortization expense for each of the five succeeding fiscal years, (b) for intangible assets not subject to amortization the carrying amount in total and by major class, and (c) for goodwill, in total and for each reportable segment, the changes in the carrying amount of goodwill during the period (including the aggregate amount of goodwill acquired, the aggregate amount of impairment losses recognized, and the amount of goodwill included in the gain (loss) on disposal of a reporting unit). If any part of goodwill has not been allocated to a reportable segment, discloses the unallocated amount and the reasons for not allocating. For each impairment loss recognized related to an intangible asset (excluding goodwill), discloses: (a) a description of the impaired intangible asset and the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method for determining fair value, (c) the caption in the income statement or the statement of activities in which the impairment loss is aggregated, and (d) the segment in which the impaired intangible asset is reported. For each goodwill impairment loss recognized, discloses: (a) a description of the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method of determining the fair value of the associated reporting unit, and (c) if a recognized impairment loss is an estimate not finalized and the reasons why the estimate is not final. May also disclose the nature and amount of any significant adjustments made to a previous estimate of an impairment loss.

Debt Obligations

6 Months Ended

Jun. 30, 2012

Debt Obligations [Abstract]

Debt Obligations

Note 9. Debt Obligations

The following table presents our consolidated debt obligations (arranged by company and maturity date) at the dates indicated:

	June 30, 2012			December 31, 2011
EPO senior debt obligations:
Senior Notes S, 7.625% fixed-rate, due February 2012	$	--		$	490.5
Senior Notes P, 4.60% fixed-rate, due August 2012		500.0			500.0
Senior Notes C, 6.375% fixed-rate, due February 2013		350.0			350.0
Senior Notes T, 6.125% fixed-rate, due February 2013		182.5			182.5
Senior Notes M, 5.65% fixed-rate, due April 2013		400.0			400.0
Senior Notes U, 5.90% fixed-rate, due April 2013		237.6			237.6
Senior Notes O, 9.75% fixed-rate, due January 2014		500.0			500.0
Senior Notes G, 5.60% fixed-rate, due October 2014		650.0			650.0
Senior Notes I, 5.00% fixed-rate, due March 2015		250.0			250.0
Senior Notes X, 3.70% fixed-rate, due June 2015		400.0			400.0
Senior Notes AA, 3.20% fixed-rate, due February 2016		750.0			750.0
$3.5 Billion Multi-Year Revolving Credit Facility, variable-rate, due September 2016		427.0			150.0
Senior Notes L, 6.30% fixed-rate, due September 2017		800.0			800.0
Senior Notes V, 6.65% fixed-rate, due April 2018		349.7			349.7
Senior Notes N, 6.50% fixed-rate, due January 2019		700.0			700.0
Senior Notes Q, 5.25% fixed-rate, due January 2020		500.0			500.0
Senior Notes Y, 5.20% fixed-rate, due September 2020		1,000.0			1,000.0
Senior Notes CC, 4.05% fixed-rate, due February 2022		650.0			650.0
Senior Notes D, 6.875% fixed-rate, due March 2033		500.0			500.0
Senior Notes H, 6.65% fixed-rate, due October 2034		350.0			350.0
Senior Notes J, 5.75% fixed-rate, due March 2035		250.0			250.0
Senior Notes W, 7.55% fixed-rate, due April 2038		399.6			399.6
Senior Notes R, 6.125% fixed-rate, due October 2039		600.0			600.0
Senior Notes Z, 6.45% fixed-rate, due September 2040		600.0			600.0
Senior Notes BB, 5.95% fixed-rate, due February 2041		750.0			750.0
Senior Notes DD, 5.70% fixed-rate, due February 2042		600.0			600.0
Senior Notes EE, 4.85% fixed-rate, due August 2042		750.0			--
TEPPCO senior debt obligations:
TEPPCO Senior Notes, 7.625% fixed-rate, due February 2012		--			9.5
TEPPCO Senior Notes, 6.125% fixed-rate, due February 2013		17.5			17.5
TEPPCO Senior Notes, 5.90% fixed-rate, due April 2013		12.4			12.4
TEPPCO Senior Notes, 6.65% fixed-rate, due April 2018		0.3			0.3
TEPPCO Senior Notes, 7.55% fixed-rate, due April 2038		0.4			0.4
Total principal amount of senior debt obligations		13,477.0			12,950.0
EPO Junior Subordinated Notes A, fixed/variable-rate, due August 2066		550.0			550.0
EPO Junior Subordinated Notes C, fixed/variable-rate, due June 2067		285.8			285.8
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		14.2			14.2
Total principal amount of senior and junior debt obligations		15,009.7			14,482.7
Other, non-principal amounts:
Change in fair value of debt hedged in fair value hedging relationship (1)		39.7			73.8
Unamortized discounts, net of premiums		(32.6	)		(30.0	)
Unamortized deferred net gains related to terminated interest rate swaps (1)		29.9			2.9
Total other, non-principal amounts		37.0			46.7
Less current maturities of debt (2)		(1,700.0	)		(500.0	)
Total long-term debt	$	13,346.7		$	14,029.4

(1) See Note 4 for information regarding our interest rate hedging activities. (2) We expect to refinance the current maturities of our debt obligations prior to their maturity.

The following table presents contractually scheduled maturities of our consolidated debt obligations outstanding at June 30, 2012 for the next five years, and in total thereafter:

			Scheduled Maturities of Debt
	Total		Remainder of 2012		2013		2014		2015		2016		After 2016
Revolving Credit Facility	$	427.0	$	--	$	--	$	--	$	--	$	427.0	$	--
Senior Notes		13,050.0		500.0		1,200.0		1,150.0		650.0		750.0		8,800.0
Junior Subordinated Notes		1,532.7		--		--		--		--		--		1,532.7
Total	$	15,009.7	$	500.0	$	1,200.0	$	1,150.0	$	650.0	$	1,177.0	$	10,332.7

Apart from that discussed below and routine fluctuations in the balance of our revolving credit facility, there have been no significant changes in the terms or amounts of our consolidated debt obligations since those reported in our 2011 Form 10-K.

Issuance of Senior Notes EE in February 2012

In February 2012, EPO issued $750.0 million in principal amount of 30-year unsecured Senior Notes EE at 99.542% of their principal amount. Senior Notes EE have a fixed interest rate of 4.85% and mature on August 15, 2042. Enterprise guarantees the notes through an unconditional guarantee on an unsecured and unsubordinated basis. Net proceeds from the issuance of Senior Notes EE were used to repay outstanding amounts on the maturity of our $490.5 million principal amount of Senior Notes S due February 2012 and our $9.5 million principal amount of TEPPCO Senior Notes due February 2012 and for general company purposes.

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

In August 2012, EPO agreed to issue $650 million in principal amount of Senior Notes FF and $1.1 billion in principal amount of Senior Notes GG. See Note 18 for information regarding this subsequent event.

Commercial Paper Program

On August 8, 2012, EPO established a commercial paper program, under which EPO may issue up to $2.0 billion of short-term commercial paper notes outstanding at any time. See Note 18 for information regarding this subsequent event.

Letters of Credit

At June 30, 2012, EPO had $77.5 million in letters of credit outstanding related to its commodity derivative instruments. These letters of credit do not reduce the amount available for borrowing under EPO's $3.5 Billion Multi-Year Revolving Credit Facility.

Parent-Subsidiary Guarantor Relationships

Enterprise Products Partners L.P. acts as guarantor of the consolidated debt obligations of EPO with the exception of the remaining debt obligations of TEPPCO. If EPO were to default on any of its guaranteed debt, Enterprise Products Partners L.P. would be responsible for full and unconditional repayment of that obligation.

Lender Financial Covenants

We were in compliance with the financial covenants of our consolidated debt agreements at June 30, 2012.

Information Regarding Variable Interest Rates Paid

The following table presents the range of interest rates and weighted-average interest rates paid on our consolidated variable-rate debt obligation during the six months ended June 30, 2012:

	Range of Interest Rates Paid	Weighted-Average Interest Rate Paid
EPO $3.5 Billion Multi-Year Revolving Credit Facility	1.54% to 3.63%	1.61%

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

Equity and Distributions

6 Months Ended

Jun. 30, 2012

Equity and Distributions [Abstract]

Equity and Distributions

Note 10. Equity and Distributions

Partners' equity reflects the various classes of limited partner interests (common units, including restricted common units, and Class B units) that we have outstanding. The following table summarizes changes in the number of our units outstanding during the six months ended June 30, 2012:

	Common Units			Class B Units		Treasury Units
Number of units outstanding at December 31, 2011		881,620,418			4,520,431		--
Common units issued in connection with DRIP and EUPP		1,270,609			--		--
Common units issued in connection with equity-based awards		214,492			--		--
Restricted common unit awards issued		1,538,438			--		--
Forfeiture of restricted common unit awards		(95,575	)		--		--
Acquisition of treasury units in connection with vesting of equity-based awards		(373,391	)		--		373,391
Cancellation of treasury units		--			--		(373,391	)
Number of units outstanding at June 30, 2012		884,174,991			4,520,431		--

During the six months ended June 30, 2012, 1,236,352 restricted common unit awards held by EPCO employees vested and converted to common units. Of this amount, 373,391 common units were sold back to us by the recipients to cover related withholding tax requirements. We cancelled such treasury units immediately upon acquisition.

We may issue additional equity or debt securities to assist us in meeting our future liquidity and capital spending requirements. We have a universal shelf registration statement (the "2010 Shelf") on file with the SEC. The 2010 Shelf allows Enterprise and EPO (on a standalone basis) to issue an unlimited amount of equity and debt securities, respectively. EPO utilized the 2010 Shelf to issue its Senior Notes EE in February 2012 (see Note 9) and will use the 2010 Shelf to issue additional senior notes in August 2012 (see Note 18).

In May 2012, we entered into an equity distribution agreement with certain broker-dealers pursuant to which we may offer and sell up to $1.0 billion of our common units in amounts, at prices and on terms to be determined by market conditions and other factors at the time of such offerings. Pursuant to this "at-the-market" program, we may sell common units under the agreement from time-to-time by means of ordinary brokers' transactions through the NYSE at market prices, in block transactions or as otherwise agreed to with the broker-dealer parties to the agreement. A registration statement covering the issuance of common units pursuant to this agreement was filed with the SEC in March 2012. There were no issuances and sales under this agreement as of June 30, 2012.

We also have registration statements on file with the SEC collectively authorizing the issuance of up to 70,000,000 of our common units in connection with a 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 our common units they own by reinvesting the quarterly cash distributions they would otherwise receive from us into the purchase of additional common units. After taking into account the number of common units issued under the DRIP through June 30, 2012, we may issue an additional 24,974,588 common units under this plan. A total of 1,198,552 common units were issued during the six months ended June 30, 2012 under our DRIP, which generated net cash proceeds of $58.0 million.

In addition to the DRIP, we have a registration statement on file with the SEC authorizing the issuance of up to 440,879 of our common units in connection with an employee unit purchase plan ("EUPP"). After taking into account the number of common units issued under the EUPP through June 30, 2012, we may issue an additional 358,791 common units under this plan. A total of 72,057 common units were issued during the six months ended June 30, 2012 under our EUPP, which generated net cash proceeds of $3.7 million.

The net cash proceeds we received from the DRIP and EUPP during the six months ended June 30, 2012 were used to temporarily reduce borrowings outstanding under EPO's revolving credit facility and for general company purposes.

Accumulated Other Comprehensive Income (Loss)

Accumulated other comprehensive income (loss) primarily reflects the effective portion of the gain or loss on derivative instruments designated and qualified as cash flow hedges. Gain or loss amounts related to cash flow hedges recorded in accumulated other comprehensive income (loss) are reclassified to earnings in the same period(s) in which the underlying hedged forecasted transactions affect earnings. If it becomes probable that a forecasted transaction will not occur, the related net gain or loss in accumulated other comprehensive income (loss) is immediately reclassified into earnings.

The following table presents the components of accumulated other comprehensive income (loss) as reported on our Unaudited Condensed Consolidated Balance Sheets at the dates indicated:

	June 30, 2012			December 31, 2011
Commodity derivative instruments (1)	$	60.2		$	(21.4	)
Interest rate derivative instruments (1)		(377.7	)		(329.0	)
Foreign currency translation adjustment (2)		1.7			1.7
Pension and postretirement benefit plans		(2.9	)		(1.7	)
Other		--			(1.0	)
Total accumulated other comprehensive loss	$	(318.7	)	$	(351.4	)

(1) See Note 4 for additional information regarding our derivative instruments. (2) Relates to transactions of a Canadian subsidiary.

Noncontrolling Interests

The following table presents additional information regarding noncontrolling interests as presented on our Unaudited Condensed Consolidated Balance Sheets at the dates indicated:

	June 30, 2012		December 31, 2011
Joint venture partners (1)	$	109.8	$	105.9
(1) Represents third party ownership interests in joint ventures that we consolidate, including Tri-States NGL Pipeline L.L.C., Independence Hub LLC, Rio Grande Pipeline Company and Wilprise Pipeline Company LLC.

The following table presents the components of net income attributable to noncontrolling interests as presented on our Unaudited Condensed Statements of Consolidated Operations for the periods presented:

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2012		2011		2012		2011
Former owners of Duncan Energy Partners	$	--	$	9.4	$	--	$	17.3
Joint venture partners		0.9		5.4		5.1		11.3
Total	$	0.9	$	14.8	$	5.1	$	28.6

Prior to completion of the Duncan Merger (see Note 1), we accounted for the former owners' interest in Duncan Energy Partners as noncontrolling interest. Under this method of presentation, all pre-Duncan Merger revenues and expenses of Duncan Energy Partners are included in net income, and the former owners' share of the income of Duncan Energy Partners is a component of "Net income attributable to noncontrolling interests" as reflected on our Unaudited Condensed Statements of Consolidated Operations.

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

	For the Six Months Ended June 30,
	2012		2011
Cash distributions paid to noncontrolling interests:
Former owners of Duncan Energy Partners	$	--	$	21.9
Joint venture partners		8.1		12.9
Total cash distributions paid to noncontrolling interests	$	8.1	$	34.8

Cash contributions from noncontrolling interests:
Former owners of Duncan Energy Partners	$	--	$	1.5
Joint venture partners		5.9		1.1
Total cash contributions from noncontrolling interests	$	5.9	$	2.6

Cash distributions paid to the former owners of Duncan Energy Partners (prior to the Duncan Merger) represent the quarterly cash distributions paid to its unitholders. Similarly, cash contributions received from the former owners of Duncan Energy Partners (prior to the Duncan Merger) represent net cash proceeds received from the issuance of its limited partner units.

Cash Distributions

The following table presents our declared quarterly cash distribution rates with respect to the quarter indicated:

	Distribution Per Common Unit		Record Date	Payment Date
2012
1st Quarter	$	0.6275	04/30/12	05/09/12
2nd Quarter	$	0.6350	07/31/12	08/08/12

A privately held affiliate of EPCO has agreed to temporarily waive the regular quarterly cash distributions it would otherwise receive from us with respect to a certain number of our common units it owns (the "Designated Units"). The temporary distribution waiver remains in effect for five years following the closing date of the Holdings Merger, which was completed in November 2010. For the remaining term of the waiver agreement, the number of Designated Units is as follows for distributions paid or to be paid, if any, during the following calendar years: 26,130,000 during 2012; 23,700,000 during 2013; 22,560,000 during 2014; and 17,690,000 during 2015.

The entire disclosure for shareholders' equity, comprised of portions attributable to the parent entity and noncontrolling interest, if any, including other comprehensive income (as applicable). Including, but not limited to: (1) balances of common stock, preferred stock, additional paid-in capital, other capital and retained earnings; (2) accumulated balance for each classification of other comprehensive income and total amount of comprehensive income; (3) amount and nature of changes in separate accounts, including the number of shares authorized and outstanding, number of shares issued upon exercise and conversion, and for other comprehensive income, the adjustments for reclassifications to net income; (4) rights and privileges of each class of stock authorized; (5) basis of treasury stock, if other than cost, and amounts paid and accounting treatment for treasury stock purchased significantly in excess of market; (6) dividends paid or payable per share and in the aggregate for each class of stock for each period presented; (7) dividend restrictions and accumulated preferred dividends in arrears (in aggregate and per share amount); (8) retained earnings appropriations or restrictions, such as dividend restrictions; (9) impact of change in accounting principle, initial adoption of new accounting principle and correction of an error in previously issued financial statements; (10) shares held in trust for Employee Stock Ownership Plan (ESOP); (11) deferred compensation related to issuance of capital stock; (12) note received for issuance of stock; (13) unamortized discount on shares; (14) description, terms, and number of warrants or rights outstanding; (15) shares under subscription and subscription receivables, effective date of new retained earnings after quasi-reorganization and deficit eliminated by quasi-reorganization and, for a period of at least ten years after the effective date, the point in time from which the new retained dates; and (16) retroactive effective of subsequent change in capital structure.

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Business Segments

6 Months Ended

Jun. 30, 2012

Business Segments [Abstract]

Business Segments

Note 11. Business Segments

We currently have five active reportable business segments: (i) NGL Pipelines & Services; (ii) Onshore Natural Gas Pipelines & Services; (iii) Onshore Crude Oil Pipelines & Services; (iv) Offshore Pipelines & Services; and (v) Petrochemical & Refined Products Services. Our business segments are generally organized and managed according to the type of services rendered (or technologies employed) and products produced and/or sold.

All activities included in our sixth reportable business segment, Other Investments, ceased on January 18, 2012, which was the date we discontinued using the equity method to account for our previously held investment in Energy Transfer Equity. See Note 7 for information regarding the liquidation of our investment in Energy Transfer Equity.

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 expenses; (ii) non-cash asset impairment charges; (iii) operating lease expenses for which we did 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 the preparation of our consolidated financial statements. Gross operating margin is exclusive of other income and expense transactions, income taxes, the cumulative effect of changes in accounting principles and extraordinary charges. Gross operating margin is presented on a 100% basis before any allocation of earnings to noncontrolling interests.

We include equity in income of unconsolidated affiliates in our measurement of segment gross operating margin and operating income. Equity investments with industry partners are a significant component of our business strategy. They are a means by which we conduct our operations to align our interests with those of 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. Many of these businesses perform supporting or complementary roles to our other midstream business operations.

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

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2012			2011			2012			2011
Revenues	$	9,789.8		$	11,216.5		$	21,042.3		$	21,400.2
Less: Operating costs and expenses		(9,009.5	)		(10,533.3	)		(19,476.7	)		(20,070.4	)
Add: Equity in income of unconsolidated affiliates		11.3			11.1			21.2			27.3
Depreciation, amortization and accretion (1)		261.3			233.3			515.9			464.1
Non-cash asset impairment charges		9.1			--			14.5			--
Operating lease expenses paid by EPCO		--			0.1			--			0.3
Gains related to asset sales (2)		(1.3	)		(5.2	)		(3.8	)		(23.6	)
Gains related to property damage insurance recoveries (see Note 16)		(27.7	)		--			(27.7	)		--
Total segment gross operating margin	$	1,033.0		$	922.5		$	2,085.7		$	1,797.9

(1) Amount is a component of "Depreciation, amortization and accretion" as presented on the Unaudited Condensed Statements of Consolidated Cash Flows. (2) Amounts presented for the second quarter of 2011 and the six months ended June 30, 2011 include $5.4 million of gains related to the sale of a portion of our previously held equity method investment in Energy Transfer Equity (see Note 7).

The following table presents a reconciliation of total segment gross operating margin to operating income and further to income before income taxes for the periods indicated:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2012			2011			2012			2011
Total segment gross operating margin	$	1,033.0		$	922.5		$	2,085.7		$	1,797.9
Adjustments to reconcile total segment gross operating margin to operating income:
Amounts included in operating costs and expenses:
Depreciation, amortization and accretion		(261.3	)		(233.3	)		(515.9	)		(464.1	)
Non-cash asset impairment charges		(9.1	)		--			(14.5	)		--
Operating lease expenses paid by EPCO		--			(0.1	)		--			(0.3	)
Gains related to asset sales		1.3			5.2			3.8			23.6
Gains related to property damage insurance recoveries (see Note 16)		27.7			--			27.7			--
General and administrative costs		(42.5	)		(50.4	)		(88.8	)		(88.3	)
Operating income		749.1			643.9			1,498.0			1,268.8
Other expense, net		(173.4	)		(188.0	)		(301.2	)		(371.3	)
Income before income taxes	$	575.7		$	455.9		$	1,196.8		$	897.5

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

	Reportable Business Segments
	NGL Pipelines & Services		Onshore Natural Gas Pipelines & Services			Onshore Crude Oil Pipelines & Services			Offshore Pipelines & Services		Petrochemical & Refined Products Services				Other Investments		Adjustments and Eliminations			Consolidated Total
Revenues from third parties:
Three months ended June 30, 2012	$	3,327.9		$	700.9	$	4,188.7		$	47.5		$	1,499.2		$	--	$	--		$	9,764.2
Three months ended June 30, 2011		3,960.1			862.5		4,281.6			61.1			1,907.0			--		--			11,072.3
Six months ended June 30, 2012		7,682.0			1,505.8		8,662.3			101.9			3,033.9			--		--			20,985.9
Six months ended June 30, 2011		8,015.5			1,734.2		7,652.2			121.7			3,482.3			--		--			21,005.9
Revenues from related parties:
Three months ended June 30, 2012		4.6			19.5		--			1.5			--			--		--			25.6
Three months ended June 30, 2011		76.8			64.8		--			2.6			--			--		--			144.2
Six months ended June 30, 2012		5.0			48.2		--			3.2			--			--		--			56.4
Six months ended June 30, 2011		278.2			109.7		--			6.4			--			--		--			394.3
Intersegment and intrasegment revenues:
Three months ended June 30, 2012		2,276.5			179.0		1,735.5			1.7			438.7			--		(4,631.4	)		--
Three months ended June 30, 2011		3,228.2			253.9		1,477.6			0.1			445.5			--		(5,405.3	)		--
Six months ended June 30, 2012		5,094.7			402.7		3,466.4			5.0			878.6			--		(9,847.4	)		--
Six months ended June 30, 2011		6,702.8			524.8		2,184.7			1.8			918.6			--		(10,332.7	)		--
Total revenues:
Three months ended June 30, 2012		5,609.0			899.4		5,924.2			50.7			1,937.9			--		(4,631.4	)		9,789.8
Three months ended June 30, 2011		7,265.1			1,181.2		5,759.2			63.8			2,352.5			--		(5,405.3	)		11,216.5
Six months ended June 30, 2012		12,781.7			1,956.7		12,128.7			110.1			3,912.5			--		(9,847.4	)		21,042.3
Six months ended June 30, 2011		14,996.5			2,368.7		9,836.9			129.9			4,400.9			--		(10,332.7	)		21,400.2
Equity in income (loss) of unconsolidated affiliates:
Three months ended June 30, 2012		3.8			1.2		3.6			4.1			(1.4	)		--		--			11.3
Three months ended June 30, 2011		6.2			1.5		(1.6	)		6.6			(4.3	)		2.7		--			11.1
Six months ended June 30, 2012		9.0			2.6		4.1			11.0			(7.9	)		2.4		--			21.2
Six months ended June 30, 2011		12.1			2.7		(2.1	)		14.9			(9.3	)		9.0		--			27.3
Gross operating margin:
Three months ended June 30, 2012		565.8			175.8		95.8			38.3			157.3			--		--			1,033.0
Three months ended June 30, 2011		497.7			161.1		67.8			53.4			139.8			2.7		--			922.5
Six months ended June 30, 2012		1,220.7			382.0		135.1			90.4			255.1			2.4		--			2,085.7
Six months ended June 30, 2011		1,002.1			320.3		99.6			114.7			252.2			9.0		--			1,797.9
Segment assets:
At June 30, 2012		8,534.7			10,419.1		1,315.5			2,001.9			3,838.4			--		2,275.7			28,385.3
At December 31, 2011		7,966.4			9,949.6		944.6			2,000.9			3,769.5			1,023.1		2,145.6			27,799.7
Property, plant and equipment, net: (see Note 6)
At June 30, 2012		7,668.7			8,997.6		819.6			1,385.0			2,614.0			--		2,275.7			23,760.6
At December 31, 2011		7,137.8			8,495.4		456.9			1,416.4			2,539.5			--		2,145.6			22,191.6
Investments in unconsolidated affiliates: (see Note 7)
At June 30, 2012		184.4			25.5		179.2			462.5			61.6			--		--			913.2
At December 31, 2011		146.1			30.1		170.7			424.9			64.7			1,023.1		--			1,859.6
Intangible assets, net: (see Note 8)
At June 30, 2012		340.4			1,099.7		5.5			72.3			101.3			--		--			1,619.2
At December 31, 2011		341.3			1,127.8		5.8			77.5			103.8			--		--			1,656.2
Goodwill: (see Note 8)
At June 30, 2012		341.2			296.3		311.2			82.1			1,061.5			--		--			2,092.3
At December 31, 2011		341.2			296.3		311.2			82.1			1,061.5			--		--			2,092.3

The following table presents additional information regarding our consolidated revenues and costs and expenses for the periods indicated:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2012			2011			2012			2011
NGL Pipelines & Services:
Sales of NGLs and related products	$	3,133.9		$	3,832.2		$	7,249.2		$	7,889.9
Midstream services		198.6			204.7			437.8			403.8
Total		3,332.5			4,036.9			7,687.0			8,293.7
Onshore Natural Gas Pipelines & Services:
Sales of natural gas		510.8			719.5			1,083.4			1,432.2
Midstream services		209.6			207.8			470.6			411.7
Total		720.4			927.3			1,554.0			1,843.9
Onshore Crude Oil Pipelines & Services:
Sales of crude oil		4,174.0			4,257.9			8,621.6			7,606.1
Midstream services		14.7			23.7			40.7			46.1
Total		4,188.7			4,281.6			8,662.3			7,652.2
Offshore Pipelines & Services:
Sales of natural gas		--			0.3			0.1			0.6
Sales of crude oil		--			2.5			1.4			5.8
Midstream services		49.0			60.9			103.6			121.7
Total		49.0			63.7			105.1			128.1
Petrochemical & Refined Products Services:
Sales of petrochemicals and refined products		1,316.8			1,718.7			2,668.0			3,101.5
Midstream services		182.4			188.3			365.9			380.8
Total		1,499.2			1,907.0			3,033.9			3,482.3
Total consolidated revenues	$	9,789.8		$	11,216.5		$	21,042.3		$	21,400.2

Consolidated costs and expenses
Operating costs and expenses:
Cost of sales	$	8,195.2		$	9,790.3		$	17,861.0		$	18,609.6
Other operating costs and expenses (1)		572.9			514.9			1,116.8			1,020.3
Depreciation, amortization and accretion		261.3			233.3			515.9			464.1
Gains related to asset sales		(1.3	)		(5.2	)		(3.8	)		(23.6	)
Gains related to property damage insurance recoveries		(27.7	)		--			(27.7	)		--
Non-cash asset impairment charges		9.1			--			14.5			--
General and administrative costs		42.5			50.4			88.8			88.3
Total consolidated costs and expenses	$	9,052.0		$	10,583.7		$	19,565.5		$	20,158.7

(1) Represents cost of operating our plants, pipelines and other fixed assets, excluding non-cash depreciation, amortization and accretion charges.

Period-to-period fluctuations in our product sales revenues and related cost of sales amounts are explained in part by changes in energy commodity prices. In general, lower energy commodity prices result in a decrease in our revenues attributable to product sales; however, these lower commodity prices also decrease the associated cost of sales as purchase costs decline.

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

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Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 131
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Related Party Transactions

Related Party Transactions

6 Months Ended

Jun. 30, 2012

Note 12. Related Party Transactions

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

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2012		2011		2012		2011
Revenues - related parties:
Energy Transfer Equity and subsidiaries	$	--	$	86.7	$	--	$	296.9
Other unconsolidated affiliates		25.6		57.5		56.4		97.4
Total revenue - related parties	$	25.6	$	144.2	$	56.4	$	394.3
Costs and expenses - related parties:
EPCO and affiliates	$	240.1	$	192.4	$	406.1	$	365.4
Energy Transfer Equity and subsidiaries		--		223.0		--		490.4
Other unconsolidated affiliates		7.2		11.4		12.3		21.6
Total costs and expenses - related parties	$	247.3	$	426.8	$	418.4	$	877.4

Energy Transfer Equity was a related party to us during the period in which we accounted for our investment in its limited partner units using the equity method of accounting. We ceased reporting Energy Transfer Equity as a related party in January 2012. See Note 7 for information regarding the liquidation of our investment in Energy Transfer Equity.

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

	June 30, 2012		December 31, 2011
Accounts receivable - related parties:
Energy Transfer Equity and subsidiaries	$	--	$	28.4
Other unconsolidated affiliates		2.3		15.1
Total accounts receivable - related parties	$	2.3	$	43.5

Accounts payable - related parties:
EPCO and affiliates	$	61.8	$	108.3
Energy Transfer Equity and subsidiaries		--		92.6
Other unconsolidated affiliates		8.4		10.7
Total accounts payable - related parties	$	70.2	$	211.6

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 privately held affiliates (including Enterprise GP, our sole general partner), which are not a part of our consolidated group of companies.

EPCO is a privately held company controlled collectively by the EPCO Trustees. At June 30, 2012, EPCO and its privately held affiliates (including Dan Duncan LLC and two Duncan family trusts, the beneficiaries of which include the estate of Mr. Duncan) beneficially owned the following limited partner interests in us:

Number of Units	Percentage of Total Units Outstanding
338,930,881 (1)	38.1%
(1) Includes 4,520,431 Class B units.

Dan Duncan LLC owns 100% of our general partner, Enterprise GP.

We and Enterprise GP are both separate legal entities apart from each other and apart from EPCO and its other affiliates, with assets and liabilities that are also separate from those of EPCO and its other affiliates. EPCO and its privately held affiliates depend on the cash distributions they receive from us and other investments to fund their other operations and to meet their debt obligations. During the six months ended June 30, 2012 and 2011, we paid EPCO and its privately held affiliates cash distributions of $369.6 million and $346.4 million, respectively.

We have no employees. All of our operating functions and general and administrative support services are provided by employees of EPCO pursuant to the ASA or by other service providers. The following table presents costs and expenses related to the ASA and other EPCO transactions for the periods indicated:

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2012		2011		2012		2011
Operating costs and expenses	$	213.6	$	157.9	$	356.3	$	305.3
General and administrative expenses		26.5		34.5		49.8		60.1
Total costs and expenses	$	240.1	$	192.4	$	406.1	$	365.4

The entire disclosure for related party transactions. Examples of related party transactions include transactions between (a) a parent company and its subsidiary; (b) subsidiaries of a common parent; (c) and entity and its principal owners; and (d) affiliates.

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Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 57
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Earnings Per Unit

6 Months Ended

Jun. 30, 2012

Earnings Per Unit [Abstract]

Earnings Per Unit

Note 13. Earnings Per Unit

Basic earnings per unit is computed by dividing net income or loss attributable to our limited partners by the weighted-average number of our distribution-bearing units outstanding during a period, which excludes the Designated Units (see Note 10) to the extent that such units do not participate in the distributions to be paid with respect to such period.

Diluted earnings per unit is computed by dividing net income or loss attributable to our limited partners by the sum of (i) the weighted-average number of our distribution-bearing units outstanding during a period (as used in determining basic earnings per unit), (ii) the weighted-average number of our Class B units outstanding during a period, (iii) the weighted-average number of Designated 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").

The following table presents our calculation of basic and diluted earnings per unit for the periods indicated:

	For the Three Months Ended June 30				For the Six Months Ended June 30,
	2012		2011		2012		2011
BASIC EARNINGS PER UNIT
Numerator:
Net income attributable to limited partners	$	566.3	$	433.7	$	1,217.6	$	854.4
Denominator:
Weighted-average number of:
Distribution-bearing common units outstanding		857.9		815.1		857.3		814.5
Basic earnings per unit:
Net income attributable to limited partners	$	0.66	$	0.53	$	1.42	$	1.05
DILUTED EARNINGS PER UNIT
Numerator:
Net income attributable to limited partners	$	566.3	$	433.7	$	1,217.6	$	854.4
Denominator:
Weighted-average number of:
Distribution-bearing common units outstanding		857.9		815.1		857.3		814.5
Class B units		4.5		4.5		4.5		4.5
Designated Units (see Note 10)		26.1		30.6		26.1		30.6
Incremental option units		1.4		1.2		1.4		1.3
Total		889.9		851.4		889.3		850.9
Diluted earnings per unit:
Net income attributable to limited partners	$	0.64	$	0.51	$	1.37	$	1.00

Commitments and Contingencies	6 Months Ended
Commitments and Contingencies	Jun. 30, 2012
Commitments and Contingencies [Abstract]
Commitments and Contingencies	Note 14. Commitments and Contingencies As part of our normal business activities, we may be named as defendants in legal proceedings, including those arising from 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 fully indemnify us against losses arising from future legal proceedings. We will vigorously defend the partnership in litigation matters. Management has regular quarterly litigation reviews, including updates from legal counsel, to assess the possible need for accounting recognition and disclosure of these contingencies. We accrue an undiscounted liability for those contingencies where the loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum amount in the range is accrued. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material to our consolidated financial statements, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss. Based on a consideration of all relevant known facts and circumstances, we do not believe that the ultimate outcome of any currently pending litigation directed against us will have a material impact on our consolidated financial statements either individually at the claim level or in the aggregate. At June 30, 2012 and December 31, 2011, our accruals for litigation contingencies were $16.2 million and $16.5 million, respectively, and were recorded in our Unaudited Condensed Consolidated Balance Sheets as a component of "Other current liabilities." Our accruals for litigation contingencies are recorded on an undiscounted basis. Our evaluation of litigation contingencies is based on the facts and circumstances of each case and predicting the outcome of these matters involves uncertainties. In the event the assumptions we use to evaluate these matters change in future periods or new information becomes available, we may be required to record additional accruals. In an effort to mitigate expenses associated with litigation, we may settle legal proceedings out of court. Contractual Obligations Scheduled Maturities of Long-Term Debt. With the exception of (i) routine fluctuations in the balance of our revolving credit facility, (ii) the issuance of Senior Notes EE in February 2012 and (iii) the repayment of Senior Notes S and TEPPCO Senior Notes in February 2012, there have been no significant changes in our consolidated debt obligations since those reported in our 2011 Form 10-K. See Note 9 for additional information regarding our consolidated debt obligations. Operating Lease Obligations. Consolidated lease and rental expense was $22.7 million and $21.5 million during the three months ended June 30, 2012 and 2011, respectively. For the six months ended June 30, 2012 and 2011, consolidated lease and rental expense was $45.1 million and $42.0 million, respectively. There have been no material changes in our operating lease commitments since those reported in our 2011 Form 10-K. Purchase Obligations. There have been no material changes in our consolidated purchase obligations since those reported in our 2011 Form 10-K. Other Claims As part of our normal business activities with joint venture partners and certain customers and suppliers, we occasionally make claims against such parties or have claims made against us as a result of disputes related to contractual agreements or similar arrangements. As of June 30, 2012, our contingent claims against such parties were approximately $39.1 million and claims against us were approximately $42.1 million. These matters are in various stages of assessment and the ultimate outcome of such disputes cannot be reasonably estimated at this time. With respect to claims against us, we believe that the likelihood of a material loss resulting from such claims is remote. Accordingly, no accruals for loss contingencies related to these matters have been recorded.

The entire disclosure for commitments and contingencies.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 14
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 5
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

6 Months Ended

Jun. 30, 2012

Supplemental Cash Flow Information

Note 15. Supplemental Cash Flow Information

The following table presents the net effect of changes in our operating accounts for the periods indicated:

	For the Six Months
	Ended June 30,
	2012			2011
Decrease (increase) in:
Accounts receivable - trade	$	785.5		$	(474.2	)
Accounts receivable - related parties		35.7			(0.2	)
Inventories		(20.8	)		266.5
Prepaid and other current assets		(13.9	)		(55.8	)
Other assets		(53.7	)		(34.2	)
Increase (decrease) in:
Accounts payable - trade		(45.7	)		110.9
Accounts payable - related parties		(141.3	)		49.9
Accrued product payables		(880.2	)		479.0
Accrued interest		1.0			18.1
Other current liabilities		84.1			(10.4	)
Other liabilities		(31.0	)		11.8
Net effect of changes in operating accounts	$	(280.3	)	$	361.4

We incurred liabilities for construction in progress that had not been paid at June 30, 2012 and December 31, 2011 of $289.8 million and $286.9 million, respectively. Such amounts are not included under the caption "Capital expenditures" on the Unaudited Condensed Statements of Consolidated Cash Flows.

On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with projects related to pipeline construction and production well tie-ins. These cash receipts are presented as "Contributions in aid of construction costs" within the investing activities section of our Unaudited Condensed Statements of Consolidated Cash Flows.

Proceeds from asset sales increased $878.5 million period-to-period, primarily from the sale of 29,303,514 common units of Energy Transfer Equity during the six months ended June 30, 2012. See Note 7 for information regarding our investment in Energy Transfer Equity.

See Note 16 for information regarding the collection of $27.7 million of nonrefundable property damage insurance proceeds during the second quarter of 2012.

See Note 10 for information regarding cash amounts attributable to noncontrolling interests.

Insurance Matters	6 Months Ended
Insurance Matters	Jun. 30, 2012
Insurance Matters [Abstract]
Insurance Matters [Text Block]	Note 16. Insurance Matters We participate as a named insured in EPCO's insurance program, which provides us with property damage, business interruption and other insurance coverage, the scope and amounts of which we believe are customary and prudent for the nature and extent of our operations. While we believe EPCO maintains adequate insurance coverage on our behalf, insurance may not fully cover every type of damage, interruption or other loss that might occur. If we were to incur a significant loss for which we were not fully insured, it could have a material impact on our financial position, results of operations and cash flows. In addition, there may be timing differences between amounts we accrue related to property damage expense, amounts we are required to pay in connection with a loss and amounts we subsequently receive from insurance carriers as reimbursements. Any event that materially interrupts the revenues generated by our consolidated operations, or other losses that require us to make material expenditures not reimbursed by insurance, could reduce our ability to pay distributions to our unitholders and, accordingly, adversely affect the market price of our common units. Involuntary conversions result from the loss of an asset because of some unforeseen event (e.g., destruction due to fire). Some of these events are insurable, thus resulting in a property damage insurance recovery. Amounts we receive from insurance carriers are net of any deductibles related to the covered event. EPCO renewed its annual insurance programs during the second quarter of 2012. Under terms of the renewed policies,EPCO's deductibles for property damage claims now range from $5.0 million to $60.0 million depending on the nature of the loss (windstorm or non-windstorm) and the assets involved (onshore or offshore). We continue to maintain business interruption coverage for our onshore and offshore assets, except for those situations involving windstorm-related downtime for our offshore assets. After performing a cost-benefit analysis, management elected to forego windstorm coverage for our Gulf of Mexico offshore assets. The combination of increasingly high deductibles and premiums resulted in such coverage being uneconomic to us; therefore, we chose to self-insure such operations for the current annual policy period. Although the new EPCO policies do not provide any windstorm coverage for offshore assets, producers affiliated with our Independence Hub and Marco Polo platforms provide physical damage windstorm coverage of approximately $350.0 million for each of these key offshore assets. During the second quarter of 2012, we collected $27.7 million of nonrefundable cash proceeds from insurance carriers that we recognized as a gain. These proceeds relate to property damage claims we made in connection with the February 2011 NGL release and fire at the West Storage location of our Mont Belvieu, Texas underground storage facility. As additional non-refundable insurance proceeds continue to be received, we expect to record gains equal to such proceeds.

Condensed Consolidating Financial Information

6 Months Ended

Jun. 30, 2012

Condensed Consolidating Financial Information [Abstract]

Condensed Consolidating Financial Information

Note 17. 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 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 the remaining debt obligations of TEPPCO. 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. EPO's consolidated subsidiaries have no significant restrictions on their ability to pay distributions or make loans to Enterprise Products Partners L.P. See Note 9 for additional information regarding our consolidated debt obligations.

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Balance Sheet

June 30, 2012

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non-guarantor)		EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries		Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments			Consolidated Total
ASSETS
Current assets:
Cash and cash equivalents and restricted cash	$	28.1	$	34.3	$	(47.9	)	$	14.5	$	--		$	--		$	14.5
Accounts receivable - trade, net		1,151.8		2,579.7		(6.6	)		3,724.9		--			--			3,724.9
Accounts receivable - related parties		323.6		1,566.5		(1,871.6	)		18.5		(16.8	)		0.6			2.3
Inventories		766.4		127.6		(1.1	)		892.9		--			--			892.9
Prepaid and other current assets		181.9		267.4		(14.8	)		434.5		0.3			--			434.8
Total current assets		2,451.8		4,575.5		(1,942.0	)		5,085.3		(16.5	)		0.6			5,069.4
Property, plant and equipment, net		1,599.2		22,170.8		(9.4	)		23,760.6		--			--			23,760.6
Investments in unconsolidated affiliates		26,978.9		1,483.2		(27,548.9	)		913.2		12,382.7			(12,382.7	)		913.2
Intangible assets, net		155.2		1,477.1		(13.1	)		1,619.2		--			--			1,619.2
Goodwill		458.9		1,633.4		--			2,092.3		--			--			2,092.3
Other assets		125.3		87.8		(0.8	)		212.3		0.1			--			212.4
Total assets	$	31,769.3	$	31,427.8	$	(29,514.2	)	$	33,682.9	$	12,366.3		$	(12,382.1	)	$	33,667.1

LIABILITIES AND EQUITY
Current liabilities:
Current maturities of debt	$	1,670.1	$	29.9	$	--		$	1,700.0	$	--		$	--		$	1,700.0
Accounts payable - trade		245.1		565.4		(47.9	)		762.6		--			--			762.6
Accounts payable - related parties		1,778.4		158.0		(1,866.8	)		69.6		--			0.6			70.2
Accrued product payables		1,554.7		2,496.4		(11.4	)		4,039.7		--			--			4,039.7
Accrued interest		288.4		0.7		--			289.1		--			--			289.1
Other current liabilities		427.3		343.0		(13.7	)		756.6		--			0.1			756.7
Total current liabilities		5,964.0		3,593.4		(1,939.8	)		7,617.6		--			0.7			7,618.3
Long-term debt		13,331.8		14.9		--			13,346.7		--			--			13,346.7
Deferred tax liabilities		5.8		19.7		(0.8	)		24.7		--			(0.9	)		23.8
Other long-term liabilities		23.7		178.5		--			202.2		--			--			202.2
Commitments and contingencies
Equity:
Partners' and other owners' equity		12,444.0		27,544.1		(27,624.0	)		12,364.1		12,366.3			(12,364.1	)		12,366.3
Noncontrolling interests		--		77.2		50.4			127.6		--			(17.8	)		109.8
Total equity		12,444.0		27,621.3		(27,573.6	)		12,491.7		12,366.3			(12,381.9	)		12,476.1
Total liabilities and equity	$	31,769.3	$	31,427.8	$	(29,514.2	)	$	33,682.9	$	12,366.3		$	(12,382.1	)	$	33,667.1

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Balance Sheet

December 31, 2011

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non-guarantor)		EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries		Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments			Consolidated Total
ASSETS
Current assets:
Cash and cash equivalents and restricted cash	$	48.2	$	21.3	$	(11.2	)	$	58.3	$	--		$	--		$	58.3
Accounts receivable - trade, net		1,599.4		2,913.2		(10.8	)		4,501.8		--			--			4,501.8
Accounts receivable - related parties		141.1		2,155.5		(2,252.0	)		44.6		(1.1	)		--			43.5
Inventories		943.6		170.5		(2.4	)		1,111.7		--			--			1,111.7
Prepaid and other current assets		216.8		152.6		(16.0	)		353.4		--			--			353.4
Total current assets		2,949.1		5,413.1		(2,292.4	)		6,069.8		(1.1	)		--			6,068.7
Property, plant and equipment, net		1,477.5		20,723.7		(9.6	)		22,191.6		--			--			22,191.6
Investments in unconsolidated affiliates		27,060.0		8,266.7		(33,467.1	)		1,859.6		12,114.5			(12,114.5	)		1,859.6
Intangible assets, net		142.4		1,527.4		(13.6	)		1,656.2		--			--			1,656.2
Goodwill		458.9		1,633.4		--			2,092.3		--			--			2,092.3
Other assets		146.4		107.5		2.8			256.7		--			--			256.7
Total assets	$	32,234.3	$	37,671.8	$	(35,779.9	)	$	34,126.2	$	12,113.4		$	(12,114.5	)	$	34,125.1

LIABILITIES AND EQUITY
Current liabilities:
Current maturities of debt	$	500.0	$	--	$	--		$	500.0	$	--		$	--		$	500.0
Accounts payable - trade		205.6		578.6		(11.2	)		773.0		--			--			773.0
Accounts payable - related parties		2,407.2		71.9		(2,267.5	)		211.6		--			--			211.6
Accrued product payables		2,141.0		2,912.4		(6.3	)		5,047.1		--			--			5,047.1
Accrued interest		287.1		1.0		--			288.1		--			--			288.1
Other current liabilities		298.1		321.8		(7.4	)		612.5		--			0.1			612.6
Total current liabilities		5,839.0		3,885.7		(2,292.4	)		7,432.3		--			0.1			7,432.4
Long-term debt		13,975.1		54.3		--			14,029.4		--			--			14,029.4
Deferred tax liabilities		22.2		67.1		2.8			92.1		--			(0.9	)		91.2
Other long-term liabilities		155.3		197.5		--			352.8		--			--			352.8
Commitments and contingencies
Equity:
Partners' and other owners' equity		12,242.7		28,799.8		(28,946.4	)		12,096.1		12,113.4			(12,096.1	)		12,113.4
Noncontrolling interests		--		4,667.4		(4,543.9	)		123.5		--			(17.6	)		105.9
Total equity		12,242.7		33,467.2		(33,490.3	)		12,219.6		12,113.4			(12,113.7	)		12,219.3
Total liabilities and equity	$	32,234.3	$	37,671.8	$	(35,779.9	)	$	34,126.2	$	12,113.4		$	(12,114.5	)	$	34,125.1

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Statement of Operations

Three Months Ended June 30, 2012

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non-guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
Revenues	$	6,033.6		$	6,696.0		$	(2,939.8	)	$	9,789.8		$	--	$	--		$	9,789.8
Costs and expenses:
Operating costs and expenses		5,864.4			6,083.0			(2,937.9	)		9,009.5			--		--			9,009.5
General and administrative costs		9.1			32.6			--			41.7			0.8		--			42.5
Total costs and expenses		5,873.5			6,115.6			(2,937.9	)		9,051.2			0.8		--			9,052.0
Equity in income of unconsolidated affiliates		598.8			(51.0	)		(536.5	)		11.3			567.1		(567.1	)		11.3
Operating income		758.9			529.4			(538.4	)		749.9			566.3		(567.1	)		749.1
Other income (expense):
Interest expense		(185.7	)		(0.9	)		--			(186.6	)		--		--			(186.6	)
Other, net		--			13.2			--			13.2			--		--			13.2
Total other expense, net		(185.7	)		12.3			--			(173.4	)		--		--			(173.4	)
Income before income taxes		573.2			541.7			(538.4	)		576.5			566.3		(567.1	)		575.7
Provision for income taxes		(4.6	)		(3.7	)		--			(8.3	)		--		(0.2	)		(8.5	)
Net income		568.6			538.0			(538.4	)		568.2			566.3		(567.3	)		567.2
Net loss (income) attributable to noncontrolling interests		--			40.2			(41.7	)		(1.5	)		--		0.6			(0.9	)
Net income attributable to entity	$	568.6		$	578.2		$	(580.1	)	$	566.7		$	566.3	$	(566.7	)	$	566.3

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Statement of Operations

Three Months Ended June 30, 2011

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non-guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
Revenues	$	7,959.5		$	7,194.7		$	(3,937.7	)	$	11,216.5		$	--	$	--		$	11,216.5
Costs and expenses:
Operating costs and expenses		7,824.2			6,646.7			(3,937.6	)		10,533.3			--		--			10,533.3
General and administrative costs		3.4			43.8			--			47.2			3.2		--			50.4
Total costs and expenses		7,827.6			6,690.5			(3,937.6	)		10,580.5			3.2		--			10,583.7
Equity in income of unconsolidated affiliates		492.8			24.9			(506.6	)		11.1			436.9		(436.9	)		11.1
Operating income		624.7			529.1			(506.7	)		647.1			433.7		(436.9	)		643.9
Other income (expense):
Interest expense		(184.0	)		(6.2	)		1.9			(188.3	)		--		--			(188.3	)
Other, net		1.9			0.3			(1.9	)		0.3			--		--			0.3
Total other expense, net		(182.1	)		(5.9	)		--			(188.0	)		--		--			(188.0	)
Income before income taxes		442.6			523.2			(506.7	)		459.1			433.7		(436.9	)		455.9
Provision for income taxes		(5.7	)		(1.6	)		--			(7.3	)		--		(0.1	)		(7.4	)
Net income		436.9			521.6			(506.7	)		451.8			433.7		(437.0	)		448.5
Net loss (income) attributable to noncontrolling interests		--			(7.5	)		(7.5	)		(15.0	)		--		0.2			(14.8	)
Net income attributable to entity	$	436.9		$	514.1		$	(514.2	)	$	436.8		$	433.7	$	(436.8	)	$	433.7

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Statement of Operations

Six Months Ended June 30, 2012

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
Revenues	$	13,673.4		$	13,854.5		$	(6,485.6	)	$	21,042.3		$	--	$	--		$	21,042.3
Costs and expenses:
Operating costs and expenses		13,274.2			12,686.6			(6,484.1	)		19,476.7			--		--			19,476.7
General and administrative costs		24.5			63.3			--			87.8			1.0		--			88.8
Total costs and expenses		13,298.7			12,749.9			(6,484.1	)		19,564.5			1.0		--			19,565.5
Equity in income of unconsolidated affiliates		1,193.3			27.4			(1,199.5	)		21.2			1,218.6		(1,218.6	)		21.2
Operating income		1,568.0			1,132.0			(1,201.0	)		1,499.0			1,217.6		(1,218.6	)		1,498.0
Other income (expense):
Interest expense		(371.3	)		(1.8	)		--			(373.1	)		--		--			(373.1	)
Other, net		0.1			71.8			--			71.9			--		--			71.9
Total other expense, net		(371.2	)		70.0			--			(301.2	)		--		--			(301.2	)
Income before income taxes		1,196.8			1,202.0			(1,201.0	)		1,197.8			1,217.6		(1,218.6	)		1,196.8
Benefit from income taxes		22.4			3.7			--			26.1			--		(0.2	)		25.9
Net income		1,219.2			1,205.7			(1,201.0	)		1,223.9			1,217.6		(1,218.8	)		1,222.7
Net loss (income) attributable to noncontrolling interests		--			(4.2	)		(2.0	)		(6.2	)		--		1.1			(5.1	)
Net income attributable to entity	$	1,219.2		$	1,201.5		$	(1,203.0	)	$	1,217.7		$	1,217.6	$	(1,217.7	)	$	1,217.6

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Statement of Operations

Six Months Ended June 30, 2011

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
Revenues	$	16,284.3		$	13,273.4		$	(8,157.5	)	$	21,400.2		$	--	$	--		$	21,400.2
Costs and expenses:
Operating costs and expenses		16,002.4			12,225.3			(8,157.3	)		20,070.4			--		--			20,070.4
General and administrative costs		4.3			77.5			--			81.8			6.5		--			88.3
Total costs and expenses		16,006.7			12,302.8			(8,157.3	)		20,152.2			6.5		--			20,158.7
Equity in income of unconsolidated affiliates		950.8			56.7			(980.2	)		27.3			860.9		(860.9	)		27.3
Operating income		1,228.4			1,027.3			(980.4	)		1,275.3			854.4		(860.9	)		1,268.8
Other income (expense):
Interest expense		(363.0	)		(12.9	)		3.8			(372.1	)		--		--			(372.1	)
Other, net		3.9			0.7			(3.8	)		0.8			--		--			0.8
Total other expense, net		(359.1	)		(12.2	)		--			(371.3	)		--		--			(371.3	)
Income before income taxes		869.3			1,015.1			(980.4	)		904.0			854.4		(860.9	)		897.5
Provision for income taxes		(8.5	)		(5.9	)		--			(14.4	)		--		(0.1	)		(14.5	)
Net income		860.8			1,009.2			(980.4	)		889.6			854.4		(861.0	)		883.0
Net loss (income) attributable to noncontrolling interests		--			(10.9	)		(18.2	)		(29.1	)		--		0.5			(28.6	)
Net income attributable to entity	$	860.8		$	998.3		$	(998.6	)	$	860.5		$	854.4	$	(860.5	)	$	854.4

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Statement of Comprehensive Income

Three Months Ended June 30, 2012

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non- guarantor)		EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
Comprehensive income	$	503.8	$	625.9	$	(538.4	)	$	591.3		$	589.4	$	(590.4	)	$	590.3
Comprehensive income attributable to noncontrolling interests		--		40.2		(41.7	)		(1.5	)		--		0.6			(0.9	)
Comprehensive income attributable to entity	$	503.8	$	666.1	$	(580.1	)	$	589.8		$	589.4	$	(589.8	)	$	589.4

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Statement of Comprehensive Income

Three Months Ended June 30, 2011

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
Comprehensive income	$	382.1	$	570.3		$	(506.7	)	$	445.7		$	427.6	$	(430.9	)	$	442.4
Comprehensive income attributable to noncontrolling interests		--		(7.5	)		(7.5	)		(15.0	)		--		0.2			(14.8	)
Comprehensive income attributable to entity	$	382.1	$	562.8		$	(514.2	)	$	430.7		$	427.6	$	(430.7	)	$	427.6

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Statement of Comprehensive Income

Six Months Ended June 30, 2012

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
Comprehensive income	$	1,183.6	$	1,274.0		$	(1,201.0	)	$	1,256.6		$	1,250.3	$	(1,251.5	)	$	1,255.4
Comprehensive income attributable to noncontrolling interests		--		(4.2	)		(2.0	)		(6.2	)		--		1.1			(5.1	)
Comprehensive income attributable to entity	$	1,183.6	$	1,269.8		$	(1,203.0	)	$	1,250.4		$	1,250.3	$	(1,250.4	)	$	1,250.3

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Statement of Comprehensive Income

Six Months Ended June 30, 2011

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
Comprehensive income	$	817.2	$	979.1		$	(980.4	)	$	815.9		$	780.7	$	(787.3	)	$	809.3
Comprehensive income attributable to noncontrolling interests		--		(10.9	)		(18.2	)		(29.1	)		--		0.5			(28.6	)
Comprehensive income attributable to entity	$	817.2	$	968.2		$	(998.6	)	$	786.8		$	780.7	$	(786.8	)	$	780.7

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2012

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments			Consolidated Total
Operating activities:
Net income	$	1,219.2		$	1,205.7		$	(1,201.0	)	$	1,223.9		$	1,217.6		$	(1,218.8	)	$	1,222.7
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		66.4			472.0			(0.7	)		537.7			--			--			537.7
Equity in income of unconsolidated affiliates		(1,193.3	)		(27.4	)		1,199.5			(21.2	)		(1,218.6	)		1,218.6			(21.2	)
Distributions received from unconsolidated affiliates		1,589.2			40.0			(1,578.7	)		50.5			1,082.4			(1,082.4	)		50.5
Net effect of changes in operating accounts and other operating activities		(1,148.6	)		722.3			(34.5	)		(460.8	)		9.2			0.2			(451.4	)
Net cash flows provided by operating activities		532.9			2,412.6			(1,615.4	)		1,330.1			1,090.6			(1,082.4	)		1,338.3
Investing activities:
Capital expenditures, net of contributions in aid of construction costs		(83.5	)		(1,719.6	)		--			(1,803.1	)		--			--			(1,803.1	)
Proceeds from asset sales		1,104.8			24.2			--			1,129.0			--			--			1,129.0
Other investing activities		(961.9	)		(54.2	)		940.4			(75.7	)		(60.4	)		60.4			(75.7	)
Cash used in investing activities		59.4			(1,749.6	)		940.4			(749.8	)		(60.4	)		60.4			(749.8	)
Financing activities:
Borrowings under debt agreements		2,414.6			--			--			2,414.6			--			--			2,414.6
Repayments of debt		(1,881.5	)		(9.5	)		--			(1,891.0	)		--			--			(1,891.0	)
Cash distributions paid to partners		(1,082.4	)		(1,586.9	)		1,586.9			(1,082.4	)		(1,068.6	)		1,082.4			(1,068.6	)
Cash distributions paid to noncontrolling interests		--			--			(8.1	)		(8.1	)		--			--			(8.1	)
Cash contributions from noncontrolling interests		--			--			5.9			5.9			--			--			5.9
Net cash proceeds from issuance of common units		--			--			--			--			57.7			--			57.7
Cash contributions from owners		60.4			946.4			(946.4	)		60.4			--			(60.4	)		--
Other financing activities		(85.0	)		--			--			(85.0	)		(19.3	)		--			(104.3	)
Cash provided by (used in) financing activities		(573.9	)		(650.0	)		638.3			(585.6	)		(1,030.2	)		1,022.0			(593.8	)
Net change in cash and cash equivalents		18.4			13.0			(36.7	)		(5.3	)		--			--			(5.3	)
Cash and cash equivalents, January 1		9.7			21.3			(11.2	)		19.8			--			--			19.8
Cash and cash equivalents, June 30	$	28.1		$	34.3		$	(47.9	)	$	14.5		$	--		$	--		$	14.5

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2011

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments			Consolidated Total
Operating activities:
Net income	$	860.8		$	1,009.2		$	(980.4	)	$	889.6		$	854.4		$	(861.0	)	$	883.0
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		56.6			428.9			(0.7	)		484.8			--			--			484.8
Equity in income of unconsolidated affiliates		(950.8	)		(56.7	)		980.2			(27.3	)		(860.9	)		860.9			(27.3	)
Distributions received from unconsolidated affiliates		115.3			111.9			(142.4	)		84.8			979.8			(979.8	)		84.8
Net effect of changes in operating accounts and other operating activities		1,076.0			(383.2	)		(365.1	)		327.7			1.5			--			329.2
Net cash flows provided by operating activities		1,157.9			1,110.1			(508.4	)		1,759.6			974.8			(979.9	)		1,754.5
Investing activities:
Capital expenditures, net of contributions in aid of construction costs		(50.6	)		(1,659.2	)		--			(1,709.8	)		--			--			(1,709.8	)
Other investing activities		(466.5	)		231.9			452.2			217.6			(49.2	)		49.2			217.6
Cash used in investing activities		(517.1	)		(1,427.3	)		452.2			(1,492.2	)		(49.2	)		49.2			(1,492.2	)
Financing activities:
Borrowings under debt agreements		3,372.1			419.0			--			3,791.1			--			--			3,791.1
Repayments of debt		(2,976.0	)		(57.5	)		--			(3,033.5	)		--			--			(3,033.5	)
Cash distributions paid to partners		(979.8	)		(440.0	)		440.0			(979.8	)		(966.5	)		979.8			(966.5	)
Cash distributions paid to noncontrolling interests		--			(72.8	)		38.0			(34.8	)		--			--			(34.8	)
Cash contributions from noncontrolling interests		--			449.4			(446.6	)		2.8			--			(0.2	)		2.6
Net cash proceeds from issuance of common units		--			--			--			--			45.1			--			45.1
Cash contributions from owners		49.2			5.6			(5.6	)		49.2			--			(49.2	)		--
Other financing activities		(18.5	)		--			--			(18.5	)		(4.2	)		--			(22.7	)
Cash provided by (used in) financing activities		(553.0	)		303.7			25.8			(223.5	)		(925.6	)		930.4			(218.7	)
Net change in cash and cash equivalents		87.8			(13.5	)		(30.4	)		43.9			--			(0.3	)		43.6
Cash and cash equivalents, January 1		0.5			67.9			(2.9	)		65.5			--			--			65.5
Cash and cash equivalents, June 30	$	88.3		$	54.4		$	(33.3	)	$	109.4		$	--		$	(0.3	)	$	109.1

Subsequent Events	6 Months Ended
Subsequent Events	Jun. 30, 2012
Subsequent Events [Abstract]
Subsequent Events	Note 18. Subsequent Events August 2012 Senior Notes Offering On August 6, 2012, EPO agreed to issue $650 million in principal amount of 3-year unsecured Senior Notes FF at 99.941% of their principal amount and $1.1 billion in principal amount of 30-year unsecured Senior Notes GG at 99.470% of their principal amount. The transaction is scheduled to close on August 13, 2012. The Senior Notes FF to be issued upon closing will have a fixed interest rate of 1.25% and mature on August, 13, 2015, and the Senior Notes GG to be issued upon closing will have a fixed interest rate of 4.45% and mature on February 15, 2043. Enterprise has agreed to guarantee both such series of notes through an unconditional guarantee on an unsecured and unsubordinated basis. EPO expects to use net proceeds from the issuance of such notes to temporarily reduce borrowings under its $3.5 Billion Multi-Year Revolving Credit Facility (which was used to repay amounts due upon the maturity of its $500.0 million principal amount of Senior Notes P on August 1, 2012) and for general company purposes. Senior Notes FF and Senior Notes GG will rank equal with EPO's existing and future unsecured and unsubordinated indebtedness. They will be senior to any existing and future subordinated indebtedness of EPO. Senior Notes FF and Senior Notes GG will be subject to make-whole redemption rights and will be issued under an indenture containing certain covenants, which generally restrict EPO's ability, with certain exceptions, to incur debt secured by liens and engage in sale and leaseback transactions. Commercial Paper Program On August 8, 2012, EPO established a commercial paper program, under which EPO may issue up to $2.0 billion of short-term commercial paper notes outstanding at any time. The commercial paper notes will be senior unsecured obligations of EPO that are unconditionally guaranteed by Enterprise. We intend to use the net proceeds from the sale of the commercial paper notes for general company purposes. The commercial paper program is fully backed by EPO's existing $3.5 Billion Multi-Year Revolving Credit Facility. As of the filing date of this quarterly report, EPO has not issued any commercial paper notes pursuant to this program.

General Accounting Matters (Policies)	6 Months Ended
General Accounting Matters (Policies)	Jun. 30, 2012
General Accounting Matters [Abstract]
Contingencies	Contingencies Certain conditions may exist as of the date our consolidated financial statements are issued, which may result in a loss to us but which will only be resolved when one or more future events occur or fail to occur. Management has regular quarterly litigation reviews, including updates from legal counsel, to assess the need for accounting recognition or disclosure of these contingencies, and such assessment inherently involves an exercise in judgment. In assessing loss contingencies related to legal proceedings that are pending against us or unasserted claims that may result in such proceedings, our management and legal counsel evaluate the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein. We accrue an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when it is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material, we disclose the nature of the contingency and, if feasible, an estimate of the possible loss or range of loss. Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed. See Note 14 for additional information regarding our contingencies.
Derivative Instruments	Derivative Instruments We use derivative instruments such as futures, swaps, options, forward contracts and other arrangements to manage price risks associated with inventories, firm commitments, interest rates, foreign currencies and certain anticipated future transactions. To qualify for hedge accounting, the hedged item must expose us to risk and the related derivative instrument must reduce that exposure and meet specific hedge documentation requirements related to designation dates, expectations for hedge effectiveness and the probability that hedged future transactions will occur as forecasted. We formally designate derivative instruments as hedges and document and assess their effectiveness at inception of the hedge and on a monthly or quarterly basis thereafter. Forecasted transactions are evaluated for the probability of occurrence and are periodically back-tested once the forecasted period has passed to determine whether similarly forecasted transactions are probable of occurring in the future. For certain of our physical forward commodity derivative contracts, we apply the normal purchase/normal sale exception, whereby changes in the mark-to-market values of such contracts are not recognized in income. As a result, the revenues and expenses associated with such physical contract transactions are recognized during the period when volumes are physically delivered or received. Physical forward commodity contracts are evaluated for the probability of future delivery and are periodically back-tested once the forecasted period has passed to determine whether similar forward contracts are probable of physically delivering in the future. See Note 4 for additional information regarding our derivative instruments and related interest rate and commodity hedging activities.
Estimates	Estimates Preparing our consolidated financial statements in conformity with GAAP requires us to make estimates that affect amounts presented in the financial statements. Our most significant estimates relate to (i) the useful lives and depreciation/amortization methods used for fixed and identifiable intangible assets; (ii) measurement of fair value and projections used in impairment testing of fixed and intangible assets (including goodwill); (iii) contingencies; and (iv) revenue and expense accruals. Actual results could differ materially from our estimates. On an ongoing basis, we review our estimates based on currently available information. Any changes in the facts and circumstances underlying our estimates may require us to update such estimates, which could have a material impact on our consolidated financial statements.

Disclosure of accounting policy for commitments and contingencies, which may include policies for recognizing and measuring loss and gain contingencies.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Publisher AICPA
-Name Audit and Accounting Guide (AAG)
-Number AAG-HCO
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-Name Statement of Financial Accounting Standard (FAS)
-Number 5
-Paragraph 26
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-Name Statement of Financial Accounting Standard (FAS)
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Disclosure of accounting policy for its derivative instruments and hedging activities.

General Accounting Matters [Abstract]

General Accounting Matters (Tables)

6 Months Ended

Jun. 30, 2012

Schedule of Other Nonoperating Income

The following table presents the components of "Other, net" income for the periods presented:

	For the Three Months					For the Six Months
	Ended June 30,					Ended June 30,
	2012			2011		2012			2011
Gain on sales of Energy Transfer Equity common units (1)	$	15.5		$	--	$	68.8		$	--
Distribution income from Energy Transfer Equity		--			--		4.1			--
Other		(2.4	)		--		(1.4	)		0.2
Total	$	13.1		$	--	$	71.5		$	0.2

(1) See Note 7 for information regarding our previously held investment in Energy Transfer Equity.

Equity-based Awards (Tables)

6 Months Ended

Jun. 30, 2012

Equity-based Awards [Abstract]

Equity-based Award Expense

	For the Three Months				For the Six Months
	Ended June 30,				Ended June 30,
	2012		2011		2012		2011
Restricted common unit awards	$	15.7	$	12.1	$	30.5	$	23.5
Unit option awards		0.3		0.8		1.0		1.7
Other (1)		0.5		0.3		1.4		(0.2	)
Total compensation expense	$	16.5	$	13.2	$	32.9	$	25.0

(1) Primarily consists of unit appreciation rights ("UARs"), phantom units and similar awards.

Restricted Common Unit Awards

The following table presents information regarding restricted common unit awards for the period presented:

	Number of Units			Weighted- Average Grant Date Fair Value per Unit (1)
Restricted common units at December 31, 2011		3,868,216		$	34.22
Granted (2,3)		1,538,438		$	51.92
Vested (3)		(1,236,352	)	$	34.77
Forfeited		(95,575	)	$	38.43
Restricted common units at June 30, 2012		4,074,727		$	40.64

(1) Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued. (2) The aggregate grant date fair value of restricted common unit awards issued in 2012 was $79.9 million based on a grant date market price ranging from $51.92 to $52.26 per unit. An estimated annual forfeiture rate of 3.25% was applied to these awards. (3) Includes awards granted to the independent directors of the board of directors of Enterprise GP as part of their annual compensation for 2012. A total of 10,038 restricted common units were issued in February 2012 to the independent directors of Enterprise GP that immediately vested upon issuance.

Cash Distributions and Total Intrinsic Value of Restricted Common Units

The following table presents supplemental information regarding our restricted common unit awards for the periods presented:

	For the Three Months				For the Six Months
	Ended June 30,				Ended June 30,
	2012		2011		2012		2011
Cash distributions paid to restricted common unit holders	$	3.0	$	2.7	$	5.4	$	4.8
Total intrinsic value of our restricted common unit awards vesting during period		30.1		20.5		62.7		35.2

Unit Option Activity

	Number of Units			Weighted- Average Strike Price (dollars/unit)		Weighted- Average Remaining Contractual Term (in years)		Aggregate Intrinsic Value (1)
Unit options at December 31, 2011		3,753,420		$	28.08		2.6	$	11.1
Exercised		(712,280	)	$	30.76
Forfeited		(130,000	)	$	27.12
Unit options at June 30, 2012		2,911,140		$	27.46		2.5	$	14.4
Options exercisable at June 30, 2012		--					--		--

(1) Aggregate intrinsic value reflects fully vested unit options at the date indicated.

Supplemental Information Regarding Unit Options

The following table presents supplemental information regarding our unit options during the periods presented:

	For the Three Months				For the Six Months
	Ended June 30,				Ended June 30,
	2012		2011		2012		2011
Total intrinsic value of unit option awards exercised during period	$	--	$	--	$	14.0	$	--
Cash received from EPCO in connection with the exercise of unit option awards		--		--		10.2		--
Unit option-related reimbursements to EPCO		--		--		14.0		--

Tabular disclosure of the allocation of equity-based compensation costs to a given line item on the balance sheet and income statement for the period. This may include the reporting line for the costs and the amount capitalized and expensed.

Derivative Instruments, Hedging Activities and Fair Value Measurements [Abstract]

Derivative Instruments, Hedging Activities and Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2012

Hedging Instruments Under the FASB's Derivative and Hedging Guidance

Hedged Transaction	Number and Type of Derivatives Outstanding	Notional Amount	Period of Hedge	Rate Swap	Accounting Treatment
Senior Notes AA	10 fixed-to-floating swaps	$750.0	1/2011 to 2/2016	3.2% to 1.5%	Fair value hedge
Undesignated swaps	6 floating-to-fixed swaps	$600.0	5/2010 to 7/2014	0.5% to 2.0%	Mark-to-market

Hedged Transaction	Number and Type of Derivatives Outstanding	Notional Amount	Expected Termination Date	Average Rate Locked	Accounting Treatment
Future debt offering	7 forward starting swaps	$350.0	8/2012	3.7%	Cash flow hedge
Future debt offering	16 forward starting swaps	$1,000.0	3/2013	3.7%	Cash flow hedge

	Volume (1)		Accounting
Derivative Purpose	Current (2)	Long-Term (2)	Treatment
Derivatives designated as hedging instruments:
Natural gas processing:
Forecasted natural gas purchases for plant thermal reduction ("PTR") (3)	15.3 Bcf	n/a	Cash flow hedge
Forecasted sales of NGLs (4)	1.6 MMBbls	n/a	Cash flow hedge
Octane enhancement:
Forecasted purchases of NGLs	0.2 MMBbls	n/a	Cash flow hedge
Forecasted sales of octane enhancement products	2.0 MMBbls	n/a	Cash flow hedge
Natural gas marketing:
Forecasted sales of natural gas	1.2 Bcf	n/a	Cash flow hedge
Natural gas storage inventory management activities (Bcf)	11.1 Bcf	n/a	Fair value hedge
NGL marketing:
Forecasted purchases of NGLs and related hydrocarbon products	3.2 MMBbls	0.5 MMBbls	Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products	3.7 MMBbls	0.5 MMBbls	Cash flow hedge
Refined products marketing:
Forecasted purchases of refined products	0.1 MMBbls	n/a	Cash flow hedge
Forecasted sales of refined products	0.5 MMBbls	n/a	Cash flow hedge
Refined products inventory management activities	0.2 MMBbls	n/a	Fair value hedge
Crude oil marketing:
Forecasted purchases of crude oil	2.8 MMBbls	n/a	Cash flow hedge
Forecasted sales of crude oil	4.1 MMBbls	n/a	Cash flow hedge
Derivatives not designated as hedging instruments:
Natural gas risk management activities (5,6)	241.0 Bcf	56.0 Bcf	Mark-to-market
Refined products risk management activities (6)	1.1 MMBbls	n/a	Mark-to-market
Crude oil risk management activities (6)	5.7 MMBbls	n/a	Mark-to-market
(1) Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes. (2) The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is December 2013, March 2013 and October 2015, respectively. (3) PTR represents the British thermal unit ("Btu") equivalent of the NGLs extracted from natural gas by a processing plant, and includes the natural gas used as plant fuel to extract those liquids, plant flare and other shortages. (4) Forecasted sales of NGL volumes under natural gas processing exclude 2.2 MMBbls of additional hedges executed under contracts that have been designated as normal sales agreements. (5) Current volumes include approximately 62.5 Bcf of physical derivative instruments that are predominantly priced at an index plus a premium or minus a discount related to location differences. (6) Reflects the use of derivative instruments to manage risks associated with transportation, processing and storage assets.

Derivative Assets and Liabilities Balance Sheet

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

	Asset Derivatives						Liability Derivatives
	June 30, 2012			December 31, 2011			June 30, 2012			December 31, 2011
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments
Interest rate derivatives	Other current assets	$	18.6	Other current assets	$	43.7	Other current liabilities	$	230.6	Other current liabilities	$	163.6
Interest rate derivatives	Other assets		26.6	Other assets		44.2	Other liabilities		--	Other liabilities		127.1
Total interest rate derivatives			45.2			87.9			230.6			290.7
Commodity derivatives	Other current assets		127.4	Other current assets		20.3	Other current liabilities		74.6	Other current liabilities		30.3
Commodity derivatives	Other assets		4.8	Other assets		--	Other liabilities		2.1	Other liabilities		0.2
Total commodity derivatives (1)			132.2			20.3			76.7			30.5
Total derivatives designated as hedging instruments		$	177.4		$	108.2		$	307.3		$	321.2

Derivatives not designated as hedging instruments
Interest rate derivatives	Other current assets	$	--	Other current assets	$	--	Other current liabilities	$	11.0	Other current liabilities	$	10.1
Interest rate derivatives	Other assets		--	Other assets		--	Other liabilities		8.6	Other liabilities		10.6
Total interest rate derivatives			--			--			19.6			20.7
Commodity derivatives	Other current assets		26.0	Other current assets		34.4	Other current liabilities		19.4	Other current liabilities		32.5
Commodity derivatives	Other assets		4.4	Other assets		12.6	Other liabilities		1.8	Other liabilities		2.0
Total commodity derivatives			30.4			47.0			21.2			34.5
Total derivatives not designated as hedging instruments		$	30.4		$	47.0		$	40.8		$	55.2

(1) Represents commodity derivative instrument transactions that have either not settled or have settled and cash has not been paid or received. Settled and unpaid or unreceived amounts are reflected in either accounts receivable or accounts payable depending on the outcome of the transaction.

Derivative Instruments Effects on Statements of Operations

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

Derivatives in Fair Value Hedging Relationships	Location	Gain/(Loss) Recognized in Income on Derivative
		For the Three Months						For the Six Months
		Ended June 30,						Ended June 30,
		2012			2011			2012			2011
Interest rate derivatives	Interest expense	$	4.6		$	21.1		$	3.1		$	8.8
Commodity derivatives	Revenue		(16.4	)		(1.6	)		(15.7	)		(1.3	)
Total		$	(11.8	)	$	19.5		$	(12.6	)	$	7.5

Derivatives in Fair Value Hedging Relationships	Location	Gain/(Loss) Recognized in Income on Hedged Item
		For the Three Months						For the Six Months
		Ended June 30,						Ended June 30,
		2012			2011			2012			2011
Interest rate derivatives	Interest expense	$	(4.5	)	$	(21.0	)	$	(3.4	)	$	(9.7	)
Commodity derivatives	Revenue		15.9			0.2			16.3			(1.1	)
Total		$	11.4		$	(20.8	)	$	12.9		$	(10.8	)

Derivatives in Cash Flow Hedging Relationships	Change in Value Recognized in Other Comprehensive Income/(Loss) on Derivative (Effective Portion)
	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2012			2011			2012			2011
Interest rate derivatives	$	(84.0	)	$	(60.1	)	$	(55.1	)	$	(46.0	)
Commodity derivatives - Revenue		99.8			(19.4	)		60.2			(174.8	)
Commodity derivatives - Operating costs and expenses		5.2			(2.3	)		(14.8	)		1.7
Total	$	21.0		$	(81.8	)	$	(9.7	)	$	(219.1	)

Derivatives in Cash Flow Hedging Relationships	Location	Gain/(Loss) Reclassified from Accumulated Other Comprehensive Income/(Loss) to Income (Effective Portion)
		For the Three Months						For the Six Months
		Ended June 30,						Ended June 30,
		2012			2011			2012			2011
Interest rate derivatives	Interest expense	$	(3.7	)	$	(1.5	)	$	(6.4	)	$	(3.0	)
Commodity derivatives	Revenue		(2.6	)		(79.3	)		(12.6	)		(148.5	)
Commodity derivatives	Operating costs and expenses		(11.6	)		4.5			(23.6	)		4.8
Total		$	(17.9	)	$	(76.3	)	$	(42.6	)	$	(146.7	)

Derivatives in Cash Flow Hedging Relationships	Location	Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)
		For the Three Months				For the Six Months
		Ended June 30,				Ended June 30,
		2012		2011		2012		2011
Commodity derivatives	Revenue	$	0.9	$	0.3	$	0.9	$	0.2
Commodity derivatives	Operating costs and expenses		--		--		0.3		--
Total		$	0.9	$	0.3	$	1.2	$	0.2

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

Derivatives Not Designated as Hedging Instruments	Location	Gain/(Loss) Recognized in Income on Derivative
		For the Three Months						For the Six Months
		Ended June 30,						Ended June 30,
		2012			2011			2012			2011
Interest rate derivatives	Interest expense	$	(1.1	)	$	(11.9	)	$	(3.3	)	$	(10.5	)
Commodity derivatives	Revenue		9.3			9.5			30.1			13.3
Commodity derivatives	Operating costs and expenses		--			--			(2.8	)		--
Total		$	8.2		$	(2.4	)	$	24.0		$	2.8

Derivative Instruments Effects on Statements of Comprehensive Income

Derivatives in Cash Flow Hedging Relationships	Change in Value Recognized in Other Comprehensive Income/(Loss) on Derivative (Effective Portion)
	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2012			2011			2012			2011
Interest rate derivatives	$	(84.0	)	$	(60.1	)	$	(55.1	)	$	(46.0	)
Commodity derivatives - Revenue		99.8			(19.4	)		60.2			(174.8	)
Commodity derivatives - Operating costs and expenses		5.2			(2.3	)		(14.8	)		1.7
Total	$	21.0		$	(81.8	)	$	(9.7	)	$	(219.1	)

Gain/(Loss) Reclassified from Accumulated Other Comprehensive Income/(Loss) to Income (Effective Portion)

Derivatives in Cash Flow Hedging Relationships	Location	Gain/(Loss) Reclassified from Accumulated Other Comprehensive Income/(Loss) to Income (Effective Portion)
		For the Three Months						For the Six Months
		Ended June 30,						Ended June 30,
		2012			2011			2012			2011
Interest rate derivatives	Interest expense	$	(3.7	)	$	(1.5	)	$	(6.4	)	$	(3.0	)
Commodity derivatives	Revenue		(2.6	)		(79.3	)		(12.6	)		(148.5	)
Commodity derivatives	Operating costs and expenses		(11.6	)		4.5			(23.6	)		4.8
Total		$	(17.9	)	$	(76.3	)	$	(42.6	)	$	(146.7	)

Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)

Derivatives in Cash Flow Hedging Relationships	Location	Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)
		For the Three Months				For the Six Months
		Ended June 30,				Ended June 30,
		2012		2011		2012		2011
Commodity derivatives	Revenue	$	0.9	$	0.3	$	0.9	$	0.2
Commodity derivatives	Operating costs and expenses		--		--		0.3		--
Total		$	0.9	$	0.3	$	1.2	$	0.2

Fair Value Measurements of Financial Assets and Liabilities

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

Derivatives Not Designated as Hedging Instruments	Location	Gain/(Loss) Recognized in Income on Derivative
		For the Three Months						For the Six Months
		Ended June 30,						Ended June 30,
		2012			2011			2012			2011
Interest rate derivatives	Interest expense	$	(1.1	)	$	(11.9	)	$	(3.3	)	$	(10.5	)
Commodity derivatives	Revenue		9.3			9.5			30.1			13.3
Commodity derivatives	Operating costs and expenses		--			--			(2.8	)		--
Total		$	8.2		$	(2.4	)	$	24.0		$	2.8

	Fair Value Measurements Using
	Quoted Prices
	in Active
	Markets for		Significant		Significant		Carrying
	Identical Assets		Observable		Unobservable		Value
	and Liabilities		Inputs		Inputs		at June 30,
	(Level 1)		(Level 2)		(Level 3)		2012
Financial assets:
Interest rate derivatives	$	--	$	45.2	$	--	$	45.2
Commodity derivatives		81.6		73.1		7.9		162.6
Total	$	81.6	$	118.3	$	7.9	$	207.8

Financial liabilities:
Interest rate derivatives	$	--	$	250.2	$	--	$	250.2
Commodity derivatives		39.1		55.8		3.0		97.9
Total	$	39.1	$	306.0	$	3.0	$	348.1

Reconciliation of Changes in the Fair Value of Level 3 Financial Assets and Liabilities

The following table sets forth a reconciliation of changes in the overall fair values of our recurring Level 3 financial assets and liabilities for the periods presented:

		For the Six Months
		Ended June 30,
	Location	2012			2011
Balance, January 1		$	0.4		$	(25.9	)
Total gains (losses) included in:
Net income (1)	Revenue		0.5			(0.5	)
Other comprehensive income (loss)	Commodity derivative instruments - changes in fair value of cash flow hedges		0.5			16.2
Settlements			(0.5	)		0.8
Transfers out of Level 3 (2)			--			9.8
Balance, March 31			0.9			0.4
Total gains (losses) included in:
Net income (1)	Revenue		(1.3	)		1.9
Other comprehensive income (loss)	Commodity derivative instruments - changes in fair value of cash flow hedges		6.0			--
Settlements			(0.7	)		(0.2	)
Balance, June 30		$	4.9		$	2.1

(1) There were $2.0 million and $1.9 million of unrealized losses included in these amounts for the three and six months ended June 30, 2012, respectively. There were $2.0 million and $1.8 million of unrealized gains included in these amounts for the three and six months ended June 30, 2011, respectively. (2) Transfers out of Level 3 into Level 2 during 2011 were primarily due to the change in observability of forward NGL prices.

Nonrecurring fair value measurements

The following table provides quantitative information about our recurring Level 3 fair value measurements at June 30, 2012:

	Fair Value
	Financial Assets		Financial Liabilities		Valuation Techniques	Unobservable Input	Range
Commodity derivatives - Propane	$	4.7	$	0.9	Discounted cash flow	Forward commodity price	$0.86-$0.92 /gallon
Commodity derivatives - Natural gasoline		2.7		--	Discounted cash flow	Forward commodity price	$1.83-$1.83 /gallon
Commodity derivatives - Crude oil		0.3		2.0	Discounted cash flow	Forward commodity price	$84.96-$88.71 /barrel
Commodity derivatives - Natural gas		0.2		0.1	Discounted cash flow	Forward commodity price	$3.90-$4.13 /million Btu
Total	$	7.9	$	3.0

	Fair Value Measurements Using								Total
									Non-Cash Asset
	Quoted Prices								Impairment
	in Active		Significant		Significant		Carrying		Charges for the
	Markets for		Observable		Unobservable		Value at		Six Months
	Identical Assets		Inputs		Inputs		June 30,		Ended
	(Level 1)		(Level 2)		(Level 3)		2012		June 30, 2012
NGL Pipelines & Services
Property, plant and equipment, net	$	--	$	--	$	--	$	--	$	8.0
Onshore Crude Oil Pipelines & Services
Property, plant and equipment, net		--		--		--		--		6.2
Petrochemical & Refined Products Services
Long-lived fixed assets held for sale		--		--		0.5		0.5		0.3
Total	$	--	$	--	$	0.5	$	0.5	$	14.5

Inventories (Tables)

6 Months Ended

Jun. 30, 2012

Inventories [Abstract]

Inventory Amounts by Product Type

Our inventory amounts by product type were as follows at the dates indicated:

Available-for-Sale Inventory by Product Type	June 30, 2012		December 31, 2011
NGLs	$	553.4	$	563.6
Petrochemicals and refined products		246.1		443.4
Crude oil		46.5		39.2
Natural gas		46.9		65.5
Total	$	892.9	$	1,111.7

Cost of Sales and Lower of Cost or Market Adjustments

The following table presents our total cost of sales amounts and lower of cost or market adjustments for the periods indicated:

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2012		2011		2012		2011
Cost of sales (1)	$	8,195.2	$	9,790.3	$	17,861.0	$	18,609.6
Lower of cost or market adjustments		8.0		0.5		13.9		1.7
(1) Cost of sales is a component of "Operating costs and expenses," as presented on our Unaudited Condensed Statements of Consolidated Operations. Period-to-period fluctuations in these amounts are primarily due to changes in energy commodity prices and sales volumes associated with our marketing activities.

Property, Plant and Equipment (Tables)

6 Months Ended

Jun. 30, 2012

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment and Accumulated Depreciation

The historical costs of our property, plant and equipment and related accumulated depreciation balances were as follows at the dates indicated:

	Estimated Useful Life in Years	June 30, 2012		December 31, 2011
Plants, pipelines and facilities (1)	3-45 (6)	$	24,105.7	$	22,354.4
Underground and other storage facilities (2)	5-40 (7)		1,455.9		1,388.6
Platforms and facilities (3)	20-31		637.5		637.5
Transportation equipment (4)	3-10		158.4		151.5
Marine vessels (5)	15-30		660.3		615.9
Land			141.7		136.1
Construction in progress			2,275.7		2,145.6
Total			29,435.2		27,429.6
Less accumulated depreciation			5,674.6		5,238.0
Property, plant and equipment, net		$	23,760.6	$	22,191.6

(1) Plants and pipelines include processing plants; NGL, natural gas, crude oil and petrochemical and refined products 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 located in the Gulf of Mexico. (4) Transportation equipment includes tractor-trailer tank trucks and other vehicles and similar assets used in our operations. (5) Marine vessels include tow boats, barges and related equipment used in our marine transportation business. (6) In general, the estimated useful lives of major assets within this category are: processing plants, 20-35 years; pipelines and related equipment, 5-45 years; terminal facilities, 10-35 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 assets within this category are: underground storage facilities, 5-35 years; storage tanks, 10-40 years; and water wells, 5-35 years.

Depreciation Expense and Capitalized Interest

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

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2012		2011		2012		2011
Depreciation expense (1)	$	222.0	$	189.8	$	434.0	$	376.3
Capitalized interest (2)		29.5		24.8		60.1		42.0
(1) Depreciation expense is a component of "Costs and expenses" as presented on our Unaudited Condensed Statements of Consolidated Operations. (2) We capitalize interest cost incurred on funds used to construct property, plant and equipment. The capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset's estimated useful life as a component of depreciation expense. Capitalized interest reduces interest expense during the period it is recorded.

AROs

The following table summarizes changes in our ARO liability balance during the six months ended June 30, 2012:

ARO liability balance, December 31, 2011	$	112.0
Liabilities incurred during period		1.1
Liabilities settled during period		(5.9	)
Revisions in estimated cash flows		8.9
Accretion expense		2.7
ARO liability balance, June 30, 2012	$	118.8

Forecasted Accretion Expense Associated with AROs

The following table presents our forecast of accretion expense for the periods indicated:

Remainder of 2012				2013				2014				2015				2016
$	2.8			$	6.0			$	6.5			$	6.2			$	6.5

Investments in Unconsolidated Affiliates (Tables)

6 Months Ended

Jun. 30, 2012

Investments in Unconsolidated Affiliates [Abstract]

Investments in Unconsolidated Affiliates

The following table presents our investments in unconsolidated affiliates by business segment at the dates indicated. Unless noted otherwise, we account for these investments using the equity method.

	Ownership Interest at June 30, 2012	June 30, 2012		December 31, 2011
NGL Pipelines & Services:
Venice Energy Service Company, L.L.C.	13.1%	$	31.1	$	35.5
K/D/S Promix, L.L.C.	50%		40.9		40.7
Baton Rouge Fractionators LLC	32.2%		20.6		21.0
Skelly-Belvieu Pipeline Company, L.L.C.	50%		37.4		35.0
Texas Express Pipeline LLC ("Texas Express")	35%		39.2		13.9
Texas Express Gathering LLC ("TEG") (1)	45%		8.9		--
Front Range Pipeline LLC ("Front Range")	33.3%		6.3		--
Onshore Natural Gas Pipelines & Services:
Evangeline (2)	--		--		4.4
White River Hub, LLC	50%		25.5		25.7
Onshore Crude Oil Pipelines & Services:
Seaway Crude Pipeline LLC	50%		179.2		170.7
Offshore Pipelines & Services:
Poseidon Oil Pipeline Company, L.L.C. ("Poseidon")	36%		50.6		55.4
Cameron Highway Oil Pipeline Company	50%		218.2		222.8
Deepwater Gateway, L.L.C.	50%		93.7		94.6
Neptune Pipeline Company, L.L.C.	25.7		48.3		51.1
Southeast Keathley Canyon Pipeline Company L.L.C.	50%		51.7		1.0
Petrochemical & Refined Products Services:
Baton Rouge Propylene Concentrator, LLC	30%		8.9		9.5
Centennial Pipeline LLC ("Centennial")	50%		49.4		51.8
Other (3)	Various		3.3		3.4
Other Investments:
Energy Transfer Equity (4)	--		--		1,023.1
Total		$	913.2	$	1,859.6

(1) In April 2012, we, along with Enbridge Midcoast Energy, LP ("Enbridge") and WGR Asset Holding Company LLC formed a new joint venture, TEG, to design and construct two gas gathering systems to complement the Texas Express Pipeline. Enbridge will construct and operate the systems, which are expected to begin service in the second quarter of 2013. (2) In June 2012, we acquired the remaining ownership interests in Evangeline and it became a wholly owned subsidiary of ours. (3) 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. (4) We ceased using the equity method to account for our investment in Energy Transfer Equity limited partner units effective January 18, 2012 and began accounting for them as available-for-sale securities. We completed the sale of the remaining Energy Transfer Equity units in April 2012 (see below).

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

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2012			2011			2012			2011
NGL Pipelines & Services	$	3.8		$	6.2		$	9.0		$	12.1
Onshore Natural Gas Pipelines & Services		1.2			1.5			2.6			2.7
Onshore Crude Oil Pipelines & Services		3.6			(1.6	)		4.1			(2.1	)
Offshore Pipelines & Services		4.1			6.6			11.0			14.9
Petrochemical & Refined Products Services		(1.4	)		(4.3	)		(7.9	)		(9.3	)
Other Investments (1)		--			2.7			2.4			9.0
Total	$	11.3		$	11.1		$	21.2		$	27.3

(1) With respect to the six months ended June 30, 2012, the amount presented reflects our equity in the income of Energy Transfer Equity from January 1, 2012 to January 18, 2012.

The following table presents unamortized excess cost amounts by business segment at the dates indicated:

	June 30, 2012		December 31, 2011
NGL Pipelines & Services	$	24.2	$	24.7
Onshore Crude Oil Pipelines & Services		18.9		19.2
Offshore Pipelines & Services		14.2		14.8
Petrochemical & Refined Products Services		2.8		2.9
Other Investments (1)		--		1,119.0
Total	$	60.1	$	1,180.6

(1) On January 18, 2012, we discontinued using the equity method to account for our investment in Energy Transfer Equity common units and began accounting for this investment as an available-for-sale security. As a result, we no longer recognized any excess cost amounts associated with this investment.

The following table presents our amortization of excess cost amounts by business segment for the periods presented:

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2012		2011		2012		2011
NGL Pipelines & Services	$	0.3	$	0.2	$	0.5	$	0.5
Onshore Crude Oil Pipelines & Services		0.1		0.2		0.3		0.4
Offshore Pipelines & Services		0.3		0.3		0.6		0.6
Petrochemical & Refined Products Services		--		--		0.1		--
Other Investments (1)		--		8.4		0.3		17.5
Total	$	0.7	$	9.1	$	1.8	$	19.0

(1) Reflects amortization of excess cost amounts related to our investment in Energy Transfer Equity from January 1, 2012 through January 18, 2012, which is the date we ceased using the equity method to account for this investment.

	Summarized Income Statement Information for the Three Months Ended
	June 30, 2012								June 30, 2011
	Revenues		Operating Income (Loss)			Net Income (Loss)			Revenues		Operating Income (Loss)			Net Income (Loss)
NGL Pipelines & Services	$	71.5	$	15.3		$	15.2		$	116.4	$	30.5		$	30.6
Onshore Natural Gas Pipelines & Services		2.9		1.9			1.9			54.7		2.7			2.7
Onshore Crude Oil Pipelines & Services		21.5		7.4			7.3			9.6		(2.1	)		(2.1	)
Offshore Pipelines & Services		39.1		12.8			12.5			43.7		17.7			17.5
Petrochemical & Refined Products Services		5.9		(0.3	)		(2.4	)		9.2		(5.4	)		(7.6	)
Other Investments		--		--			--			1,974.9		260.6			66.3

	Summarized Income Statement Information for the Six Months Ended
	June 30, 2012								June 30, 2011
	Revenues		Operating Income (Loss)			Net Income (Loss)			Revenues		Operating Income			Net Income (Loss)
NGL Pipelines & Services	$	182.4	$	42.3		$	42.2		$	216.5	$	53.9		$	54.0
Onshore Natural Gas Pipelines & Services		5.7		3.7			3.7			90.2		5.3			5.3
Onshore Crude Oil Pipelines & Services		33.8		8.2			8.1			20.8		(1.6	)		(1.6	)
Offshore Pipelines & Services		80.2		31.9			30.9			90.0		36.6			36.2
Petrochemical & Refined Products Services		11.3		(9.7	)		(13.8	)		19.3		(12.4	)		(16.8	)
Other Investments		--		--			--			3,964.0		624.8			154.9

Intangible Assets and Goodwill (Tables)

6 Months Ended

Jun. 30, 2012

Intangible Assets and Goodwill [Abstract]

Intangible Assets by Segment

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

	June 30, 2012							December 31, 2011
	Gross Value		Accum. Amort.			Carrying Value		Gross Value		Accum. Amort.			Carrying Value
NGL Pipelines & Services:
Customer relationship intangibles	$	340.8	$	(138.0	)	$	202.8	$	340.8	$	(128.2	)	$	212.6
Contract-based intangibles		284.7		(147.1	)		137.6		298.4		(169.7	)		128.7
Segment total		625.5		(285.1	)		340.4		639.2		(297.9	)		341.3
Onshore Natural Gas Pipelines & Services:
Customer relationship intangibles		1,163.6		(230.5	)		933.1		1,163.6		(209.7	)		953.9
Contract-based intangibles		468.3		(301.7	)		166.6		464.8		(290.9	)		173.9
Segment total		1,631.9		(532.2	)		1,099.7		1,628.4		(500.6	)		1,127.8
Onshore Crude Oil Pipelines & Services:
Customer relationship intangibles		9.7		(4.4	)		5.3		9.7		(4.1	)		5.6
Contract-based intangibles		0.4		(0.2	)		0.2		0.4		(0.2	)		0.2
Segment total		10.1		(4.6	)		5.5		10.1		(4.3	)		5.8
Offshore Pipelines & Services:
Customer relationship intangibles		205.8		(134.3	)		71.5		205.8		(129.2	)		76.6
Contract-based intangibles		1.2		(0.4	)		0.8		1.2		(0.3	)		0.9
Segment total		207.0		(134.7	)		72.3		207.0		(129.5	)		77.5
Petrochemical & Refined Products Services:
Customer relationship intangibles		104.3		(30.9	)		73.4		104.3		(28.4	)		75.9
Contract-based intangibles		59.7		(31.8	)		27.9		57.6		(29.7	)		27.9
Segment total		164.0		(62.7	)		101.3		161.9		(58.1	)		103.8
Total all segments	$	2,638.5	$	(1,019.3	)	$	1,619.2	$	2,646.6	$	(990.4	)	$	1,656.2

Amortization Expense of Intangible Assets by Segment

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

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2012		2011		2012		2011
NGL Pipelines & Services	$	9.6	$	10.0	$	19.8	$	20.4
Onshore Natural Gas Pipelines & Services		15.8		20.2		31.6		40.1
Onshore Crude Oil Pipelines & Services		0.1		0.1		0.3		0.2
Offshore Pipelines & Services		2.6		2.8		5.2		5.8
Petrochemical & Refined Products Services		3.2		4.3		6.7		8.6
Total	$	31.3	$	37.4	$	63.6	$	75.1

Forecasted Amortization Expense

The following table presents our forecast of amortization expense associated with existing intangible assets for the periods indicated:

Remainder of 2012				2013				2014				2015				2016
$	60.0			$	111.6			$	107.1			$	106.6			$	107.8

Debt Obligations (Tables)

6 Months Ended

Jun. 30, 2012

Debt Obligations [Abstract]

Consolidated Debt Obligations

The following table presents our consolidated debt obligations (arranged by company and maturity date) at the dates indicated:

	June 30, 2012			December 31, 2011
EPO senior debt obligations:
Senior Notes S, 7.625% fixed-rate, due February 2012	$	--		$	490.5
Senior Notes P, 4.60% fixed-rate, due August 2012		500.0			500.0
Senior Notes C, 6.375% fixed-rate, due February 2013		350.0			350.0
Senior Notes T, 6.125% fixed-rate, due February 2013		182.5			182.5
Senior Notes M, 5.65% fixed-rate, due April 2013		400.0			400.0
Senior Notes U, 5.90% fixed-rate, due April 2013		237.6			237.6
Senior Notes O, 9.75% fixed-rate, due January 2014		500.0			500.0
Senior Notes G, 5.60% fixed-rate, due October 2014		650.0			650.0
Senior Notes I, 5.00% fixed-rate, due March 2015		250.0			250.0
Senior Notes X, 3.70% fixed-rate, due June 2015		400.0			400.0
Senior Notes AA, 3.20% fixed-rate, due February 2016		750.0			750.0
$3.5 Billion Multi-Year Revolving Credit Facility, variable-rate, due September 2016		427.0			150.0
Senior Notes L, 6.30% fixed-rate, due September 2017		800.0			800.0
Senior Notes V, 6.65% fixed-rate, due April 2018		349.7			349.7
Senior Notes N, 6.50% fixed-rate, due January 2019		700.0			700.0
Senior Notes Q, 5.25% fixed-rate, due January 2020		500.0			500.0
Senior Notes Y, 5.20% fixed-rate, due September 2020		1,000.0			1,000.0
Senior Notes CC, 4.05% fixed-rate, due February 2022		650.0			650.0
Senior Notes D, 6.875% fixed-rate, due March 2033		500.0			500.0
Senior Notes H, 6.65% fixed-rate, due October 2034		350.0			350.0
Senior Notes J, 5.75% fixed-rate, due March 2035		250.0			250.0
Senior Notes W, 7.55% fixed-rate, due April 2038		399.6			399.6
Senior Notes R, 6.125% fixed-rate, due October 2039		600.0			600.0
Senior Notes Z, 6.45% fixed-rate, due September 2040		600.0			600.0
Senior Notes BB, 5.95% fixed-rate, due February 2041		750.0			750.0
Senior Notes DD, 5.70% fixed-rate, due February 2042		600.0			600.0
Senior Notes EE, 4.85% fixed-rate, due August 2042		750.0			--
TEPPCO senior debt obligations:
TEPPCO Senior Notes, 7.625% fixed-rate, due February 2012		--			9.5
TEPPCO Senior Notes, 6.125% fixed-rate, due February 2013		17.5			17.5
TEPPCO Senior Notes, 5.90% fixed-rate, due April 2013		12.4			12.4
TEPPCO Senior Notes, 6.65% fixed-rate, due April 2018		0.3			0.3
TEPPCO Senior Notes, 7.55% fixed-rate, due April 2038		0.4			0.4
Total principal amount of senior debt obligations		13,477.0			12,950.0
EPO Junior Subordinated Notes A, fixed/variable-rate, due August 2066		550.0			550.0
EPO Junior Subordinated Notes C, fixed/variable-rate, due June 2067		285.8			285.8
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		14.2			14.2
Total principal amount of senior and junior debt obligations		15,009.7			14,482.7
Other, non-principal amounts:
Change in fair value of debt hedged in fair value hedging relationship (1)		39.7			73.8
Unamortized discounts, net of premiums		(32.6	)		(30.0	)
Unamortized deferred net gains related to terminated interest rate swaps (1)		29.9			2.9
Total other, non-principal amounts		37.0			46.7
Less current maturities of debt (2)		(1,700.0	)		(500.0	)
Total long-term debt	$	13,346.7		$	14,029.4

(1) See Note 4 for information regarding our interest rate hedging activities. (2) We expect to refinance the current maturities of our debt obligations prior to their maturity.

Consolidated Debt Maturities

The following table presents contractually scheduled maturities of our consolidated debt obligations outstanding at June 30, 2012 for the next five years, and in total thereafter:

			Scheduled Maturities of Debt
	Total		Remainder of 2012		2013		2014		2015		2016		After 2016
Revolving Credit Facility	$	427.0	$	--	$	--	$	--	$	--	$	427.0	$	--
Senior Notes		13,050.0		500.0		1,200.0		1,150.0		650.0		750.0		8,800.0
Junior Subordinated Notes		1,532.7		--		--		--		--		--		1,532.7
Total	$	15,009.7	$	500.0	$	1,200.0	$	1,150.0	$	650.0	$	1,177.0	$	10,332.7

Interest Rates and Weighted-Average Interest Rates Paid on Consolidated Variable-Rate Debt Obligations

The following table presents the range of interest rates and weighted-average interest rates paid on our consolidated variable-rate debt obligation during the six months ended June 30, 2012:

	Range of Interest Rates Paid	Weighted-Average Interest Rate Paid
EPO $3.5 Billion Multi-Year Revolving Credit Facility	1.54% to 3.63%	1.61%

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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Reference 11: http://www.xbrl.org/2003/role/presentationRef
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-Name Regulation S-X (SX)
-Number 210
-Section 02
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Summary of Changes in Outstanding Units

Equity and Distributions (Tables)

6 Months Ended

Jun. 30, 2012

Equity and Distributions [Abstract]

	Common Units			Class B Units		Treasury Units
Number of units outstanding at December 31, 2011		881,620,418			4,520,431		--
Common units issued in connection with DRIP and EUPP		1,270,609			--		--
Common units issued in connection with equity-based awards		214,492			--		--
Restricted common unit awards issued		1,538,438			--		--
Forfeiture of restricted common unit awards		(95,575	)		--		--
Acquisition of treasury units in connection with vesting of equity-based awards		(373,391	)		--		373,391
Cancellation of treasury units		--			--		(373,391	)
Number of units outstanding at June 30, 2012		884,174,991			4,520,431		--

Components of Accumulated Other Comprehensive Income (Loss)

The following table presents the components of accumulated other comprehensive income (loss) as reported on our Unaudited Condensed Consolidated Balance Sheets at the dates indicated:

	June 30, 2012			December 31, 2011
Commodity derivative instruments (1)	$	60.2		$	(21.4	)
Interest rate derivative instruments (1)		(377.7	)		(329.0	)
Foreign currency translation adjustment (2)		1.7			1.7
Pension and postretirement benefit plans		(2.9	)		(1.7	)
Other		--			(1.0	)
Total accumulated other comprehensive loss	$	(318.7	)	$	(351.4	)

(1) See Note 4 for additional information regarding our derivative instruments. (2) Relates to transactions of a Canadian subsidiary.

Components of Noncontrolling Interest

The following table presents additional information regarding noncontrolling interests as presented on our Unaudited Condensed Consolidated Balance Sheets at the dates indicated:

	June 30, 2012		December 31, 2011
Joint venture partners (1)	$	109.8	$	105.9
(1) Represents third party ownership interests in joint ventures that we consolidate, including Tri-States NGL Pipeline L.L.C., Independence Hub LLC, Rio Grande Pipeline Company and Wilprise Pipeline Company LLC.

Components of Net Income Attributable to Noncontrolling Interest

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2012		2011		2012		2011
Former owners of Duncan Energy Partners	$	--	$	9.4	$	--	$	17.3
Joint venture partners		0.9		5.4		5.1		11.3
Total	$	0.9	$	14.8	$	5.1	$	28.6

Cash Distributions Paid to and Cash Contributions Received From Noncontrolling Interests

	For the Six Months Ended June 30,
	2012		2011
Cash distributions paid to noncontrolling interests:
Former owners of Duncan Energy Partners	$	--	$	21.9
Joint venture partners		8.1		12.9
Total cash distributions paid to noncontrolling interests	$	8.1	$	34.8

Cash contributions from noncontrolling interests:
Former owners of Duncan Energy Partners	$	--	$	1.5
Joint venture partners		5.9		1.1
Total cash contributions from noncontrolling interests	$	5.9	$	2.6

Declared Quarterly Cash Distribution Rates

The following table presents our declared quarterly cash distribution rates with respect to the quarter indicated:

	Distribution Per Common Unit		Record Date	Payment Date
2012
1st Quarter	$	0.6275	04/30/12	05/09/12
2nd Quarter	$	0.6350	07/31/12	08/08/12

Business Segments (Tables)

6 Months Ended

Jun. 30, 2012

Business Segments [Abstract]

Measurement of Total Segment Gross Operating Margin

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

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2012			2011			2012			2011
Revenues	$	9,789.8		$	11,216.5		$	21,042.3		$	21,400.2
Less: Operating costs and expenses		(9,009.5	)		(10,533.3	)		(19,476.7	)		(20,070.4	)
Add: Equity in income of unconsolidated affiliates		11.3			11.1			21.2			27.3
Depreciation, amortization and accretion (1)		261.3			233.3			515.9			464.1
Non-cash asset impairment charges		9.1			--			14.5			--
Operating lease expenses paid by EPCO		--			0.1			--			0.3
Gains related to asset sales (2)		(1.3	)		(5.2	)		(3.8	)		(23.6	)
Gains related to property damage insurance recoveries (see Note 16)		(27.7	)		--			(27.7	)		--
Total segment gross operating margin	$	1,033.0		$	922.5		$	2,085.7		$	1,797.9

(1) Amount is a component of "Depreciation, amortization and accretion" as presented on the Unaudited Condensed Statements of Consolidated Cash Flows. (2) Amounts presented for the second quarter of 2011 and the six months ended June 30, 2011 include $5.4 million of gains related to the sale of a portion of our previously held equity method investment in Energy Transfer Equity (see Note 7).

Reconciliation of Total Segment Gross Operating Margin to Operating Income and Income Before Provision for Income Taxes

The following table presents a reconciliation of total segment gross operating margin to operating income and further to income before income taxes for the periods indicated:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2012			2011			2012			2011
Total segment gross operating margin	$	1,033.0		$	922.5		$	2,085.7		$	1,797.9
Adjustments to reconcile total segment gross operating margin to operating income:
Amounts included in operating costs and expenses:
Depreciation, amortization and accretion		(261.3	)		(233.3	)		(515.9	)		(464.1	)
Non-cash asset impairment charges		(9.1	)		--			(14.5	)		--
Operating lease expenses paid by EPCO		--			(0.1	)		--			(0.3	)
Gains related to asset sales		1.3			5.2			3.8			23.6
Gains related to property damage insurance recoveries (see Note 16)		27.7			--			27.7			--
General and administrative costs		(42.5	)		(50.4	)		(88.8	)		(88.3	)
Operating income		749.1			643.9			1,498.0			1,268.8
Other expense, net		(173.4	)		(188.0	)		(301.2	)		(371.3	)
Income before income taxes	$	575.7		$	455.9		$	1,196.8		$	897.5

Information by Business Segments

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

	Reportable Business Segments
	NGL Pipelines & Services		Onshore Natural Gas Pipelines & Services			Onshore Crude Oil Pipelines & Services			Offshore Pipelines & Services		Petrochemical & Refined Products Services				Other Investments		Adjustments and Eliminations			Consolidated Total
Revenues from third parties:
Three months ended June 30, 2012	$	3,327.9		$	700.9	$	4,188.7		$	47.5		$	1,499.2		$	--	$	--		$	9,764.2
Three months ended June 30, 2011		3,960.1			862.5		4,281.6			61.1			1,907.0			--		--			11,072.3
Six months ended June 30, 2012		7,682.0			1,505.8		8,662.3			101.9			3,033.9			--		--			20,985.9
Six months ended June 30, 2011		8,015.5			1,734.2		7,652.2			121.7			3,482.3			--		--			21,005.9
Revenues from related parties:
Three months ended June 30, 2012		4.6			19.5		--			1.5			--			--		--			25.6
Three months ended June 30, 2011		76.8			64.8		--			2.6			--			--		--			144.2
Six months ended June 30, 2012		5.0			48.2		--			3.2			--			--		--			56.4
Six months ended June 30, 2011		278.2			109.7		--			6.4			--			--		--			394.3
Intersegment and intrasegment revenues:
Three months ended June 30, 2012		2,276.5			179.0		1,735.5			1.7			438.7			--		(4,631.4	)		--
Three months ended June 30, 2011		3,228.2			253.9		1,477.6			0.1			445.5			--		(5,405.3	)		--
Six months ended June 30, 2012		5,094.7			402.7		3,466.4			5.0			878.6			--		(9,847.4	)		--
Six months ended June 30, 2011		6,702.8			524.8		2,184.7			1.8			918.6			--		(10,332.7	)		--
Total revenues:
Three months ended June 30, 2012		5,609.0			899.4		5,924.2			50.7			1,937.9			--		(4,631.4	)		9,789.8
Three months ended June 30, 2011		7,265.1			1,181.2		5,759.2			63.8			2,352.5			--		(5,405.3	)		11,216.5
Six months ended June 30, 2012		12,781.7			1,956.7		12,128.7			110.1			3,912.5			--		(9,847.4	)		21,042.3
Six months ended June 30, 2011		14,996.5			2,368.7		9,836.9			129.9			4,400.9			--		(10,332.7	)		21,400.2
Equity in income (loss) of unconsolidated affiliates:
Three months ended June 30, 2012		3.8			1.2		3.6			4.1			(1.4	)		--		--			11.3
Three months ended June 30, 2011		6.2			1.5		(1.6	)		6.6			(4.3	)		2.7		--			11.1
Six months ended June 30, 2012		9.0			2.6		4.1			11.0			(7.9	)		2.4		--			21.2
Six months ended June 30, 2011		12.1			2.7		(2.1	)		14.9			(9.3	)		9.0		--			27.3
Gross operating margin:
Three months ended June 30, 2012		565.8			175.8		95.8			38.3			157.3			--		--			1,033.0
Three months ended June 30, 2011		497.7			161.1		67.8			53.4			139.8			2.7		--			922.5
Six months ended June 30, 2012		1,220.7			382.0		135.1			90.4			255.1			2.4		--			2,085.7
Six months ended June 30, 2011		1,002.1			320.3		99.6			114.7			252.2			9.0		--			1,797.9
Segment assets:
At June 30, 2012		8,534.7			10,419.1		1,315.5			2,001.9			3,838.4			--		2,275.7			28,385.3
At December 31, 2011		7,966.4			9,949.6		944.6			2,000.9			3,769.5			1,023.1		2,145.6			27,799.7
Property, plant and equipment, net: (see Note 6)
At June 30, 2012		7,668.7			8,997.6		819.6			1,385.0			2,614.0			--		2,275.7			23,760.6
At December 31, 2011		7,137.8			8,495.4		456.9			1,416.4			2,539.5			--		2,145.6			22,191.6
Investments in unconsolidated affiliates: (see Note 7)
At June 30, 2012		184.4			25.5		179.2			462.5			61.6			--		--			913.2
At December 31, 2011		146.1			30.1		170.7			424.9			64.7			1,023.1		--			1,859.6
Intangible assets, net: (see Note 8)
At June 30, 2012		340.4			1,099.7		5.5			72.3			101.3			--		--			1,619.2
At December 31, 2011		341.3			1,127.8		5.8			77.5			103.8			--		--			1,656.2
Goodwill: (see Note 8)
At June 30, 2012		341.2			296.3		311.2			82.1			1,061.5			--		--			2,092.3
At December 31, 2011		341.2			296.3		311.2			82.1			1,061.5			--		--			2,092.3

Consolidated Revenues and Expenses

The following table presents additional information regarding our consolidated revenues and costs and expenses for the periods indicated:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2012			2011			2012			2011
NGL Pipelines & Services:
Sales of NGLs and related products	$	3,133.9		$	3,832.2		$	7,249.2		$	7,889.9
Midstream services		198.6			204.7			437.8			403.8
Total		3,332.5			4,036.9			7,687.0			8,293.7
Onshore Natural Gas Pipelines & Services:
Sales of natural gas		510.8			719.5			1,083.4			1,432.2
Midstream services		209.6			207.8			470.6			411.7
Total		720.4			927.3			1,554.0			1,843.9
Onshore Crude Oil Pipelines & Services:
Sales of crude oil		4,174.0			4,257.9			8,621.6			7,606.1
Midstream services		14.7			23.7			40.7			46.1
Total		4,188.7			4,281.6			8,662.3			7,652.2
Offshore Pipelines & Services:
Sales of natural gas		--			0.3			0.1			0.6
Sales of crude oil		--			2.5			1.4			5.8
Midstream services		49.0			60.9			103.6			121.7
Total		49.0			63.7			105.1			128.1
Petrochemical & Refined Products Services:
Sales of petrochemicals and refined products		1,316.8			1,718.7			2,668.0			3,101.5
Midstream services		182.4			188.3			365.9			380.8
Total		1,499.2			1,907.0			3,033.9			3,482.3
Total consolidated revenues	$	9,789.8		$	11,216.5		$	21,042.3		$	21,400.2

Consolidated costs and expenses
Operating costs and expenses:
Cost of sales	$	8,195.2		$	9,790.3		$	17,861.0		$	18,609.6
Other operating costs and expenses (1)		572.9			514.9			1,116.8			1,020.3
Depreciation, amortization and accretion		261.3			233.3			515.9			464.1
Gains related to asset sales		(1.3	)		(5.2	)		(3.8	)		(23.6	)
Gains related to property damage insurance recoveries		(27.7	)		--			(27.7	)		--
Non-cash asset impairment charges		9.1			--			14.5			--
General and administrative costs		42.5			50.4			88.8			88.3
Total consolidated costs and expenses	$	9,052.0		$	10,583.7		$	19,565.5		$	20,158.7

(1) Represents cost of operating our plants, pipelines and other fixed assets, excluding non-cash depreciation, amortization and accretion charges.

Tabular disclosure of the profit or loss and total assets for each reportable segment. An entity discloses certain information on each reportable segment if the amounts (a) are included in the measure of segment profit or loss reviewed by the chief operating decision maker or (b) are otherwise regularly provided to the chief operating decision maker, even if not included in that measure of segment profit or loss.

Related Party Transactions

Related Party Transactions (Tables)

6 Months Ended

Jun. 30, 2012

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

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2012		2011		2012		2011
Revenues - related parties:
Energy Transfer Equity and subsidiaries	$	--	$	86.7	$	--	$	296.9
Other unconsolidated affiliates		25.6		57.5		56.4		97.4
Total revenue - related parties	$	25.6	$	144.2	$	56.4	$	394.3
Costs and expenses - related parties:
EPCO and affiliates	$	240.1	$	192.4	$	406.1	$	365.4
Energy Transfer Equity and subsidiaries		--		223.0		--		490.4
Other unconsolidated affiliates		7.2		11.4		12.3		21.6
Total costs and expenses - related parties	$	247.3	$	426.8	$	418.4	$	877.4

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

	June 30, 2012		December 31, 2011
Accounts receivable - related parties:
Energy Transfer Equity and subsidiaries	$	--	$	28.4
Other unconsolidated affiliates		2.3		15.1
Total accounts receivable - related parties	$	2.3	$	43.5

Accounts payable - related parties:
EPCO and affiliates	$	61.8	$	108.3
Energy Transfer Equity and subsidiaries		--		92.6
Other unconsolidated affiliates		8.4		10.7
Total accounts payable - related parties	$	70.2	$	211.6

Number of Units	Percentage of Total Units Outstanding
338,930,881 (1)	38.1%
(1) Includes 4,520,431 Class B units.

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2012		2011		2012		2011
Operating costs and expenses	$	213.6	$	157.9	$	356.3	$	305.3
General and administrative expenses		26.5		34.5		49.8		60.1
Total costs and expenses	$	240.1	$	192.4	$	406.1	$	365.4

Earnings Per Unit (Tables)

6 Months Ended

Jun. 30, 2012

Earnings Per Unit [Abstract]

Basic and Diluted Earnings Per Unit

The following table presents our calculation of basic and diluted earnings per unit for the periods indicated:

	For the Three Months Ended June 30				For the Six Months Ended June 30,
	2012		2011		2012		2011
BASIC EARNINGS PER UNIT
Numerator:
Net income attributable to limited partners	$	566.3	$	433.7	$	1,217.6	$	854.4
Denominator:
Weighted-average number of:
Distribution-bearing common units outstanding		857.9		815.1		857.3		814.5
Basic earnings per unit:
Net income attributable to limited partners	$	0.66	$	0.53	$	1.42	$	1.05
DILUTED EARNINGS PER UNIT
Numerator:
Net income attributable to limited partners	$	566.3	$	433.7	$	1,217.6	$	854.4
Denominator:
Weighted-average number of:
Distribution-bearing common units outstanding		857.9		815.1		857.3		814.5
Class B units		4.5		4.5		4.5		4.5
Designated Units (see Note 10)		26.1		30.6		26.1		30.6
Incremental option units		1.4		1.2		1.4		1.3
Total		889.9		851.4		889.3		850.9
Diluted earnings per unit:
Net income attributable to limited partners	$	0.64	$	0.51	$	1.37	$	1.00

Supplemental Cash Flow Information (Tables)

6 Months Ended

Jun. 30, 2012

Supplemental Cash Flow Information [Abstract]

Net Effect of Changes in Operating Assets and Liabilities

The following table presents the net effect of changes in our operating accounts for the periods indicated:

	For the Six Months
	Ended June 30,
	2012			2011
Decrease (increase) in:
Accounts receivable - trade	$	785.5		$	(474.2	)
Accounts receivable - related parties		35.7			(0.2	)
Inventories		(20.8	)		266.5
Prepaid and other current assets		(13.9	)		(55.8	)
Other assets		(53.7	)		(34.2	)
Increase (decrease) in:
Accounts payable - trade		(45.7	)		110.9
Accounts payable - related parties		(141.3	)		49.9
Accrued product payables		(880.2	)		479.0
Accrued interest		1.0			18.1
Other current liabilities		84.1			(10.4	)
Other liabilities		(31.0	)		11.8
Net effect of changes in operating accounts	$	(280.3	)	$	361.4

Condensed Consolidating Financial Information (Tables)

6 Months Ended

Jun. 30, 2012

Condensed Consolidating Financial Information [Abstract]

Condensed Consolidating Financial Information

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Balance Sheet

June 30, 2012

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non-guarantor)		EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries		Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments			Consolidated Total
ASSETS
Current assets:
Cash and cash equivalents and restricted cash	$	28.1	$	34.3	$	(47.9	)	$	14.5	$	--		$	--		$	14.5
Accounts receivable - trade, net		1,151.8		2,579.7		(6.6	)		3,724.9		--			--			3,724.9
Accounts receivable - related parties		323.6		1,566.5		(1,871.6	)		18.5		(16.8	)		0.6			2.3
Inventories		766.4		127.6		(1.1	)		892.9		--			--			892.9
Prepaid and other current assets		181.9		267.4		(14.8	)		434.5		0.3			--			434.8
Total current assets		2,451.8		4,575.5		(1,942.0	)		5,085.3		(16.5	)		0.6			5,069.4
Property, plant and equipment, net		1,599.2		22,170.8		(9.4	)		23,760.6		--			--			23,760.6
Investments in unconsolidated affiliates		26,978.9		1,483.2		(27,548.9	)		913.2		12,382.7			(12,382.7	)		913.2
Intangible assets, net		155.2		1,477.1		(13.1	)		1,619.2		--			--			1,619.2
Goodwill		458.9		1,633.4		--			2,092.3		--			--			2,092.3
Other assets		125.3		87.8		(0.8	)		212.3		0.1			--			212.4
Total assets	$	31,769.3	$	31,427.8	$	(29,514.2	)	$	33,682.9	$	12,366.3		$	(12,382.1	)	$	33,667.1

LIABILITIES AND EQUITY
Current liabilities:
Current maturities of debt	$	1,670.1	$	29.9	$	--		$	1,700.0	$	--		$	--		$	1,700.0
Accounts payable - trade		245.1		565.4		(47.9	)		762.6		--			--			762.6
Accounts payable - related parties		1,778.4		158.0		(1,866.8	)		69.6		--			0.6			70.2
Accrued product payables		1,554.7		2,496.4		(11.4	)		4,039.7		--			--			4,039.7
Accrued interest		288.4		0.7		--			289.1		--			--			289.1
Other current liabilities		427.3		343.0		(13.7	)		756.6		--			0.1			756.7
Total current liabilities		5,964.0		3,593.4		(1,939.8	)		7,617.6		--			0.7			7,618.3
Long-term debt		13,331.8		14.9		--			13,346.7		--			--			13,346.7
Deferred tax liabilities		5.8		19.7		(0.8	)		24.7		--			(0.9	)		23.8
Other long-term liabilities		23.7		178.5		--			202.2		--			--			202.2
Commitments and contingencies
Equity:
Partners' and other owners' equity		12,444.0		27,544.1		(27,624.0	)		12,364.1		12,366.3			(12,364.1	)		12,366.3
Noncontrolling interests		--		77.2		50.4			127.6		--			(17.8	)		109.8
Total equity		12,444.0		27,621.3		(27,573.6	)		12,491.7		12,366.3			(12,381.9	)		12,476.1
Total liabilities and equity	$	31,769.3	$	31,427.8	$	(29,514.2	)	$	33,682.9	$	12,366.3		$	(12,382.1	)	$	33,667.1

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Balance Sheet

December 31, 2011

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non-guarantor)		EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries		Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments			Consolidated Total
ASSETS
Current assets:
Cash and cash equivalents and restricted cash	$	48.2	$	21.3	$	(11.2	)	$	58.3	$	--		$	--		$	58.3
Accounts receivable - trade, net		1,599.4		2,913.2		(10.8	)		4,501.8		--			--			4,501.8
Accounts receivable - related parties		141.1		2,155.5		(2,252.0	)		44.6		(1.1	)		--			43.5
Inventories		943.6		170.5		(2.4	)		1,111.7		--			--			1,111.7
Prepaid and other current assets		216.8		152.6		(16.0	)		353.4		--			--			353.4
Total current assets		2,949.1		5,413.1		(2,292.4	)		6,069.8		(1.1	)		--			6,068.7
Property, plant and equipment, net		1,477.5		20,723.7		(9.6	)		22,191.6		--			--			22,191.6
Investments in unconsolidated affiliates		27,060.0		8,266.7		(33,467.1	)		1,859.6		12,114.5			(12,114.5	)		1,859.6
Intangible assets, net		142.4		1,527.4		(13.6	)		1,656.2		--			--			1,656.2
Goodwill		458.9		1,633.4		--			2,092.3		--			--			2,092.3
Other assets		146.4		107.5		2.8			256.7		--			--			256.7
Total assets	$	32,234.3	$	37,671.8	$	(35,779.9	)	$	34,126.2	$	12,113.4		$	(12,114.5	)	$	34,125.1

LIABILITIES AND EQUITY
Current liabilities:
Current maturities of debt	$	500.0	$	--	$	--		$	500.0	$	--		$	--		$	500.0
Accounts payable - trade		205.6		578.6		(11.2	)		773.0		--			--			773.0
Accounts payable - related parties		2,407.2		71.9		(2,267.5	)		211.6		--			--			211.6
Accrued product payables		2,141.0		2,912.4		(6.3	)		5,047.1		--			--			5,047.1
Accrued interest		287.1		1.0		--			288.1		--			--			288.1
Other current liabilities		298.1		321.8		(7.4	)		612.5		--			0.1			612.6
Total current liabilities		5,839.0		3,885.7		(2,292.4	)		7,432.3		--			0.1			7,432.4
Long-term debt		13,975.1		54.3		--			14,029.4		--			--			14,029.4
Deferred tax liabilities		22.2		67.1		2.8			92.1		--			(0.9	)		91.2
Other long-term liabilities		155.3		197.5		--			352.8		--			--			352.8
Commitments and contingencies
Equity:
Partners' and other owners' equity		12,242.7		28,799.8		(28,946.4	)		12,096.1		12,113.4			(12,096.1	)		12,113.4
Noncontrolling interests		--		4,667.4		(4,543.9	)		123.5		--			(17.6	)		105.9
Total equity		12,242.7		33,467.2		(33,490.3	)		12,219.6		12,113.4			(12,113.7	)		12,219.3
Total liabilities and equity	$	32,234.3	$	37,671.8	$	(35,779.9	)	$	34,126.2	$	12,113.4		$	(12,114.5	)	$	34,125.1

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Statement of Operations

Three Months Ended June 30, 2012

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non-guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
Revenues	$	6,033.6		$	6,696.0		$	(2,939.8	)	$	9,789.8		$	--	$	--		$	9,789.8
Costs and expenses:
Operating costs and expenses		5,864.4			6,083.0			(2,937.9	)		9,009.5			--		--			9,009.5
General and administrative costs		9.1			32.6			--			41.7			0.8		--			42.5
Total costs and expenses		5,873.5			6,115.6			(2,937.9	)		9,051.2			0.8		--			9,052.0
Equity in income of unconsolidated affiliates		598.8			(51.0	)		(536.5	)		11.3			567.1		(567.1	)		11.3
Operating income		758.9			529.4			(538.4	)		749.9			566.3		(567.1	)		749.1
Other income (expense):
Interest expense		(185.7	)		(0.9	)		--			(186.6	)		--		--			(186.6	)
Other, net		--			13.2			--			13.2			--		--			13.2
Total other expense, net		(185.7	)		12.3			--			(173.4	)		--		--			(173.4	)
Income before income taxes		573.2			541.7			(538.4	)		576.5			566.3		(567.1	)		575.7
Provision for income taxes		(4.6	)		(3.7	)		--			(8.3	)		--		(0.2	)		(8.5	)
Net income		568.6			538.0			(538.4	)		568.2			566.3		(567.3	)		567.2
Net loss (income) attributable to noncontrolling interests		--			40.2			(41.7	)		(1.5	)		--		0.6			(0.9	)
Net income attributable to entity	$	568.6		$	578.2		$	(580.1	)	$	566.7		$	566.3	$	(566.7	)	$	566.3

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Statement of Operations

Three Months Ended June 30, 2011

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non-guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
Revenues	$	7,959.5		$	7,194.7		$	(3,937.7	)	$	11,216.5		$	--	$	--		$	11,216.5
Costs and expenses:
Operating costs and expenses		7,824.2			6,646.7			(3,937.6	)		10,533.3			--		--			10,533.3
General and administrative costs		3.4			43.8			--			47.2			3.2		--			50.4
Total costs and expenses		7,827.6			6,690.5			(3,937.6	)		10,580.5			3.2		--			10,583.7
Equity in income of unconsolidated affiliates		492.8			24.9			(506.6	)		11.1			436.9		(436.9	)		11.1
Operating income		624.7			529.1			(506.7	)		647.1			433.7		(436.9	)		643.9
Other income (expense):
Interest expense		(184.0	)		(6.2	)		1.9			(188.3	)		--		--			(188.3	)
Other, net		1.9			0.3			(1.9	)		0.3			--		--			0.3
Total other expense, net		(182.1	)		(5.9	)		--			(188.0	)		--		--			(188.0	)
Income before income taxes		442.6			523.2			(506.7	)		459.1			433.7		(436.9	)		455.9
Provision for income taxes		(5.7	)		(1.6	)		--			(7.3	)		--		(0.1	)		(7.4	)
Net income		436.9			521.6			(506.7	)		451.8			433.7		(437.0	)		448.5
Net loss (income) attributable to noncontrolling interests		--			(7.5	)		(7.5	)		(15.0	)		--		0.2			(14.8	)
Net income attributable to entity	$	436.9		$	514.1		$	(514.2	)	$	436.8		$	433.7	$	(436.8	)	$	433.7

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Statement of Operations

Six Months Ended June 30, 2012

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
Revenues	$	13,673.4		$	13,854.5		$	(6,485.6	)	$	21,042.3		$	--	$	--		$	21,042.3
Costs and expenses:
Operating costs and expenses		13,274.2			12,686.6			(6,484.1	)		19,476.7			--		--			19,476.7
General and administrative costs		24.5			63.3			--			87.8			1.0		--			88.8
Total costs and expenses		13,298.7			12,749.9			(6,484.1	)		19,564.5			1.0		--			19,565.5
Equity in income of unconsolidated affiliates		1,193.3			27.4			(1,199.5	)		21.2			1,218.6		(1,218.6	)		21.2
Operating income		1,568.0			1,132.0			(1,201.0	)		1,499.0			1,217.6		(1,218.6	)		1,498.0
Other income (expense):
Interest expense		(371.3	)		(1.8	)		--			(373.1	)		--		--			(373.1	)
Other, net		0.1			71.8			--			71.9			--		--			71.9
Total other expense, net		(371.2	)		70.0			--			(301.2	)		--		--			(301.2	)
Income before income taxes		1,196.8			1,202.0			(1,201.0	)		1,197.8			1,217.6		(1,218.6	)		1,196.8
Benefit from income taxes		22.4			3.7			--			26.1			--		(0.2	)		25.9
Net income		1,219.2			1,205.7			(1,201.0	)		1,223.9			1,217.6		(1,218.8	)		1,222.7
Net loss (income) attributable to noncontrolling interests		--			(4.2	)		(2.0	)		(6.2	)		--		1.1			(5.1	)
Net income attributable to entity	$	1,219.2		$	1,201.5		$	(1,203.0	)	$	1,217.7		$	1,217.6	$	(1,217.7	)	$	1,217.6

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Statement of Operations

Six Months Ended June 30, 2011

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
Revenues	$	16,284.3		$	13,273.4		$	(8,157.5	)	$	21,400.2		$	--	$	--		$	21,400.2
Costs and expenses:
Operating costs and expenses		16,002.4			12,225.3			(8,157.3	)		20,070.4			--		--			20,070.4
General and administrative costs		4.3			77.5			--			81.8			6.5		--			88.3
Total costs and expenses		16,006.7			12,302.8			(8,157.3	)		20,152.2			6.5		--			20,158.7
Equity in income of unconsolidated affiliates		950.8			56.7			(980.2	)		27.3			860.9		(860.9	)		27.3
Operating income		1,228.4			1,027.3			(980.4	)		1,275.3			854.4		(860.9	)		1,268.8
Other income (expense):
Interest expense		(363.0	)		(12.9	)		3.8			(372.1	)		--		--			(372.1	)
Other, net		3.9			0.7			(3.8	)		0.8			--		--			0.8
Total other expense, net		(359.1	)		(12.2	)		--			(371.3	)		--		--			(371.3	)
Income before income taxes		869.3			1,015.1			(980.4	)		904.0			854.4		(860.9	)		897.5
Provision for income taxes		(8.5	)		(5.9	)		--			(14.4	)		--		(0.1	)		(14.5	)
Net income		860.8			1,009.2			(980.4	)		889.6			854.4		(861.0	)		883.0
Net loss (income) attributable to noncontrolling interests		--			(10.9	)		(18.2	)		(29.1	)		--		0.5			(28.6	)
Net income attributable to entity	$	860.8		$	998.3		$	(998.6	)	$	860.5		$	854.4	$	(860.5	)	$	854.4

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Statement of Comprehensive Income

Three Months Ended June 30, 2012

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non- guarantor)		EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
Comprehensive income	$	503.8	$	625.9	$	(538.4	)	$	591.3		$	589.4	$	(590.4	)	$	590.3
Comprehensive income attributable to noncontrolling interests		--		40.2		(41.7	)		(1.5	)		--		0.6			(0.9	)
Comprehensive income attributable to entity	$	503.8	$	666.1	$	(580.1	)	$	589.8		$	589.4	$	(589.8	)	$	589.4

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Statement of Comprehensive Income

Three Months Ended June 30, 2011

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
Comprehensive income	$	382.1	$	570.3		$	(506.7	)	$	445.7		$	427.6	$	(430.9	)	$	442.4
Comprehensive income attributable to noncontrolling interests		--		(7.5	)		(7.5	)		(15.0	)		--		0.2			(14.8	)
Comprehensive income attributable to entity	$	382.1	$	562.8		$	(514.2	)	$	430.7		$	427.6	$	(430.7	)	$	427.6

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Statement of Comprehensive Income

Six Months Ended June 30, 2012

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
Comprehensive income	$	1,183.6	$	1,274.0		$	(1,201.0	)	$	1,256.6		$	1,250.3	$	(1,251.5	)	$	1,255.4
Comprehensive income attributable to noncontrolling interests		--		(4.2	)		(2.0	)		(6.2	)		--		1.1			(5.1	)
Comprehensive income attributable to entity	$	1,183.6	$	1,269.8		$	(1,203.0	)	$	1,250.4		$	1,250.3	$	(1,250.4	)	$	1,250.3

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Statement of Comprehensive Income

Six Months Ended June 30, 2011

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
Comprehensive income	$	817.2	$	979.1		$	(980.4	)	$	815.9		$	780.7	$	(787.3	)	$	809.3
Comprehensive income attributable to noncontrolling interests		--		(10.9	)		(18.2	)		(29.1	)		--		0.5			(28.6	)
Comprehensive income attributable to entity	$	817.2	$	968.2		$	(998.6	)	$	786.8		$	780.7	$	(786.8	)	$	780.7

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2012

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments			Consolidated Total
Operating activities:
Net income	$	1,219.2		$	1,205.7		$	(1,201.0	)	$	1,223.9		$	1,217.6		$	(1,218.8	)	$	1,222.7
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		66.4			472.0			(0.7	)		537.7			--			--			537.7
Equity in income of unconsolidated affiliates		(1,193.3	)		(27.4	)		1,199.5			(21.2	)		(1,218.6	)		1,218.6			(21.2	)
Distributions received from unconsolidated affiliates		1,589.2			40.0			(1,578.7	)		50.5			1,082.4			(1,082.4	)		50.5
Net effect of changes in operating accounts and other operating activities		(1,148.6	)		722.3			(34.5	)		(460.8	)		9.2			0.2			(451.4	)
Net cash flows provided by operating activities		532.9			2,412.6			(1,615.4	)		1,330.1			1,090.6			(1,082.4	)		1,338.3
Investing activities:
Capital expenditures, net of contributions in aid of construction costs		(83.5	)		(1,719.6	)		--			(1,803.1	)		--			--			(1,803.1	)
Proceeds from asset sales		1,104.8			24.2			--			1,129.0			--			--			1,129.0
Other investing activities		(961.9	)		(54.2	)		940.4			(75.7	)		(60.4	)		60.4			(75.7	)
Cash used in investing activities		59.4			(1,749.6	)		940.4			(749.8	)		(60.4	)		60.4			(749.8	)
Financing activities:
Borrowings under debt agreements		2,414.6			--			--			2,414.6			--			--			2,414.6
Repayments of debt		(1,881.5	)		(9.5	)		--			(1,891.0	)		--			--			(1,891.0	)
Cash distributions paid to partners		(1,082.4	)		(1,586.9	)		1,586.9			(1,082.4	)		(1,068.6	)		1,082.4			(1,068.6	)
Cash distributions paid to noncontrolling interests		--			--			(8.1	)		(8.1	)		--			--			(8.1	)
Cash contributions from noncontrolling interests		--			--			5.9			5.9			--			--			5.9
Net cash proceeds from issuance of common units		--			--			--			--			57.7			--			57.7
Cash contributions from owners		60.4			946.4			(946.4	)		60.4			--			(60.4	)		--
Other financing activities		(85.0	)		--			--			(85.0	)		(19.3	)		--			(104.3	)
Cash provided by (used in) financing activities		(573.9	)		(650.0	)		638.3			(585.6	)		(1,030.2	)		1,022.0			(593.8	)
Net change in cash and cash equivalents		18.4			13.0			(36.7	)		(5.3	)		--			--			(5.3	)
Cash and cash equivalents, January 1		9.7			21.3			(11.2	)		19.8			--			--			19.8
Cash and cash equivalents, June 30	$	28.1		$	34.3		$	(47.9	)	$	14.5		$	--		$	--		$	14.5

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2011

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments			Consolidated Total
Operating activities:
Net income	$	860.8		$	1,009.2		$	(980.4	)	$	889.6		$	854.4		$	(861.0	)	$	883.0
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		56.6			428.9			(0.7	)		484.8			--			--			484.8
Equity in income of unconsolidated affiliates		(950.8	)		(56.7	)		980.2			(27.3	)		(860.9	)		860.9			(27.3	)
Distributions received from unconsolidated affiliates		115.3			111.9			(142.4	)		84.8			979.8			(979.8	)		84.8
Net effect of changes in operating accounts and other operating activities		1,076.0			(383.2	)		(365.1	)		327.7			1.5			--			329.2
Net cash flows provided by operating activities		1,157.9			1,110.1			(508.4	)		1,759.6			974.8			(979.9	)		1,754.5
Investing activities:
Capital expenditures, net of contributions in aid of construction costs		(50.6	)		(1,659.2	)		--			(1,709.8	)		--			--			(1,709.8	)
Other investing activities		(466.5	)		231.9			452.2			217.6			(49.2	)		49.2			217.6
Cash used in investing activities		(517.1	)		(1,427.3	)		452.2			(1,492.2	)		(49.2	)		49.2			(1,492.2	)
Financing activities:
Borrowings under debt agreements		3,372.1			419.0			--			3,791.1			--			--			3,791.1
Repayments of debt		(2,976.0	)		(57.5	)		--			(3,033.5	)		--			--			(3,033.5	)
Cash distributions paid to partners		(979.8	)		(440.0	)		440.0			(979.8	)		(966.5	)		979.8			(966.5	)
Cash distributions paid to noncontrolling interests		--			(72.8	)		38.0			(34.8	)		--			--			(34.8	)
Cash contributions from noncontrolling interests		--			449.4			(446.6	)		2.8			--			(0.2	)		2.6
Net cash proceeds from issuance of common units		--			--			--			--			45.1			--			45.1
Cash contributions from owners		49.2			5.6			(5.6	)		49.2			--			(49.2	)		--
Other financing activities		(18.5	)		--			--			(18.5	)		(4.2	)		--			(22.7	)
Cash provided by (used in) financing activities		(553.0	)		303.7			25.8			(223.5	)		(925.6	)		930.4			(218.7	)
Net change in cash and cash equivalents		87.8			(13.5	)		(30.4	)		43.9			--			(0.3	)		43.6
Cash and cash equivalents, January 1		0.5			67.9			(2.9	)		65.5			--			--			65.5
Cash and cash equivalents, June 30	$	88.3		$	54.4		$	(33.3	)	$	109.4		$	--		$	(0.3	)	$	109.1

Partnership Operations, Organization and Basis of Presentation (Details)	6 Months Ended
	Jun. 30, 2012 shares
Partnership Operations, Organization and Basis of Presentation [Abstract]
Number of active reportable segments	5
Limited partners ownership interest (in hundredths)	100.00%
Duncan Merger [Member]
Mergers [Line Items]
Common unit exchange ratio in connection with merger	1.01
Common units issued in connection with merger (in units)	24,277,310

General Accounting Matters (Details) - USD ($)
$ in Millions

3 Months Ended

6 Months Ended

Jun. 30, 2012

Jun. 30, 2011

Jun. 30, 2012

Jun. 30, 2011

Income Tax Expense (Benefit) [Abstract]

Benefit from (provision for) income taxes

$ (8.5)

$ (7.4)

$ 25.9

$ (14.5)

Income tax benefit from the conversion of company structure

46.5

Other Nonoperating Income (Expense) [Abstract]

Gain on sales of Energy Transfer Equity common units

^[1]

15.5

0.0

68.8

0.0

Distribution income from Energy Transfer Equity

0.0

4.1

0.0

Other

(2.4)

0.0

(1.4)

0.2

$ 13.1

$ 0.0

$ 71.5

$ 0.2

[1]	See Note 7 for information regarding our previously held investment in Energy Transfer Equity.

Equity-based Awards (Details)
$ / shares in Units, $ in Millions

3 Months Ended

6 Months Ended

12 Months Ended

Jun. 30, 2012

USD ($)

$ / shares

Jun. 30, 2011

USD ($)

Jun. 30, 2012

USD ($)

$ / shares

Jun. 30, 2011

USD ($)

Dec. 31, 2011

USD ($)

$ / shares

May 01, 2012

USD ($)

Restricted Common Unit Awards [Member]

$ 16.5

$ 13.2

$ 32.9

$ 25.0

Summary of awards activity, equity instruments other than options [Roll Forward]

$ 15.7

12.1

$ 30.5

23.5

Beginning of period (in units) | shares

3,868,216

Granted (in units) | shares

^[1],[2]

1,538,438

Vested (in units) | shares

^[1]

(1,236,352)

Forfeited (in units) | shares

(95,575)

End of period (in units) | shares

4,074,727

3,868,216

Restricted units outstanding, weighted-average grant date fair value [Roll Forward]

Weighted-average grant date fair value per unit, at beginning of period (in dollars per unit) | $ / shares

^[3]

$ 34.22

Granted weighted-average grant date fair value per unit (in dollars per unit) | $ / shares

^[1],[2],[3]

51.92

Vested weighted-average grant date fair value per unit (in dollars per unit) | $ / shares

^[1],[3]

34.77

Forfeited weighted-average grant date fair value per unit (in dollars per unit) | $ / shares

^[3]

38.43

Weighted-average grant date fair value per unit, at end of period (in dollars per unit) | $ / shares

^[3]

$ 40.64

$ 34.22

Summary of awards activity, equity instruments other than options, additional disclosures [Abstract]

Aggregate grant date fair value

$ 79.9

Estimated forfeiture rate (in hundredths)

3.25%

Cash distributions paid to restricted common unit holders

$ 3.0

2.7

$ 5.4

4.8

Total intrinsic value of our restricted common unit awards vesting during period

30.1

20.5

62.7

35.2

Recognition period for total unrecognized compensation cost

90.3

$ 90.3

2 years

Restricted Common Unit Awards [Member] | Minimum [Member]

Summary of awards activity, equity instruments other than options, additional disclosures [Abstract]

Grant date market price of common units (in dollars per unit) | $ / shares

$ 51.92

Restricted Common Unit Awards [Member] | Maximum [Member]

Summary of awards activity, equity instruments other than options, additional disclosures [Abstract]

Grant date market price of common units (in dollars per unit) | $ / shares

$ 52.26

Restricted Common Unit Awards [Member] | Enterprise [Member]

Unit Option Awards [Member]

85.7

$ 85.7

Summary of awards activity, options [Roll Forward]

$ 0.3

0.8

$ 1.0

1.7

Beginning of period (in units) | shares

3,753,420

Exercised (in units) | shares

(712,280)

Forfeited (in units) | shares

(130,000)

End of period (in units) | shares

2,911,140

3,753,420

Options outstanding, weighted-average strike price [Roll Forward]

Weighted average strike price, beginning of period (in dollars per unit) | $ / shares

$ 28.08

Weighted average strike price, exercised (in dollars per unit) | $ / shares

30.76

Weighted average strike price, forfeited (in dollars per unit) | $ / shares

27.12

Weighted average strike price, end of period (in dollars per unit) | $ / shares

$ 27.46

$ 28.08

Weighted average remaining contractual term

2 years 6 months

2 years 7 months 6 days

Aggregate intrinsic value

^[4]

$ 14.4

$ 11.1

Exercisable (in units) | shares

Exercisable - Weighted average remaining contractual term (in years) | Y

Exercisable - Aggregate intrinsic value

^[4]

$ 0.0

Total intrinsic value of unit option awards exercised during period

0.0

14.0

0.0

Cash received from EPCO in connection with the exercise of unit option awards

0.0

10.2

0.0

14.0

0.0

Recognition period for total unrecognized compensation cost

2.2

$ 2.2

1 year 1 month

Unit Option Awards [Member] | Enterprise [Member]

Other Equity-based Awards [Member]

2.0

$ 2.0

Unit Appreciation Rights [Member]

^[5]

$ 0.5

$ 0.3

$ 1.4

$ (0.2)

Summary of awards activity, equity instruments other than options [Roll Forward]

Beginning of period (in units) | shares

107,328

Vested (in units) | shares

(107,328)

End of period (in units) | shares

107,328

Accrued liability for UARs

$ 0.5

$ 1.4

Long-Term Incentive Plan (1998) [Member]

Remaining number of common units available to be issued as awards (in units) | shares

749,016

Long-Term Incentive Plan (2008) [Member]

Remaining number of common units available to be issued as awards (in units) | shares

5,038,468

[1]	Includes awards granted to the independent directors of the board of directors of Enterprise GP as part of their annual compensation for 2012. A total of 10,038 restricted common units were issued in February 2012 to the independent directors of Enterprise GP that immediately vested upon issuance.
[2]	The aggregate grant date fair value of restricted common unit awards issued in 2012 was $79.9 million based on a grant date market price ranging from $51.92 to $52.26 per unit. An estimated annual forfeiture rate of 3.25% was applied to these awards.
[3]	Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued.
[4]	Aggregate intrinsic value reflects fully vested unit options at the date indicated.
[5]	Primarily consists of unit appreciation rights ("UARs"), phantom units and similar awards.

Derivative Instruments, Hedging Activities and Fair Value Measurements (Details)
$ in Millions

1 Months Ended

3 Months Ended

6 Months Ended

Aug. 31, 2012

USD ($)

Feb. 29, 2012

USD ($)

Jun. 30, 2012

USD ($)

Bcf

MMBbls

Jun. 30, 2011

USD ($)

Jun. 30, 2012

USD ($)

Bcf

MMBbls

Jun. 30, 2011

USD ($)

Senior Notes AA [Member]

fixed-to-floating swaps

Rate Swap, fixed rate (in hundredths)

$ 750.0

Period of Hedge

1/2011 to 2/2016

3.20%

Rate Swap, floating rate (in hundredths)

1.50%

Undesignated Swaps [Member]

Fair value hedge

floating-to-fixed swaps

Rate Swap, fixed rate (in hundredths)

$ 600.0

Period of Hedge

5/2010 to 7/2014

2.00%

Rate Swap, floating rate (in hundredths)

0.50%

Interest Rate Swap [Member]

Mark-to-market

(Increase)/decrease in interest expense recorded due to interest rate swaps | $

$ 2.2

$ (2.2)

$ 5.0

$ 7.5

Future Debt Offering Tranche One [Member]

forward starting swaps

Expected Termination Date

$ 350.0

8/2012

Average Rate Locked (in hundredths)

3.70%

Future Debt Offering Tranche Two [Member]

Cash flow hedge

forward starting swaps

Expected Termination Date

$ 1,000.0

3/2013

Average Rate Locked (in hundredths)

3.70%

Natural gas processing: Forecasted natural gas purchases for plant thermal reduction (PTR) [Member]

Cash flow hedge

^[1],[2],[3]

15.3

Natural gas processing: Forecasted sales of NGLs [Member]

^[1]

Cash flow hedge

^[2],[3],[4]

1.6

Forecasted NGL sales designated as normal sales agreements

^[4]

Cash flow hedge

2.2

Octane enhancement: Forecasted purchases of NGLs [Member]

^[2],[3]

0.2

Octane enhancement: Forecasted sales of octane enhancement products [Member]

Cash flow hedge

^[2],[3]

2.0

Natural gas marketing: Forecasted sales of natural gas [Member]

Cash flow hedge

^[2],[3]

1.2

Natural gas marketing: Natural gas storage inventory management activities [Member]

Cash flow hedge

^[2],[3]

11.1

NGL marketing: Forecasted purchases of NGLs and related hydrocarbon products [Member]

Fair value hedge

^[2],[3]

3.2

Long Term Volume

^[2],[3]

0.5

NGL marketing: Forecasted sales of NGLs and related hydrocarbon products [Member]

Cash flow hedge

^[2],[3]

3.7

Long Term Volume

^[2],[3]

0.5

Refined products marketing: Forecasted purchases of refined products [Member]

Cash flow hedge

^[2],[3]

0.1

Refined products marketing: Forecasted sales of refined products [Member]

Cash flow hedge

^[2],[3]

0.5

Refined products marketing: Refined products inventory management activities [Member]

Cash flow hedge

^[2],[3]

0.2

Crude oil marketing: Forecasted purchases of crude oil [Member]

Fair value hedge

^[2],[3]

2.8

Crude oil marketing: Forecasted sales of crude oil [Member]

Cash flow hedge

^[2],[3]

4.1

Natural gas risk management activities [Member]

Cash flow hedge

^{[2],[3],[5],[6]}

241.0

Long Term Volume | Bcf

^{[2],[3],[5],[6]}

56.0

Current natural gas hedging volumes designated as an index plus or minus a discount | Bcf

^[5],[6]

Mark-to-market

62.5

Refined products risk management activities [Member]

^[2],[3],[6]

1.1

Crude oil risk management activities [Member]

^[6]

Mark-to-market

^[2],[3],[6]

5.7

Derivatives in cash flow hedging relationships [Member] | Future Debt Offering Tranche One [Member]

^[6]

Mark-to-market

Number of derivative instruments settled

Notional amount of settled derivative instruments | $

$ 350.0

Derivatives in cash flow hedging relationships [Member] | Forward Starting Swaps [Member]

Number of derivative instruments settled

Notional amount of settled derivative instruments | $

$ 500.0

Derivatives in fair value hedging relationships [Member] | Interest Rate Swap [Member]

Number of derivative instruments settled

Notional amount of settled derivative instruments | $

$ 800.0

Loss (gain) recognized due to settlement of derivative instruments | $

$ (37.7)

[1]	PTR represents the British thermal unit ("Btu") equivalent of the NGLs extracted from natural gas by a processing plant, and includes the natural gas used as plant fuel to extract those liquids, plant flare and other shortages.
[2]	The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is December 2013, March 2013 and October 2015, respectively.
[3]	Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes.
[4]	Forecasted sales of NGL volumes under natural gas processing exclude 2.2 MMBbls of additional hedges executed under contracts that have been designated as normal sales agreements.
[5]	Current volumes include approximately 62.5 Bcf of physical derivative instruments that are predominantly priced at an index plus a premium or minus a discount related to location differences.
[6]	Reflects the use of derivative instruments to manage risks associated with transportation, processing and storage assets.

Derivative Instruments, Hedging Activities and Fair Value Measurements, Derivative Fair Value Amounts (Details) - USD ($)
$ in Millions

Jun. 30, 2012

Dec. 31, 2011

Derivatives designated as hedging instruments [Member]

$ 177.4

$ 108.2

Derivatives designated as hedging instruments [Member] | Interest rate derivatives [Member]

307.3

321.2

45.2

87.9

Derivatives designated as hedging instruments [Member] | Interest rate derivatives [Member] | Other current assets [Member]

230.6

290.7

Derivatives designated as hedging instruments [Member] | Interest rate derivatives [Member] | Other assets [Member]

18.6

43.7

Derivatives designated as hedging instruments [Member] | Interest rate derivatives [Member] | Other current liabilities [Member]

26.6

44.2

Derivatives designated as hedging instruments [Member] | Interest rate derivatives [Member] | Other liabilities [Member]

230.6

163.6

Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member]

0.0

127.1

^[1]

132.2

20.3

Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member] | Other current assets [Member]

^[1]

76.7

30.5

Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member] | Other assets [Member]

127.4

20.3

Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member] | Other current liabilities [Member]

4.8

0.0

Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member] | Other liabilities [Member]

74.6

30.3

Derivatives not designated as hedging instruments [Member]

2.1

0.2

30.4

47.0

Derivatives not designated as hedging instruments [Member] | Interest rate derivatives [Member]

40.8

55.2

0.0

Derivatives not designated as hedging instruments [Member] | Interest rate derivatives [Member] | Other current assets [Member]

19.6

20.7

Derivatives not designated as hedging instruments [Member] | Interest rate derivatives [Member] | Other assets [Member]

0.0

Derivatives not designated as hedging instruments [Member] | Interest rate derivatives [Member] | Other current liabilities [Member]

0.0

Derivatives not designated as hedging instruments [Member] | Interest rate derivatives [Member] | Other liabilities [Member]

11.0

10.1

Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member]

8.6

10.6

30.4

47.0

Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Other current assets [Member]

21.2

34.5

Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Other assets [Member]

26.0

34.4

Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Other current liabilities [Member]

4.4

12.6

Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Other liabilities [Member]

19.4

32.5

Derivative Instruments, Gain (Loss) [Line Items]

$ 1.8

$ 2.0

[1]	Represents commodity derivative instrument transactions that have either not settled or have settled and cash has not been paid or received. Settled and unpaid or unreceived amounts are reflected in either accounts receivable or accounts payable depending on the outcome of the transaction.

Derivative Instruments, Hedging Activities and Fair Value Measurements, Gains and Losses on Derivative Instruments and Related Hedged Items (Details) - USD ($)
$ in Millions

1 Months Ended

3 Months Ended

6 Months Ended

Jul. 31, 2012

Jun. 30, 2012

Jun. 30, 2011

Jun. 30, 2012

Jun. 30, 2011

Aug. 01, 2012

Feb. 29, 2012

Dec. 31, 2011

Accumulated other comprehensive income (loss) related to interest rate derivative instruments

^[1]

$ (377.7)

$ (329.0)

Derivatives in fair value hedging relationships [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Gain/(Loss) Recognized in Income on Hedged Item

(11.8)

$ 19.5

(12.6)

$ 7.5

11.4

(20.8)

12.9

(10.8)

Derivatives in fair value hedging relationships [Member] | Interest rate derivatives [Member] | Location - Interest expense [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Gain/(Loss) Recognized in Income on Hedged Item

4.6

21.1

3.1

8.8

(4.5)

(21.0)

(3.4)

(9.7)

Derivatives in fair value hedging relationships [Member] | Commodity derivatives [Member] | Location - Revenue [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Gain/(Loss) Recognized in Income on Hedged Item

(16.4)

(1.6)

(15.7)

(1.3)

15.9

0.2

16.3

(1.1)

Derivatives in cash flow hedging relationships [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Change in Value Recognized in Other Comprehensive Income/(Loss) on Derivative (Effective Portion)

21.0

(81.8)

(9.7)

(219.1)

Gain/(Loss) Reclassified from Accumulated Other Comprehensive Income/(Loss) to Income (Effective Portion)

(17.9)

(76.3)

(42.6)

(146.7)

Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)

0.9

0.3

1.2

0.2

Derivatives in cash flow hedging relationships [Member] | Interest rate derivatives [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Change in Value Recognized in Other Comprehensive Income/(Loss) on Derivative (Effective Portion)

(84.0)

(60.1)

(55.1)

(46.0)

Derivatives in cash flow hedging relationships [Member] | Interest rate derivatives [Member] | Location - Interest expense [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Gain/(Loss) Reclassified from Accumulated Other Comprehensive Income/(Loss) to Income (Effective Portion)

(3.7)

(1.5)

(6.4)

(3.0)

Accumulated Other Comprehensive Loss related to interest rate derivative instruments expected to be reclassified to earnings in interest expense over the next twelve months

(26.2)

Derivatives in cash flow hedging relationships [Member] | Commodity derivatives [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Accumulated Other Comprehensive Income (Loss) related to commodity derivative instruments expected to be reclassified to earnings over the next twelve months

57.6

Derivatives in cash flow hedging relationships [Member] | Commodity derivatives [Member] | Location - Revenue [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Change in Value Recognized in Other Comprehensive Income/(Loss) on Derivative (Effective Portion)

99.8

(19.4)

60.2

(174.8)

Gain/(Loss) Reclassified from Accumulated Other Comprehensive Income/(Loss) to Income (Effective Portion)

(2.6)

(79.3)

(12.6)

(148.5)

Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)

0.9

0.3

0.9

0.2

Accumulated Other Comprehensive Income (Loss) related to commodity derivative instruments expected to be reclassified to earnings over the next twelve months

59.4

Derivatives in cash flow hedging relationships [Member] | Commodity derivatives [Member] | Location - Operating costs and expenses [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Change in Value Recognized in Other Comprehensive Income/(Loss) on Derivative (Effective Portion)

5.2

(2.3)

(14.8)

1.7

Gain/(Loss) Reclassified from Accumulated Other Comprehensive Income/(Loss) to Income (Effective Portion)

(11.6)

4.5

(23.6)

4.8

Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)

0.0

0.3

0.0

Accumulated Other Comprehensive Income (Loss) related to commodity derivative instruments expected to be reclassified to earnings over the next twelve months

(1.8)

Derivatives in cash flow hedging relationships [Member] | Future Debt Offering Tranche One [Member] | Interest rate derivatives [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Change in Value Recognized in Other Comprehensive Income/(Loss) on Derivative (Effective Portion)

$ (6.3)

Accumulated other comprehensive income (loss) related to interest rate derivative instruments

(63.9)

$ (70.2)

Derivatives in cash flow hedging relationships [Member] | Forward Starting Swaps [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Accumulated other comprehensive income (loss) related to interest rate derivative instruments

$ (115.3)

Derivatives not designated as hedging instruments [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Derivatives not designated as hedging instruments [Member] | Interest rate derivatives [Member] | Location - Interest expense [Member]

8.2

(2.4)

24.0

2.8

Derivative Instruments, Gain (Loss) [Line Items]

Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Location - Revenue [Member]

(1.1)

(11.9)

(3.3)

(10.5)

Derivative Instruments, Gain (Loss) [Line Items]

Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Location - Operating costs and expenses [Member]

9.3

9.5

30.1

13.3

Derivative Instruments, Gain (Loss) [Line Items]

$ 0.0

$ (2.8)

$ 0.0

[1]	See Note 4 for additional information regarding our derivative instruments.

Derivative Instruments, Hedging Activities and Fair Value Measurements, Fair Value Measurements (Details)
$ in Millions

3 Months Ended

6 Months Ended

Jun. 30, 2012

USD ($)

Mar. 31, 2012

USD ($)

Jun. 30, 2011

USD ($)

Mar. 31, 2011

USD ($)

Jun. 30, 2012

USD ($)

$ / gal

$ / Boe

$ / Btu

Jun. 30, 2011

USD ($)

Dec. 31, 2011

USD ($)

$ 9.1

$ 0.0

$ 14.5

$ 0.0

Unrealized gain (loss) recognized as a component of net income related to level 3 financial assets and liabilities

(2.0)

2.0

(1.9)

1.8

Reconciliation of changes in the fair value of Level 3 financial assets and liabilities [Roll Forward]

Balance, beginning of period

0.9

$ 0.4

0.4

$ (25.9)

0.4

(25.9)

Total gains (losses) included in:

Net income

^[1]

(1.3)

0.5

1.9

(0.5)

Other comprehensive income (loss)

6.0

0.5

0.0

16.2

Settlements

(0.7)

(0.5)

(0.2)

0.8

Transfers out of Level 3

0.0

^[2]

0.0

9.8

^[2]

Balance, end of period

4.9

$ 0.9

$ 2.1

$ 0.4

4.9

$ 2.1

Long-lived Fixed Assets Held For Sale [Member]

Carrying value prior to impairment

0.8

Property, Plant and Equipment [Member]

Carrying value prior to impairment

14.2

NGL Pipelines and Services [Member] | Property, Plant and Equipment [Member]

Onshore Crude Oil Pipelines and Services [Member] | Property, Plant and Equipment [Member]

8.0

Petrochemical and Refined Products Services [Member] | Long-lived Fixed Assets Held For Sale [Member]

6.2

0.3

Carrying Value [Member]

45.2

162.6

207.8

Debt obligations

14,580.0

$ 14,330.0

250.2

97.9

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]

348.1

207.8

348.1

Level 3 [Member]

7.9

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]

3.0

7.9

Level 3 [Member] | Liability Commodity Derivatives - Crude Oil [Member]

3.0

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]

2.0

2.0

$ 2.0

Discounted cash flow

Level 3 [Member] | Liability Commodity Derivatives - Crude Oil [Member] | Minimum [Member]

Forward commodity price

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]

Fair value inputs, forward commodity price (in dollars per unit) | $ / Boe

84.96

Level 3 [Member] | Liability Commodity Derivatives - Crude Oil [Member] | Maximum [Member]

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]

Fair value inputs, forward commodity price (in dollars per unit) | $ / Boe

88.71

Level 3 [Member] | Liability Commodity Derivatives Natural Gasoline [Member]

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]

0.0

$ 0.0

0.0

$ 0.0

Discounted cash flow

Level 3 [Member] | Liability Commodity Derivatives Natural Gasoline [Member] | Minimum [Member]

Forward commodity price

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]

Fair value inputs, forward commodity price (in dollars per unit) | $ / gal

1.83

Level 3 [Member] | Liability Commodity Derivatives Natural Gasoline [Member] | Maximum [Member]

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]

Fair value inputs, forward commodity price (in dollars per unit) | $ / gal

1.83

Level 3 [Member] | Liability Commodity Derivatives - Natural Gas [Member]

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]

0.1

$ 0.1

0.1

$ 0.1

Discounted cash flow

Level 3 [Member] | Liability Commodity Derivatives - Natural Gas [Member] | Minimum [Member]

Forward commodity price

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]

Fair value inputs, forward commodity price (in dollars per unit) | $ / Btu

3.90

Level 3 [Member] | Liability Commodity Derivatives - Natural Gas [Member] | Maximum [Member]

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]

Fair value inputs, forward commodity price (in dollars per unit) | $ / Btu

4.13

Level 3 [Member] | Liability Commodity Derivatives - Propane [Member]

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]

0.9

$ 0.9

0.9

$ 0.9

Discounted cash flow

Level 3 [Member] | Liability Commodity Derivatives - Propane [Member] | Minimum [Member]

Forward commodity price

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]

Fair value inputs, forward commodity price (in dollars per unit) | $ / gal

0.86

Level 3 [Member] | Liability Commodity Derivatives - Propane [Member] | Maximum [Member]

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]

Fair value inputs, forward commodity price (in dollars per unit) | $ / gal

0.92

Fair Value [Member]

Fair Value, Measurements, Recurring [Member] | Level 1 [Member]

Debt obligations

16,270.0

$ 16,270.0

$ 15,760.0

0.0

81.6

81.6

0.0

39.1

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]

39.1

81.6

Fair Value, Measurements, Recurring [Member] | Level 2 [Member]

39.1

45.2

73.1

118.3

250.2

55.8

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]

306.0

118.3

Fair Value, Measurements, Recurring [Member] | Level 3 [Member]

306.0

0.0

7.9

7.9

0.0

3.0

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]

3.0

7.9

Fair Value, Measurements, Nonrecurring [Member]

3.0

0.0

0.5

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]

0.0

Fair Value, Measurements, Nonrecurring [Member] | Petrochemical and Refined Products Services [Member]

0.5

Fair Value, Measurements, Nonrecurring [Member] | Level 1 [Member]

0.5

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]

0.0

Fair Value, Measurements, Nonrecurring [Member] | Level 1 [Member] | NGL Pipelines and Services [Member]

0.0

0.0

Fair Value, Measurements, Nonrecurring [Member] | Level 1 [Member] | Onshore Crude Oil Pipelines and Services [Member]

0.0

0.0

Fair Value, Measurements, Nonrecurring [Member] | Level 1 [Member] | Petrochemical and Refined Products Services [Member]

0.0

Fair Value, Measurements, Nonrecurring [Member] | Level 2 [Member]

0.0

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]

0.0

Fair Value, Measurements, Nonrecurring [Member] | Level 2 [Member] | NGL Pipelines and Services [Member]

0.0

0.0

Fair Value, Measurements, Nonrecurring [Member] | Level 2 [Member] | Onshore Crude Oil Pipelines and Services [Member]

0.0

0.0

Fair Value, Measurements, Nonrecurring [Member] | Level 2 [Member] | Petrochemical and Refined Products Services [Member]

0.0

Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member]

0.0

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]

0.5

Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | NGL Pipelines and Services [Member]

0.5

0.0

Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Onshore Crude Oil Pipelines and Services [Member]

0.0

0.0

Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Petrochemical and Refined Products Services [Member]

0.0

Asset Commodity derivatives - Propane [Member] | Level 3 [Member]

0.5

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]

4.7

4.7

$ 4.7

Discounted cash flow

Asset Commodity derivatives - Propane [Member] | Level 3 [Member] | Minimum [Member]

Forward commodity price

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]

Fair value inputs, forward commodity price (in dollars per unit) | $ / gal

0.86

Asset Commodity derivatives - Propane [Member] | Level 3 [Member] | Maximum [Member]

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]

Fair value inputs, forward commodity price (in dollars per unit) | $ / gal

0.92

Asset Commodity derivatives - Crude oil [Member] | Level 3 [Member]

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]

0.3

$ 0.3

0.3

$ 0.3

Discounted cash flow

Asset Commodity derivatives - Crude oil [Member] | Level 3 [Member] | Minimum [Member]

Forward commodity price

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]

Fair value inputs, forward commodity price (in dollars per unit) | $ / Boe

84.96

Asset Commodity derivatives - Crude oil [Member] | Level 3 [Member] | Maximum [Member]

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]

Fair value inputs, forward commodity price (in dollars per unit) | $ / Boe

88.71

Assets Commodity derivatives - Natural gas [Member] | Level 3 [Member]

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]

0.2

$ 0.2

0.2

$ 0.2

Discounted cash flow

Assets Commodity derivatives - Natural gas [Member] | Level 3 [Member] | Minimum [Member]

Forward commodity price

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]

Fair value inputs, forward commodity price (in dollars per unit) | $ / Btu

3.90

Assets Commodity derivatives - Natural gas [Member] | Level 3 [Member] | Maximum [Member]

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]

Fair value inputs, forward commodity price (in dollars per unit) | $ / Btu

4.13

Asset Commodity Derivatives Natural Gasoline [Member] | Level 3 [Member]

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]

2.7

$ 2.7

$ 2.7

Discounted cash flow

Asset Commodity Derivatives Natural Gasoline [Member] | Level 3 [Member] | Minimum [Member]

Forward commodity price

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]

Fair value inputs, forward commodity price (in dollars per unit) | $ / gal

1.83

Asset Commodity Derivatives Natural Gasoline [Member] | Level 3 [Member] | Maximum [Member]

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]

Fair value inputs, forward commodity price (in dollars per unit) | $ / gal

1.83

[1]	There were $2.0 million and $1.9 million of unrealized losses included in these amounts for the three and six months ended June 30, 2012, respectively. There were $2.0 million and $1.8 million of unrealized gains included in these amounts for the three and six months ended June 30, 2011, respectively.
[2]	Transfers out of Level 3 into Level 2 during 2011 were primarily due to the change in observability of forward NGL prices.

Inventories (Details) - USD ($)
$ in Millions

3 Months Ended

6 Months Ended

Jun. 30, 2012

Jun. 30, 2011

Jun. 30, 2012

Jun. 30, 2011

Dec. 31, 2011

Available-for-Sale Inventory by Product Type [Abstract]

NGLs

$ 553.4

$ 563.6

Petrochemicals and refined products

246.1

443.4

Crude oil

46.5

39.2

Natural gas

46.9

65.5

Summary of cost of sales and lower of cost or market adjustments [Abstract]

892.9

$ 1,111.7

Cost of sales

^[1]

8,195.2

$ 9,790.3

17,861.0

$ 18,609.6

Lower of cost or market adjustments

$ 8.0

$ 0.5

$ 13.9

$ 1.7

[1]

Cost of sales is a component of "Operating costs and expenses," as presented on our Unaudited Condensed Statements of Consolidated Operations. Period-to-period fluctuations in these amounts are primarily due to changes in energy commodity prices and sales volumes associated with our marketing activities.

Charge to cost of goods sold that represents the reduction of the carrying amount of inventory, generally attributable to obsolescence or market conditions.

Property, plant and equipment and accumulated depreciation [Abstract]

Property, Plant and Equipment (Details) - USD ($)
$ in Millions

3 Months Ended

6 Months Ended

Jun. 30, 2012

Jun. 30, 2011

Jun. 30, 2012

Jun. 30, 2011

Dec. 31, 2011

Less accumulated depreciation

$ 29,435.2

$ 27,429.6

5,674.6

5,238.0

Property, plant and equipment , net

23,760.6

22,191.6

Summary of depreciation expense and capitalized interest [Abstract]

Depreciation expense

^[1]

222.0

$ 189.8

434.0

$ 376.3

Capitalized interest

^[2]

29.5

$ 24.8

60.1

$ 42.0

Asset Retirement Obligations [Roll Forward]

ARO liability balance, December 31, 2011

112.0

Liabilities incurred during period

1.1

Liabilities settled during period

(5.9)

Revisions in estimated cash flows

8.9

Accretion expense

2.7

ARO liability balance, June 30, 2012

118.8

Capitalized costs, asset retirement costs

42.5

37.7

Forecasted accretion expense [Abstract]

Forecast accretion expense - Remainder of 2012

2.8

Forecast accretion expense - 2013

6.0

Forecast accretion expense - 2014

6.5

Forecast accretion expense - 2015

6.2

Forecast accretion expense - 2016

6.5

Plants, pipelines and facilities [Member]

Property, plant and equipment and accumulated depreciation [Abstract]

Plants, pipelines and facilities [Member] | Minimum [Member]

^[3]

24,105.7

$ 24,105.7

22,354.4

Property, plant and equipment and accumulated depreciation [Abstract]

Plants, pipelines and facilities [Member] | Maximum [Member]

^[3],[4]

3 years

Property, plant and equipment and accumulated depreciation [Abstract]

Underground and other storage facilities [Member]

^[3],[4]

45 years

Property, plant and equipment and accumulated depreciation [Abstract]

Underground and other storage facilities [Member] | Minimum [Member]

^[5]

1,455.9

$ 1,455.9

1,388.6

Property, plant and equipment and accumulated depreciation [Abstract]

Underground and other storage facilities [Member] | Maximum [Member]

^[5],[6]

5 years

Property, plant and equipment and accumulated depreciation [Abstract]

Platforms and facilities [Member]

^[5],[6]

40 years

Property, plant and equipment and accumulated depreciation [Abstract]

Platforms and facilities [Member] | Minimum [Member]

^[7]

637.5

$ 637.5

637.5

Property, plant and equipment and accumulated depreciation [Abstract]

Platforms and facilities [Member] | Maximum [Member]

^[7]

20 years

Property, plant and equipment and accumulated depreciation [Abstract]

Transportation equipment [Member]

^[7]

31 years

Property, plant and equipment and accumulated depreciation [Abstract]

Transportation equipment [Member] | Minimum [Member]

^[8]

158.4

$ 158.4

151.5

Property, plant and equipment and accumulated depreciation [Abstract]

Transportation equipment [Member] | Maximum [Member]

^[8]

3 years

Property, plant and equipment and accumulated depreciation [Abstract]

Property, plant and equipment and accumulated depreciation [Abstract]

^[8]

10 years

Marine vessels [Member]

Marine vessels [Member] | Minimum [Member]

^[9]

660.3

$ 660.3

615.9

Property, plant and equipment and accumulated depreciation [Abstract]

Marine vessels [Member] | Maximum [Member]

^[9]

15 years

Property, plant and equipment and accumulated depreciation [Abstract]

Property, plant and equipment and accumulated depreciation [Abstract]

^[9]

30 years

Land [Member]

Construction in progress [Member]

141.7

$ 141.7

136.1

Property, plant and equipment and accumulated depreciation [Abstract]

Processing plants [Member] | Minimum [Member]

$ 2,275.7

$ 2,145.6

Property, plant and equipment and accumulated depreciation [Abstract]

Processing plants [Member] | Maximum [Member]

20 years

Property, plant and equipment and accumulated depreciation [Abstract]

Pipelines and related equipment [Member] | Minimum [Member]

35 years

Property, plant and equipment and accumulated depreciation [Abstract]

Pipelines and related equipment [Member] | Maximum [Member]

5 years

Property, plant and equipment and accumulated depreciation [Abstract]

Terminal facilities [Member] | Minimum [Member]

45 years

Property, plant and equipment and accumulated depreciation [Abstract]

Terminal facilities [Member] | Maximum [Member]

10 years

Property, plant and equipment and accumulated depreciation [Abstract]

Office furniture and equipment [Member] | Minimum [Member]

35 years

Property, plant and equipment and accumulated depreciation [Abstract]

Office furniture and equipment [Member] | Maximum [Member]

3 years

Property, plant and equipment and accumulated depreciation [Abstract]

Buildings [Member] | Minimum [Member]

20 years

Property, plant and equipment and accumulated depreciation [Abstract]

Buildings [Member] | Maximum [Member]

20 years

Property, plant and equipment and accumulated depreciation [Abstract]

Laboratory and shop equipment [Member] | Minimum [Member]

40 years

Property, plant and equipment and accumulated depreciation [Abstract]

Laboratory and shop equipment [Member] | Maximum [Member]

5 years

Property, plant and equipment and accumulated depreciation [Abstract]

Underground storage facilities [Member] | Minimum [Member]

35 years

Property, plant and equipment and accumulated depreciation [Abstract]

Underground storage facilities [Member] | Maximum [Member]

5 years

Property, plant and equipment and accumulated depreciation [Abstract]

Storage tanks [Member] | Minimum [Member]

35 years

Property, plant and equipment and accumulated depreciation [Abstract]

Storage tanks [Member] | Maximum [Member]

10 years

Property, plant and equipment and accumulated depreciation [Abstract]

Water wells [Member] | Minimum [Member]

40 years

Property, plant and equipment and accumulated depreciation [Abstract]

Water wells [Member] | Maximum [Member]

5 years

Property, plant and equipment and accumulated depreciation [Abstract]

Schedule of Equity Method Investments [Line Items]

35 years

[1]	Depreciation expense is a component of "Costs and expenses" as presented on our Unaudited Condensed Statements of Consolidated Operations.
[2]	We capitalize interest cost incurred on funds used to construct property, plant and equipment. The capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset's estimated useful life as a component of depreciation expense. Capitalized interest reduces interest expense during the period it is recorded.
[3]	Plants and pipelines include processing plants; NGL, natural gas, crude oil and petrochemical and refined products pipelines; terminal loading and unloading facilities; office furniture and equipment; buildings; laboratory and shop equipment and related assets.
[4]	In general, the estimated useful lives of major assets within this category are: processing plants, 20-35 years; pipelines and related equipment, 5-45 years; terminal facilities, 10-35 years; office furniture and equipment, 3-20 years; buildings, 20-40 years; and laboratory and shop equipment, 5-35 years.
[5]	Underground and other storage facilities include underground product storage caverns; above ground storage tanks; water wells and related assets.
[6]	In general, the estimated useful lives of assets within this category are: underground storage facilities, 5-35 years; storage tanks, 10-40 years; and water wells, 5-35 years.
[7]	Platforms and facilities include offshore platforms and related facilities and other associated assets located in the Gulf of Mexico.
[8]	Transportation equipment includes tractor-trailer tank trucks and other vehicles and similar assets used in our operations.
[9]	Marine vessels include tow boats, barges and related equipment used in our marine transportation business.

Investments in Unconsolidated Affiliates (Details) - USD ($)
$ in Millions

1 Months Ended

3 Months Ended

6 Months Ended

Jan. 31, 2012

Jun. 30, 2012

Apr. 27, 2012

Jun. 30, 2011

Jun. 30, 2012

Jun. 30, 2011

Dec. 31, 2011

Gain on the sale of Energy Transfer Equity common units

$ 913.2

$ 1,859.6

$ 5.4

Investment in equity securities - available-for-sale

Gain on sales of Energy Transfer Equity common units

^[1]

15.5

0.0

68.8

0.0

Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]

Unamortized excess cost amounts by business segment [Abstract]

11.3

11.1

21.2

27.3

Equity method investment tangible and intangible asset amortization expense

60.1

1,180.6

$ 0.7

9.1

$ 1.8

19.0

Energy Transfer Equity [Member]

Schedule of Equity Method Investments [Line Items]

Ownership interest (in hundredths)

^[2]

0.00%

NGL Pipelines and Services [Member]

Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]

Unamortized excess cost amounts by business segment [Abstract]

$ 3.8

6.2

$ 9.0

12.1

Equity method investment tangible and intangible asset amortization expense

24.2

24.7

0.3

0.2

0.5

Summarized income statement information of unconsolidated affiliates [Abstract]

71.5

116.4

182.4

216.5

15.3

30.5

42.3

53.9

NGL Pipelines and Services [Member] | Venice Energy Service Company LLC [Member]

$ 15.2

30.6

$ 42.2

54.0

Schedule of Equity Method Investments [Line Items]

13.10%

NGL Pipelines and Services [Member] | K/D/S Promix, LLC [Member]

$ 31.1

35.5

Schedule of Equity Method Investments [Line Items]

50.00%

NGL Pipelines and Services [Member] | Baton Rouge Fractionators LLC [Member]

$ 40.9

40.7

Schedule of Equity Method Investments [Line Items]

32.20%

NGL Pipelines and Services [Member] | Skelly-Belvieu Pipeline Company, LLC [Member]

$ 20.6

21.0

Schedule of Equity Method Investments [Line Items]

50.00%

NGL Pipelines and Services [Member] | Texas Express Pipeline LLC [Member]

$ 37.4

35.0

Schedule of Equity Method Investments [Line Items]

35.00%

NGL Pipelines and Services [Member] | Front Range Pipeline LLC [Member]

$ 39.2

13.9

Schedule of Equity Method Investments [Line Items]

33.30%

NGL Pipelines and Services [Member] | Texas Express Gathering LLC [Member]

$ 6.3

0.0

Schedule of Equity Method Investments [Line Items]

^[3]

45.00%

Onshore Natural Gas Pipelines And Services [Member]

^[3]

$ 8.9

0.0

Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]

Summarized income statement information of unconsolidated affiliates [Abstract]

1.2

1.5

2.6

2.7

2.9

54.7

5.7

90.2

1.9

2.7

3.7

5.3

Onshore Natural Gas Pipelines And Services [Member] | Evangeline [Member]

$ 1.9

2.7

$ 3.7

5.3

Schedule of Equity Method Investments [Line Items]

^[4]

0.00%

Onshore Natural Gas Pipelines And Services [Member] | White River Hub, LLC [Member]

^[4]

$ 0.0

4.4

Schedule of Equity Method Investments [Line Items]

50.00%

Onshore Crude Oil Pipelines and Services [Member]

$ 25.5

25.7

Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]

Unamortized excess cost amounts by business segment [Abstract]

3.6

(1.6)

4.1

(2.1)

Equity method investment tangible and intangible asset amortization expense

18.9

19.2

0.1

0.2

0.3

0.4

Summarized income statement information of unconsolidated affiliates [Abstract]

21.5

9.6

33.8

20.8

7.4

(2.1)

8.2

(1.6)

Onshore Crude Oil Pipelines and Services [Member] | Seaway Crude Pipeline Company [Member]

$ 7.3

(2.1)

$ 8.1

(1.6)

Schedule of Equity Method Investments [Line Items]

50.00%

Offshore Pipelines And Services [Member]

$ 179.2

170.7

Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]

Unamortized excess cost amounts by business segment [Abstract]

4.1

6.6

11.0

14.9

Equity method investment tangible and intangible asset amortization expense

14.2

14.8

0.3

0.6

Summarized income statement information of unconsolidated affiliates [Abstract]

39.1

43.7

80.2

90.0

12.8

17.7

31.9

36.6

Offshore Pipelines And Services [Member] | Poseidon Oil Pipeline Company, LLC [Member]

$ 12.5

17.5

$ 30.9

36.2

Schedule of Equity Method Investments [Line Items]

36.00%

Offshore Pipelines And Services [Member] | Cameron Highway Oil Pipeline Company [Member]

$ 50.6

55.4

Schedule of Equity Method Investments [Line Items]

50.00%

Offshore Pipelines And Services [Member] | Deepwater Gateway LLC [Member]

$ 218.2

222.8

Schedule of Equity Method Investments [Line Items]

50.00%

Offshore Pipelines And Services [Member] | Neptune Pipeline Company, LLC [Member]

$ 93.7

94.6

Schedule of Equity Method Investments [Line Items]

25.70%

Offshore Pipelines And Services [Member] | Southeast Keathley Canyon Pipeline Company, LLC [Member]

$ 48.3

51.1

Schedule of Equity Method Investments [Line Items]

50.00%

Petrochemical and Refined Products Services [Member]

$ 51.7

1.0

Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]

Unamortized excess cost amounts by business segment [Abstract]

(1.4)

(4.3)

(7.9)

(9.3)

Equity method investment tangible and intangible asset amortization expense

2.8

2.9

0.0

0.1

0.0

Summarized income statement information of unconsolidated affiliates [Abstract]

5.9

9.2

11.3

19.3

(0.3)

(5.4)

(9.7)

(12.4)

Petrochemical and Refined Products Services [Member] | Baton Rouge Propylene Concentrator, LLC [Member]

$ (2.4)

(7.6)

$ (13.8)

(16.8)

Schedule of Equity Method Investments [Line Items]

30.00%

Petrochemical and Refined Products Services [Member] | Centennial Pipeline LLC [Member]

$ 8.9

9.5

Schedule of Equity Method Investments [Line Items]

50.00%

Petrochemical and Refined Products Services [Member] | Other Unconsolidated Affiliates [Member]

$ 49.4

51.8

Schedule of Equity Method Investments [Line Items]

Other Investment [Member]

^[5]

3.3

3.4

Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]

Unamortized excess cost amounts by business segment [Abstract]

^[6]

0.0

2.7

2.4

9.0

Equity method investment tangible and intangible asset amortization expense

^[7]

0.0

1,119.0

^[8]

0.0

8.4

0.3

17.5

Summarized income statement information of unconsolidated affiliates [Abstract]

0.0

1,974.9

0.0

3,964.0

0.0

260.6

0.0

624.8

Other Investment [Member] | Energy Transfer Equity [Member]

0.0

$ 66.3

0.0

$ 154.9

Schedule of Equity Method Investments [Line Items]

Number of common units owned accounted for under equity method (in units)

^[2]

$ 0.0

0.0

$ 1,023.1

29,303,514

Number of Energy Transfer Equity common units sold (in units)

22,762,636

4,450,000

Proceeds from the sale of Energy Transfer Equity common units

$ 825.1

$ 165.8

Gain on the sale of Energy Transfer Equity common units

$ 27.5

5.4

Investment in equity securities - available-for-sale

Number of Energy Transfer Equity common units sold (in units)

6,540,878

Proceeds from the sale of available-for-sale securities

$ 270.2

Gain on the sale of Energy Transfer Equity common units

$ 41.3

Gain on sales of Energy Transfer Equity common units

$ 15.5

$ 68.8

[1]	See Note 7 for information regarding our previously held investment in Energy Transfer Equity.
[2]	We ceased using the equity method to account for our investment in Energy Transfer Equity limited partner units effective January 18, 2012 and began accounting for them as available-for-sale securities. We completed the sale of the remaining Energy Transfer Equity units in April 2012 (see below).
[3]	In April 2012, we, along with Enbridge Midcoast Energy, LP (“Enbridge”) and WGR Asset Holding Company LLC formed a new joint venture, TEG, to design and construct two gas gathering systems to complement the Texas Express Pipeline. Enbridge will construct and operate the systems, which are expected to begin service in the second quarter of 2013.
[4]	In June 2012, we acquired the remaining ownership interests in Evangeline and it became a wholly owned subsidiary of ours.
[5]	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.
[6]	With respect to the six months ended June 30, 2012, the amount presented reflects our equity in the income of Energy Transfer Equity from January 1, 2012 to January 18, 2012.
[7]	On January 18, 2012, we discontinued using the equity method to account for our investment in Energy Transfer Equity common units and began accounting for this investment as an available-for-sale security. As a result, we no longer recognized any excess cost amounts associated with this investment.
[8]	Reflects amortization of excess cost amounts related to our investment in Energy Transfer Equity from January 1, 2012 through January 18, 2012, which is the date we ceased using the equity method to account for this investment.

Intangible Assets and Goodwill (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011
Identifiable intangible assets [Abstract]
Gross Value	$ 2,638.5		$ 2,638.5		$ 2,646.6
Accum. Amort.	(1,019.3)		(1,019.3)		(990.4)
Carrying Value	1,619.2		1,619.2		1,656.2
Amortization Expense	31.3	$ 37.4	63.6	$ 75.1
Forecasted amortization expense [Abstract]
Remainder of 2012	60.0		60.0
2013	111.6		111.6
2014	107.1		107.1
2015	106.6		106.6
2016	107.8		107.8
NGL Pipelines and Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	625.5		625.5		639.2
Accum. Amort.	(285.1)		(285.1)		(297.9)
Carrying Value	340.4		340.4		341.3
Amortization Expense	9.6	10.0	19.8	20.4
NGL Pipelines and Services [Member] \| Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	340.8		340.8		340.8
Accum. Amort.	(138.0)		(138.0)		(128.2)
Carrying Value	202.8		202.8		212.6
NGL Pipelines and Services [Member] \| Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	284.7		284.7		298.4
Accum. Amort.	(147.1)		(147.1)		(169.7)
Carrying Value	137.6		137.6		128.7
Onshore Natural Gas Pipelines And Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	1,631.9		1,631.9		1,628.4
Accum. Amort.	(532.2)		(532.2)		(500.6)
Carrying Value	1,099.7		1,099.7		1,127.8
Amortization Expense	15.8	20.2	31.6	40.1
Onshore Natural Gas Pipelines And Services [Member] \| Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	1,163.6		1,163.6		1,163.6
Accum. Amort.	(230.5)		(230.5)		(209.7)
Carrying Value	933.1		933.1		953.9
Onshore Natural Gas Pipelines And Services [Member] \| Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	468.3		468.3		464.8
Accum. Amort.	(301.7)		(301.7)		(290.9)
Carrying Value	166.6		166.6		173.9
Onshore Crude Oil Pipelines and Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	10.1		10.1		10.1
Accum. Amort.	(4.6)		(4.6)		(4.3)
Carrying Value	5.5		5.5		5.8
Amortization Expense	0.1	0.1	0.3	0.2
Onshore Crude Oil Pipelines and Services [Member] \| Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	9.7		9.7		9.7
Accum. Amort.	(4.4)		(4.4)		(4.1)
Carrying Value	5.3		5.3		5.6
Onshore Crude Oil Pipelines and Services [Member] \| Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	0.4		0.4		0.4
Accum. Amort.	(0.2)		(0.2)		(0.2)
Carrying Value	0.2		0.2		0.2
Offshore Pipelines And Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	207.0		207.0		207.0
Accum. Amort.	(134.7)		(134.7)		(129.5)
Carrying Value	72.3		72.3		77.5
Amortization Expense	2.6	2.8	5.2	5.8
Offshore Pipelines And Services [Member] \| Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	205.8		205.8		205.8
Accum. Amort.	(134.3)		(134.3)		(129.2)
Carrying Value	71.5		71.5		76.6
Offshore Pipelines And Services [Member] \| Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	1.2		1.2		1.2
Accum. Amort.	(0.4)		(0.4)		(0.3)
Carrying Value	0.8		0.8		0.9
Petrochemical and Refined Products Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	164.0		164.0		161.9
Accum. Amort.	(62.7)		(62.7)		(58.1)
Carrying Value	101.3		101.3		103.8
Amortization Expense	3.2	$ 4.3	6.7	$ 8.6
Petrochemical and Refined Products Services [Member] \| Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	104.3		104.3		104.3
Accum. Amort.	(30.9)		(30.9)		(28.4)
Carrying Value	73.4		73.4		75.9
Petrochemical and Refined Products Services [Member] \| Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	59.7		59.7		57.6
Accum. Amort.	(31.8)		(31.8)		(29.7)
Carrying Value	$ 27.9		$ 27.9		$ 27.9

Debt Obligations (Details) - USD ($)
$ in Millions

6 Months Ended

Jun. 30, 2012

Aug. 13, 2012

Aug. 08, 2012

Feb. 29, 2012

Dec. 31, 2011

$ 15,009.7

$ 14,482.7

Change in fair value of debt hedged in fair value hedging relationship

^[1]

39.7

73.8

Unamortized discounts, net of premiums

(32.6)

(30.0)

Unamortized deferred net gains related to terminated interest rate swaps

^[1]

29.9

2.9

Total other, non-principal amounts

37.0

46.7

Less current maturities of debt

(1,700.0)

(500.0)

Total long-term debt

13,346.7

14,029.4

EPO Letter of credit related to commodity derivative instruments

500.0

1,200.0

1,150.0

650.0

1,177.0

10,332.7

15,009.7

14,482.7

77.5

Total principal amount of senior debt obligations [Member]

13,477.0

12,950.0

Revolving Credit Facility [Member]

13,477.0

12,950.0

427.0

0.0

0.0

0.0

0.0

427.0

0.0

427.0

Senior Notes [Member]

13,050.0

Junior Subordinated Notes [Member]

500.0

1,200.0

1,150.0

650.0

750.0

8,800.0

13,050.0

1,532.7

EPO Senior Notes S [Member]

0.0

0.0

0.0

0.0

0.0

1,532.7

1,532.7

$ 0.0

490.5

fixed

7.625%

February 2012

EPO Senior Notes P [Member]

$ 0.0

490.5

$ 500.0

500.0

fixed

4.60%

August 2012

EPO Senior Notes C [Member]

$ 500.0

500.0

$ 350.0

350.0

fixed

6.375%

February 2013

EPO Senior Notes T [Member]

$ 350.0

350.0

$ 182.5

182.5

fixed

6.125%

February 2013

EPO Senior Notes M [Member]

$ 182.5

182.5

$ 400.0

400.0

fixed

5.65%

April 2013

EPO Senior Notes U [Member]

$ 400.0

400.0

$ 237.6

237.6

fixed

5.90%

April 2013

EPO Senior Notes O [Member]

$ 237.6

237.6

$ 500.0

500.0

fixed

9.75%

January 2014

EPO Senior Notes G [Member]

$ 500.0

500.0

$ 650.0

650.0

fixed

5.60%

October 2014

EPO Senior Notes I [Member]

$ 650.0

650.0

$ 250.0

250.0

fixed

5.00%

March 2015

EPO Senior Notes X [Member]

$ 250.0

250.0

$ 400.0

400.0

fixed

3.70%

June 2015

EPO Senior Notes AA [Member]

$ 400.0

400.0

$ 750.0

750.0

fixed

3.20%

February 2016

EPO $3.5 Billion Multi-Year Revolving Credit Facility [Member]

$ 750.0

750.0

$ 427.0

150.0

variable

September 2016

Maximum borrowing capacity

$ 427.0

150.0

$ 3,500.0

Information regarding variable interest rates paid [Abstract]

Variable Interest Rates Paid, Minimum (in hundredths)

1.54%

Variable Interest Rates Paid, Maximum (in hundredths)

3.63%

Weighted-Average Interest Rate Paid (in hundredths)

1.61%

EPO Senior Notes L [Member]

$ 800.0

800.0

fixed

6.30%

September 2017

EPO Senior Notes V [Member]

$ 800.0

800.0

$ 349.7

349.7

fixed

6.65%

April 2018

EPO Senior Notes N [Member]

$ 349.7

349.7

$ 700.0

700.0

fixed

6.50%

January 2019

EPO Senior Notes Q [Member]

$ 700.0

700.0

$ 500.0

500.0

fixed

5.25%

January 2020

EPO Senior Notes Y [Member]

$ 500.0

500.0

$ 1,000.0

1,000.0

fixed

5.20%

September 2020

EPO Senior Notes CC [Member]

$ 1,000.0

1,000.0

$ 650.0

650.0

fixed

4.05%

February 2022

EPO Senior Notes D [Member]

$ 650.0

650.0

$ 500.0

500.0

fixed

6.875%

March 2033

EPO Senior Notes H [Member]

$ 500.0

500.0

$ 350.0

350.0

fixed

6.65%

October 2034

EPO Senior Notes J [Member]

$ 350.0

350.0

$ 250.0

250.0

fixed

5.75%

March 2035

EPO Senior Notes W [Member]

$ 250.0

250.0

$ 399.6

399.6

fixed

7.55%

April 2038

EPO Senior Notes R [Member]

$ 399.6

399.6

$ 600.0

600.0

fixed

6.125%

October 2039

EPO Senior Notes Z [Member]

$ 600.0

600.0

$ 600.0

600.0

fixed

6.45%

September 2040

EPO Senior Notes BB [Member]

$ 600.0

600.0

$ 750.0

750.0

fixed

5.95%

February 2041

EPO Senior Notes DD [Member]

$ 750.0

750.0

$ 600.0

600.0

fixed

5.70%

February 2042

EPO Senior Notes EE [Member]

$ 600.0

600.0

$ 750.0

0.0

fixed

4.85%

August 2042

$ 750.0

0.0

$ 750.0

Debt issued as percent of principal amount (in hundredths)

$ 750.0

99.542%

Maturity term (in years)

TEPPCO Senior Notes 1 [Member]

$ 0.0

9.5

fixed

7.625%

February 2012

TEPPCO Senior Notes 2 [Member]

$ 0.0

9.5

$ 17.5

17.5

fixed

6.125%

February 2013

TEPPCO Senior Notes 3 [Member]

$ 17.5

17.5

$ 12.4

12.4

fixed

5.90%

April 2013

TEPPCO Senior Notes 4 [Member]

$ 12.4

12.4

$ 0.3

0.3

fixed

6.65%

April 2018

TEPPCO Senior Notes 5 [Member]

$ 0.3

0.3

$ 0.4

0.4

fixed

7.55%

April 2038

EPO Junior Subordinated Notes A [Member]

$ 0.4

0.4

$ 550.0

550.0

fixed/variable

August 2066

EPO Junior Subordinated Notes C [Member]

$ 550.0

550.0

$ 285.8

285.8

fixed/variable

June 2067

EPO Junior Subordinated Notes B [Member]

$ 285.8

285.8

$ 682.7

682.7

fixed/variable

January 2068

TEPPCO Junior Subordinated Notes [Member]

$ 682.7

682.7

$ 14.2

14.2

fixed/variable

June 2067

EPO Senior Notes FF [Member]

$ 14.2

$ 650.0

EPO Senior Notes GG [Member]

650.0

1,100.0

Commercial Paper [Member]

$ 1,100.0

Maximum borrowing capacity

$ 2,000.0

[1]	See Note 4 for information regarding our interest rate hedging activities.

Equity and Distributions (Details) - USD ($)
$ / shares in Units, $ in Millions

3 Months Ended

6 Months Ended

Jun. 30, 2012

Mar. 31, 2012

Jun. 30, 2011

Jun. 30, 2012

Jun. 30, 2011

Dec. 31, 2011

Net Cash Proceeds from Sale of Common Units [Abstract]

Accumulated Other Comprehensive Income (Loss) [Abstract]

$ 57.7

$ 45.1

Commodity derivative instruments

^[1]

$ 60.2

60.2

$ (21.4)

Interest rate derivative instruments

^[1]

(377.7)

(329.0)

Foreign currency translation adjustment

^[2]

1.7

Pension and postretirement benefit plans

(2.9)

(1.7)

Other

0.0

(1.0)

Total accumulated other comprehensive loss

(318.7)

(351.4)

Components of noncontrolling interests [Abstract]

Components of net income attributable to noncontrolling interests [Abstract]

^[3]

109.8

$ 105.9

Former owners of Duncan Energy Partners

0.0

$ 9.4

0.0

17.3

0.9

5.4

5.1

11.3

Cash distributions paid to noncontrolling interests:

$ 0.9

$ 14.8

5.1

28.6

Former owners of Duncan Energy Partners

0.0

21.9

Total cash distributions paid to noncontrolling interests

8.1

12.9

8.1

34.8

Cash contributions from noncontrolling interests:

Former owners of Duncan Energy Partners

0.0

1.5

Total cash contributions from noncontrolling interests

5.9

1.1

$ 5.9

$ 2.6

Distribution Reinvestment Plan [Member]

Summary of changes in outstanding units [Roll Forward]

Common units issued in connection with DRIP and EUPP (in units)

1,198,552

Registration Statements and Equity Offerings [Line Items]

Maximum common units authorized for issuance (in units)

70,000,000

Remaining units available for issuance (in units)

24,974,588

Net Cash Proceeds from Sale of Common Units [Abstract]

1,198,552

Summary of changes in outstanding units [Roll Forward]

$ 58.0

Enterprise EUPP [Member]

Common units issued in connection with DRIP and EUPP (in units)

72,057

Registration Statements and Equity Offerings [Line Items]

Maximum common units authorized for issuance (in units)

440,879

Remaining units available for issuance (in units)

358,791

Net Cash Proceeds from Sale of Common Units [Abstract]

72,057

2012 Registration [Member]

$ 3.7

Registration Statements and Equity Offerings [Line Items]

Maximum common units authorized for issuance

$ 1,000.0

Cash Distribution [Member] | Enterprise [Member]

Distributions to Partners [Abstract]

Distribution Per Common Unit (in dollars per unit)

$ 0.6350

$ 0.6275

Record Date

Jul. 31, 2012

Apr. 30, 2012

Payment Date

Aug. 08, 2012

May 09, 2012

Number of Designated Units (in units)

26,130,000

Common units [Member]

Summary of changes in outstanding units [Roll Forward]

Beginning Balance (in units)

881,620,418

Common units issued in connection with DRIP and EUPP (in units)

1,270,609

Common units issued in connection with equity-based awards (in units)

214,492

Restricted common units awards issued (in units)

1,538,438

Forfeiture of restricted common unit awards (in units)

(95,575)

Acquisition of treasury units in connection with vesting of equity-based awards (in units)

(373,391)

Cancellation of treasury units (in units)

Ending Balance (in units)

884,174,991

Conversion of restricted units to common units (in units)

1,236,352

Net Cash Proceeds from Sale of Common Units [Abstract]

Summary of changes in outstanding units [Roll Forward]

1,270,609

Class B units [Member]

Beginning Balance (in units)

4,520,431

Common units issued in connection with DRIP and EUPP (in units)

Common units issued in connection with equity-based awards (in units)

Restricted common units awards issued (in units)

Forfeiture of restricted common unit awards (in units)

Acquisition of treasury units in connection with vesting of equity-based awards (in units)

Cancellation of treasury units (in units)

Ending Balance (in units)

4,520,431

Net Cash Proceeds from Sale of Common Units [Abstract]

Summary of changes in outstanding units [Roll Forward]

Treasury Units [Member]

Beginning Balance (in units)

Common units issued in connection with DRIP and EUPP (in units)

Common units issued in connection with equity-based awards (in units)

Restricted common units awards issued (in units)

Forfeiture of restricted common unit awards (in units)

Acquisition of treasury units in connection with vesting of equity-based awards (in units)

373,391

Cancellation of treasury units (in units)

(373,391)

Ending Balance (in units)

Net Cash Proceeds from Sale of Common Units [Abstract]

Number of active reportable segments

[1]	See Note 4 for additional information regarding our derivative instruments.
[2]	Relates to transactions of a Canadian subsidiary.
[3]	Represents third party ownership interests in joint ventures that we consolidate, including Tri-States NGL Pipeline L.L.C., Independence Hub LLC, Rio Grande Pipeline Company and Wilprise Pipeline Company LLC.

Business Segments (Details)
$ in Millions

3 Months Ended

6 Months Ended

Jun. 30, 2012

USD ($)

Jun. 30, 2011

USD ($)

Jun. 30, 2012

USD ($)

Jun. 30, 2011

USD ($)

Dec. 31, 2011

USD ($)

Business Segments [Abstract]

Less: Operating costs and expenses

$ 9,789.8

$ 11,216.5

$ 21,042.3

$ 21,400.2

(9,009.5)

(10,533.3)

(19,476.7)

(20,070.4)

11.3

11.1

21.2

27.3

^[1]

261.3

233.3

515.9

464.1

Operating lease expenses paid by EPCO

9.1

0.0

14.5

0.0

0.0

0.1

0.0

0.3

^[2]

(1.3)

(5.2)

(3.8)

(23.6)

(27.7)

0.0

(27.7)

0.0

Gain on the sale of Energy Transfer Equity common units

1,033.0

922.5

2,085.7

1,797.9

5.4

Reconciliation of total Segment Gross Operating Margin [Abstract]

Adjustments to reconcile total segment gross operating margin to operating income:

1,033.0

922.5

2,085.7

1,797.9

^[1]

(261.3)

(233.3)

(515.9)

(464.1)

Operating lease expenses paid by EPCO

(9.1)

0.0

(14.5)

0.0

0.0

(0.1)

0.0

(0.3)

General and administrative costs

^[2]

1.3

5.2

3.8

23.6

27.7

0.0

27.7

0.0

(42.5)

(50.4)

(88.8)

(88.3)

Operating income

749.1

643.9

1,498.0

1,268.8

Other expense, net

(173.4)

(188.0)

(301.2)

(371.3)

Income before income taxes

575.7

455.9

1,196.8

897.5

9,764.2

11,072.3

20,985.9

21,005.9

25.6

144.2

56.4

394.3

0.0

Equity in income (loss) of unconsolidated affiliates

9,789.8

11,216.5

21,042.3

21,400.2

11.3

11.1

21.2

27.3

1,033.0

922.5

2,085.7

1,797.9

28,385.3

$ 27,799.7

Investments in unconsolidated affiliates (see Note 7)

23,760.6

22,191.6

913.2

1,859.6

1,619.2

1,656.2

2,092.3

9,789.8

11,216.5

21,042.3

21,400.2

Operating costs and expenses:

Cost of sales

^[3]

8,195.2

9,790.3

17,861.0

18,609.6

^[1]

261.3

233.3

515.9

464.1

^[2]

(1.3)

(5.2)

(3.8)

(23.6)

(27.7)

0.0

(27.7)

0.0

Other operating costs and expenses

9.1

0.0

14.5

0.0

^[4]

572.9

514.9

1,116.8

1,020.3

General and administrative costs

42.5

50.4

88.8

88.3

Total costs and expenses (see Note 11)

9,052.0

10,583.7

19,565.5

20,158.7

NGL Pipelines and Services [Member]

3,332.5

4,036.9

7,687.0

8,293.7

3.8

6.2

9.0

12.1

Reconciliation of total Segment Gross Operating Margin [Abstract]

565.8

497.7

1,220.7

1,002.1

565.8

497.7

1,220.7

1,002.1

3,327.9

3,960.1

7,682.0

8,015.5

4.6

76.8

5.0

278.2

2,276.5

3,228.2

5,094.7

6,702.8

Equity in income (loss) of unconsolidated affiliates

5,609.0

7,265.1

12,781.7

14,996.5

3.8

6.2

9.0

12.1

565.8

497.7

1,220.7

1,002.1

8,534.7

7,966.4

Investments in unconsolidated affiliates (see Note 7)

7,668.7

7,137.8

184.4

146.1

340.4

341.3

341.2

Sales of NGLs and related products

3,133.9

3,832.2

7,249.2

7,889.9

198.6

204.7

437.8

403.8

Onshore Natural Gas Pipelines And Services [Member]

3,332.5

4,036.9

7,687.0

8,293.7

720.4

927.3

1,554.0

1,843.9

1.2

1.5

2.6

2.7

Reconciliation of total Segment Gross Operating Margin [Abstract]

175.8

161.1

382.0

320.3

175.8

161.1

382.0

320.3

700.9

862.5

1,505.8

1,734.2

19.5

64.8

48.2

109.7

179.0

253.9

402.7

524.8

Equity in income (loss) of unconsolidated affiliates

899.4

1,181.2

1,956.7

2,368.7

1.2

1.5

2.6

2.7

175.8

161.1

382.0

320.3

10,419.1

9,949.6

Investments in unconsolidated affiliates (see Note 7)

8,997.6

8,495.4

25.5

30.1

1,099.7

1,127.8

296.3

209.6

207.8

470.6

411.7

Sales of natural gas

510.8

719.5

1,083.4

1,432.2

Onshore Crude Oil Pipelines and Services [Member]

720.4

927.3

1,554.0

1,843.9

4,188.7

4,281.6

8,662.3

7,652.2

3.6

(1.6)

4.1

(2.1)

Reconciliation of total Segment Gross Operating Margin [Abstract]

95.8

67.8

135.1

99.6

95.8

67.8

135.1

99.6

4,188.7

4,281.6

8,662.3

7,652.2

0.0

1,735.5

1,477.6

3,466.4

2,184.7

Equity in income (loss) of unconsolidated affiliates

5,924.2

5,759.2

12,128.7

9,836.9

3.6

(1.6)

4.1

(2.1)

95.8

67.8

135.1

99.6

1,315.5

944.6

Investments in unconsolidated affiliates (see Note 7)

819.6

456.9

179.2

170.7

5.5

5.8

311.2

14.7

23.7

40.7

46.1

Sales of crude oil

4,174.0

4,257.9

8,621.6

7,606.1

Offshore Pipelines And Services [Member]

4,188.7

4,281.6

8,662.3

7,652.2

49.0

63.7

105.1

128.1

4.1

6.6

11.0

14.9

Reconciliation of total Segment Gross Operating Margin [Abstract]

38.3

53.4

90.4

114.7

38.3

53.4

90.4

114.7

47.5

61.1

101.9

121.7

1.5

2.6

3.2

6.4

1.7

0.1

5.0

1.8

Equity in income (loss) of unconsolidated affiliates

50.7

63.8

110.1

129.9

4.1

6.6

11.0

14.9

38.3

53.4

90.4

114.7

2,001.9

2,000.9

Investments in unconsolidated affiliates (see Note 7)

1,385.0

1,416.4

462.5

424.9

72.3

77.5

82.1

49.0

60.9

103.6

121.7

Sales of natural gas

0.0

0.3

0.1

0.6

Sales of crude oil

0.0

2.5

1.4

5.8

Petrochemical and Refined Products Services [Member]

49.0

63.7

105.1

128.1

1,499.2

1,907.0

3,033.9

3,482.3

(1.4)

(4.3)

(7.9)

(9.3)

Reconciliation of total Segment Gross Operating Margin [Abstract]

157.3

139.8

255.1

252.2

157.3

139.8

255.1

252.2

1,499.2

1,907.0

3,033.9

3,482.3

0.0

438.7

445.5

878.6

918.6

Equity in income (loss) of unconsolidated affiliates

1,937.9

2,352.5

3,912.5

4,400.9

(1.4)

(4.3)

(7.9)

(9.3)

157.3

139.8

255.1

252.2

3,838.4

3,769.5

Investments in unconsolidated affiliates (see Note 7)

2,614.0

2,539.5

61.6

64.7

101.3

103.8

1,061.5

Sales of petrochemicals and refined products

182.4

188.3

365.9

380.8

1,316.8

1,718.7

2,668.0

3,101.5

Other Investment [Member]

1,499.2

1,907.0

3,033.9

3,482.3

^[5]

0.0

2.7

2.4

9.0

Reconciliation of total Segment Gross Operating Margin [Abstract]

0.0

2.7

2.4

9.0

0.0

2.7

2.4

9.0

0.0

0.0

0.0

Equity in income (loss) of unconsolidated affiliates

0.0

^[5]

0.0

2.7

2.4

9.0

0.0

2.7

2.4

9.0

0.0

1,023.1

Investments in unconsolidated affiliates (see Note 7)

0.0

0.0

1,023.1

0.0

Adjustments and Eliminations [Member]

0.0

0.0

Reconciliation of total Segment Gross Operating Margin [Abstract]

0.0

0.0

0.0

0.0

(4,631.4)

(5,405.3)

(9,847.4)

(10,332.7)

Equity in income (loss) of unconsolidated affiliates

(4,631.4)

(5,405.3)

(9,847.4)

(10,332.7)

0.0

0.0

$ 0.0

0.0

$ 0.0

2,275.7

2,145.6

Investments in unconsolidated affiliates (see Note 7)

2,275.7

2,145.6

0.0

0.0

Total revenue - related parties

$ 0.0

[1]	Amount is a component of "Depreciation, amortization and accretion" as presented on the Unaudited Condensed Statements of Consolidated Cash Flows.
[2]	Amounts presented for the second quarter of 2011 and the six months ended June 30, 2011 include $5.4 million of gains related to the sale of a portion of our previously held equity method investment in Energy Transfer Equity (see Note 7).
[3]	Cost of sales is a component of "Operating costs and expenses," as presented on our Unaudited Condensed Statements of Consolidated Operations. Period-to-period fluctuations in these amounts are primarily due to changes in energy commodity prices and sales volumes associated with our marketing activities.
[4]	Represents cost of operating our plants, pipelines and other fixed assets, excluding non-cash depreciation, amortization and accretion charges.
[5]	With respect to the six months ended June 30, 2012, the amount presented reflects our equity in the income of Energy Transfer Equity from January 1, 2012 to January 18, 2012.

Related Party Transactions (Details) - USD ($)
$ in Millions

3 Months Ended

6 Months Ended

Jun. 30, 2012

Jun. 30, 2011

Jun. 30, 2012

Jun. 30, 2011

Dec. 31, 2011

Revenues - related parties:

$ 25.6

$ 144.2

$ 56.4

$ 394.3

Accounts receivable - related parties:

247.3

426.8

418.4

877.4

Total accounts receivable - related parties

2.3

$ 43.5

Relationship with Affiliates [Abstract]

$ 70.2

211.6

Dan Duncan LLC's ownership interest of general partner of Enterprise (in hundredths)

100.00%

Administrative Services Agreement [Abstract]

Operating costs and expenses

$ 221.5

392.7

$ 369.9

818.3

General and administrative expenses

25.8

34.1

48.5

59.1

EPCO and affiliates [Member]

240.1

192.4

406.1

365.4

Relationship with Affiliates [Abstract]

$ 61.8

108.3

Number of Units (in units)

^[1]

338,930,881

Percentage of Total Units Outstanding (in hundredths)

38.10%

Distributions:

Total distributions

$ 369.6

346.4

Administrative Services Agreement [Abstract]

Operating costs and expenses

$ 213.6

157.9

356.3

305.3

General and administrative expenses

$ 26.5

34.5

$ 49.8

60.1

EPCO and affiliates [Member] | Class B units [Member]

Relationship with Affiliates [Abstract]

Number of Units (in units)

4,520,431

Energy Transfer Equity and subsidiaries [Member]

Revenues - related parties:

Total revenue - related parties

$ 0.0

86.7

$ 0.0

296.9

Accounts receivable - related parties:

0.0

223.0

0.0

490.4

Total accounts receivable - related parties

0.0

28.4

Other unconsolidated affiliates [Member]

0.0

92.6

Revenues - related parties:

Total revenue - related parties

25.6

57.5

56.4

97.4

Accounts receivable - related parties:

7.2

$ 11.4

12.3

$ 21.6

Total accounts receivable - related parties

2.3

15.1