Enterprise Products Partners (EPD) 10-Q 6 Nov 15 2015 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2015	Oct. 30, 2015
Document and Entity Information [Abstract]
Entity Registrant Name	ENTERPRISE PRODUCTS PARTNERS L P
Entity Central Index Key	1,061,219
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		2,005,753,801
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2015

UNAUDITED CONDENSED CONSOLIDATE

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions		Sep. 30, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents		$ 80.5	$ 74.4
Restricted cash		46.2	0
Accounts receivable - trade, net of allowance for doubtful accounts of $12.9 at September 30, 2015 and $13.9 at December 31, 2014		2,802	3,823
Accounts receivable - related parties		1.7	2.8
Inventories		1,085.4	1,014.2
Derivative assets		241.8	226
Prepaid and other current assets		402.4	350.3
Total current assets		4,660	5,490.7
Property, plant and equipment, net		31,214.1	29,881.6
Investments in unconsolidated affiliates		2,625.3	3,042
Intangible assets, net of accumulated amortization of $1,192.2 at September 30, 2015 and $1,246.3 at December 31, 2014 (see Note 9)		4,082.1	4,302.1
Goodwill (see Note 9)		5,749.2	4,300.2
Other assets		197.1	184.4
Total assets		48,527.8	47,201
Current liabilities:
Current maturities of debt (see Note 10)	[1]	1,619.4	2,206.4
Accounts payable - trade		844.9	773.8
Accounts payable - related parties		80.3	118.9
Accrued product payables		2,547.9	3,853.3
Accrued liability related to EFS Midstream acquisition (see Note 8)		997.7	0
Accrued interest		198.9	335.5
Other current liabilities		589.8	585.8
Total current liabilities		6,878.9	7,873.7
Long-term debt (see Note 10)		20,840.7	19,157.4
Deferred tax liabilities		53.4	66.6
Other long-term liabilities		$ 401.9	$ 411.1
Commitments and contingencies (see Note 15)
Limited partners:
Common units (2,005,785,601 units outstanding at September 30, 2015 and 1,937,324,817 units outstanding at December 31, 2014)		$ 20,392.8	$ 18,304.8
Accumulated other comprehensive loss		(230.7)	(241.6)
Total partners' equity		20,162.1	18,063.2
Noncontrolling interests		190.8	1,629
Total equity		20,352.9	19,692.2
Total liabilities and equity		$ 48,527.8	$ 47,201
[1]	We expect to refinance the current maturities of our debt obligations at or prior to their maturity.

UNAUDITED CONDENSED CONSOLIDAT3

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Current assets:
Accounts receivable, allowance for doubtful accounts	$ 12.9	$ 13.9
Intangible assets, accumulated amortization	$ 1,192.2	$ 1,246.3
Limited partners:
Capital account, units outstanding (in units)	2,005,785,601	1,937,324,817

UNAUDITED CONDENSED STATEMENTS

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Revenues:
Third parties	$ 6,294	$ 12,319.2	$ 20,845.6	$ 37,697.1
Related parties	13.9	11	27.3	63.8
Total revenues (see Note 12)	6,307.9	12,330.2	20,872.9	37,760.9
Operating costs and expenses:
Third parties	5,167.9	11,198.1	17,642.6	34,198.9
Related parties	284.7	216.7	783.9	735.5
Total operating costs and expenses	5,452.6	11,414.8	18,426.5	34,934.4
General and administrative costs:
Third parties	20.8	18.1	57.9	60
Related parties	28.2	31.9	85.3	90.9
Total general and administrative costs	49	50	143.2	150.9
Total costs and expenses	5,501.6	11,464.8	18,569.7	35,085.3
Equity in income of unconsolidated affiliates	103.1	72.3	302.5	179.1
Operating income	909.4	937.7	2,605.7	2,854.7
Other income (expense):
Interest expense	(243.7)	(229.8)	(723.2)	(679.6)
Change in fair value of Liquidity Option Agreement (see Note 15)	(4.3)	0	(15.8)	0
Other, net	1.8	(1)	2.6	(0.2)
Total other expense, net	(246.2)	(230.8)	(736.4)	(679.8)
Income before income taxes	663.2	706.9	1,869.3	2,174.9
Provision for income taxes	(5.5)	(7.7)	(4.4)	(22.5)
Net income	657.7	699.2	1,864.9	2,152.4
Net income attributable to noncontrolling interests (see Note 11)	(8.4)	(8.1)	(28.5)	(24.8)
Net income attributable to limited partners	$ 649.3	$ 691.1	$ 1,836.4	$ 2,127.6
Earnings per unit: (see Note 14)
Basic earnings per unit (in dollars per unit)	$ 0.33	$ 0.38	$ 0.94	$ 1.16
Diluted earnings per unit (in dollars per unit)	$ 0.32	$ 0.37	$ 0.92	$ 1.13

UNAUDITED CONDENSED STATEMENTS5

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
Net income	$ 657.7	$ 699.2	$ 1,864.9	$ 2,152.4
Commodity derivative instruments:
Changes in fair value of cash flow hedges	85.8	58.1	112.3	16.1
Reclassification of losses (gains) to net income	(46.8)	(18)	(128.1)	12.9
Interest rate derivative instruments:
Reclassification of losses to net income	8.9	8	26.3	23.9
Total cash flow hedges	47.9	48.1	10.5	52.9
Other	0	0	0.4	0
Total other comprehensive income	47.9	48.1	10.9	52.9
Comprehensive income	705.6	747.3	1,875.8	2,205.3
Comprehensive income attributable to noncontrolling interests	(8.4)	(8.1)	(28.5)	(24.8)
Comprehensive income attributable to limited partners	$ 697.2	$ 739.2	$ 1,847.3	$ 2,180.5

UNAUDITED CONDENSED STATEMENTS6

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Operating activities:
Net income	$ 1,864.9	$ 2,152.4
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion	1,147.7	992.4
Non-cash asset impairment charges (see Note 4)	139.1	18.2
Equity in income of unconsolidated affiliates	(302.5)	(179.1)
Distributions received from unconsolidated affiliates	362.4	260.7
Net losses (gains) attributable to asset sales and insurance recoveries (see Note 16)	14.7	(99)
Gains on early extinguishment of debt	(1.4)	0
Deferred income tax expense (benefit)	(13.3)	2.6
Changes in fair value of Liquidity Option Agreement	15.8	0
Changes in fair market value of derivative instruments	(7.7)	(3.8)
Net effect of changes in operating accounts (see Note 16)	(627.9)	(435.8)
Other operating activities	(0.6)	(4.2)
Net cash flows provided by operating activities	2,591.2	2,704.4
Investing activities:
Capital expenditures	(2,630.5)	(1,879.5)
Contributions in aid of construction costs	11.4	20
Decrease (increase) in restricted cash	(46.2)	59
Cash used for business combinations, net of cash received (see Note 8)	(1,045.1)	0
Investments in unconsolidated affiliates	(130.7)	(583.3)
Proceeds from asset sales and insurance recoveries (see Note 16)	1,537.3	121.5
Other investing activities	(4.4)	(5.8)
Cash used in investing activities	(2,308.2)	(2,268.1)
Financing activities:
Borrowings under debt agreements	17,113.7	7,167.5
Repayments of debt	(16,139.2)	(4,856.3)
Debt issuance costs	(23.9)	(18.1)
Cash distributions paid to limited partners (see Note 11)	(2,185.1)	(1,948.2)
Cash payments made in connection with distribution equivalent rights	(5.6)	(2.4)
Cash distributions paid to noncontrolling interests	(33.2)	(29.4)
Cash contributions from noncontrolling interests	37.4	4
Net cash proceeds from the issuance of common units	1,011.4	304.9
Other financing activities	(52.4)	(53.6)
Cash provided by (used in) financing activities	(276.9)	568.4
Net change in cash and cash equivalents	6.1	1,004.7
Cash and cash equivalents, beginning balance	74.4	56.9
Cash and cash equivalents, ending balance	$ 80.5	$ 1,061.6

UNAUDITED CONDENSED STATEMENTS7

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY - USD ($) $ in Millions	Total	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interests [Member]	Limited Partners [Member]
Balance at Dec. 31, 2013	$ 15,440.4	$ (359)	$ 225.6	$ 15,573.8
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	2,152.4	0	24.8	2,127.6
Cash distributions paid to limited partners	(1,948.2)	0	0	(1,948.2)
Cash payments made in connection with distribution equivalent rights	(2.4)	0	0	(2.4)
Cash distributions paid to noncontrolling interests	(29.4)	0	(29.4)	0
Cash contributions from noncontrolling interests	4	0	4	0
Net cash proceeds from the issuance of common units	304.9	0	0	304.9
Amortization of fair value of equity-based awards	61.6	0	0	61.6
Cash flow hedges	52.9	52.9	0	0
Other	(54.3)	0	(0.6)	(53.7)
Balance at Sep. 30, 2014	15,981.9	(306.1)	224.4	16,063.6
Balance at Dec. 31, 2014	19,692.2	(241.6)	1,629	18,304.8
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	1,864.9	0	28.5	1,836.4
Cash distributions paid to limited partners	(2,185.1)	0	0	(2,185.1)
Cash payments made in connection with distribution equivalent rights	(5.6)	0	0	(5.6)
Cash distributions paid to noncontrolling interests	(33.2)	0	(33.2)	0
Cash contributions from noncontrolling interests	37.4	0	37.4	0
Common units issued in connection with Step 2 of Oiltanking acquisition	0	0	(1,408.7)	1,408.7
Transfer of noncontrolling interests in connection with sale of Offshore Business	(62.1)	0	(62.1)	0
Net cash proceeds from the issuance of common units	1,011.4	0	0	1,011.4
Amortization of fair value of equity-based awards	72.9	0	0	72.9
Cash flow hedges	10.5	10.5	0	0
Other	(50.4)	0.4	(0.1)	(50.7)
Balance at Sep. 30, 2015	$ 20,352.9	$ (230.7)	$ 190.8	$ 20,392.8

Partnership Operations, Organiz

Partnership Operations, Organization and Basis for Presentation	9 Months Ended
	Sep. 30, 2015
Partnership Operations and Organization [Abstract]
Partnership Operations and Organization	the dollar amounts presented in the tabular data within these disclosures are stated in millions of dollars. KEY REFERENCES USED IN THESE Unless the context requires otherwise, references to “we,” “us,” “our,” “Enterprise” or “Enterprise Products Partners” are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries. References to “EPO” mean Enterprise Products Operating LLC, which is a wholly owned subsidiary of Enterprise, and its consolidated subsidiaries, through which Enterprise Products Partners L.P. conducts its business. Enterprise is managed by its general partner, Enterprise Products Holdings LLC (“Enterprise GP”), which is a wholly owned subsidiary of Dan Duncan LLC, a privately held Texas limited liability company. The membership interests of Dan Duncan LLC are owned by a voting trust, the current trustees (“DD LLC Trustees”) of which are: (i) Randa Duncan Williams, who is also a director and Chairman of the Board of Enterprise GP; (ii) Dr. Ralph S. Cunningham; and (iii) Richard H. Bachmann. Each of the DD LLC Trustees also currently serves as one of the three managers of Dan Duncan LLC. References to “EPCO” mean Enterprise Products Company, a privately held Texas corporation, and its privately held affiliates. A majority of the outstanding voting capital stock of EPCO is owned by a voting trust, the current trustees (“EPCO Trustees”) of which are: (i) Ms. Williams, who serves as Chairman of EPCO; (ii) Dr. Cunningham, who serves as a Vice Chairman of EPCO; and (iii) Mr. Bachmann, who serves as the President and Chief Executive Officer (“CEO”) of EPCO. Each of the EPCO Trustees is also a director of EPCO. In addition to owning our general partner, EPCO and its privately held affiliates owned approximately 33.7% of our limited partner interests at September 30, 2015. References to “Oiltanking” and “Oiltanking GP” mean Oiltanking Partners, L.P. and OTLP GP, LLC, the general partner of Oiltanking, respectively. In October 2014, we acquired approximately 65.9% of the limited partner interests of Oiltanking, all of the member interests of Oiltanking GP and the incentive distribution rights (“IDRs”) held by Oiltanking GP from Oiltanking Holding Americas, Inc. (“OTA”) as the first step of a two-step acquisition of Oiltanking. In February 2015, we completed the second step of this acquisition. See Note 11 for additional information regarding this acquisition. References to “TEPPCO” mean TEPPCO Partners, L.P. prior to its merger with one of our wholly owned subsidiaries in October 2009. References to “Offshore Business” refer to the Gulf of Mexico operations we sold to Genesis Energy, L.P. (“Genesis”) in July 2015. See Note 6 for information regarding this sale. References to “EFS Midstream” mean EFS Midstream LLC, which we acquired in July 2015 from affiliates of Pioneer Natural Resources Company (“Pioneer”) and Reliance Industries Limited (“Reliance”). See Note 8 for additional information regarding this acquisition. 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, petrochemicals and refined products. Our integrated 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 midstream energy operations currently include: natural gas gathering, treating, processing, transportation and storage; NGL transportation, fractionation, storage, and import and export terminals (including liquefied petroleum gas or “LPG”); crude oil gathering, transportation, storage and terminals; petrochemical and refined products transportation, storage and terminals, and related services; and a marine transportation business that operates primarily on the U.S. inland and Intracoastal Waterway systems and in the Gulf of Mexico. Our assets currently include approximately 49,000 miles of pipelines; 225 million barrels (“MMBbls”) of storage capacity for NGLs, crude oil, petrochemicals and refined products; and 14 billion cubic feet (“Bcf”) of natural gas storage capacity. Our historical operations are reported under five business segments: (i) NGL Pipelines & Services, (ii) Crude Oil Pipelines & Services, (iii) Natural Gas Pipelines & Services, (iv) Petrochemical & Refined Products Services and (v) Offshore Pipelines & Services. On July 24, 2015, we completed the sale of our Offshore Business to Genesis. As a result of this sale, we renamed our Onshore Crude Oil Pipelines & Services business segment “Crude Oil Pipelines & Services.” In addition, we renamed our Onshore Natural Gas Pipelines & Services business segment “Natural Gas Pipelines & Services.” The operations reported within these two onshore segments did not change due to these name changes. Our consolidated financial statements reflect ownership of the Offshore Business through July 24, 2015. See Note 12 for additional information regarding our business segments. As a result of our acquisition of the member interests of EFS Midstream effective July 1, 2015, we began consolidating the financial statements of EFS Midstream as of that date. See Note 8 for information regarding this acquisition. We conduct substantially all of our business through EPO and are owned 100% by our limited partners from an economic perspective. Enterprise GP manages our partnership and owns a non-economic general partner interest in us. We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates under the collective common control of the DD LLC Trustees and the EPCO Trustees. Like many publicly traded partnerships, we have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement (the “ASA”) or by other service providers. See Note 13 for information regarding the ASA and other related party matters.

General Accounting and Disclosu

General Accounting and Disclosure Matters	9 Months Ended
	Sep. 30, 2015
General Accounting Matters [Abstract]
General Accounting Matters	Our results of operations for the three and nine months ended September 30, 2015 are not necessarily indicative of results expected for the full year of 2015. 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 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, 2014 (the “2014 Form 10-K”) filed with the SEC on March 2, 2015. 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 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. Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed. See Note 15 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 and certain anticipated future commodity transactions. To qualify for hedge accounting, the hedged item must expose us to risk and the related derivative instrument must reduce the exposure to that risk 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 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 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 transactions are recognized during the period when volumes are physically delivered or received. Physical forward commodity contracts subject to this exception 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 physical delivery in the future. See Note 4 for additional information regarding our derivative instruments. Estimates Preparing our consolidated financial statements in conformity with U.S. 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 Taxes Provision for income taxes primarily reflects our state tax obligations under the Revised Texas Franchise Tax (the “Texas Margin Tax”). Restricted Cash Restricted cash represents amounts held in segregated bank accounts by our clearing brokers as margin in support of our commodity derivative instruments portfolio and related physical purchases and sales of natural gas, NGLs, crude oil and refined products. Additional cash may be restricted to maintain our commodity derivative instruments portfolio as prices fluctuate or deposit requirements change. At September 30, 2015, our restricted cash amounts were $46.2 million. We did not have any restricted cash as of December 31, 2014. See Note 4 for information regarding our derivative instruments and hedging activities.

Equity-based Awards

Equity-based Awards	9 Months Ended
	Sep. 30, 2015
Equity-based Awards [Abstract]
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 compensation expense we recognized in connection with equity-based awards for the periods indicated: For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 Equity-classified awards: Restricted common unit awards $ 3.1 $ 8.7 $ 13.1 $ 29.3 Phantom unit awards 20.3 12.9 60.2 32.3 Liability-classified awards -- 0.1 0.2 0.4 Total $ 23.4 $ 21.7 $ 73.5 $ 62.0 The fair value of equity-classified awards is amortized into earnings over the requisite service or vesting period. Equity-classified awards are expected to result in the issuance of common units upon vesting. Compensation expense for liability-classified awards is recognized over the requisite service or vesting period based on the fair value of the award remeasured at each reporting date. Liability-classified awards are settled in cash upon vesting. At September 30, 2015, EPCO’s significant long-term incentive plans applicable to us were the Enterprise Products 1998 Long-Term Incentive Plan (“1998 Plan”) and the 2008 Enterprise Products Long-Term Incentive Plan (Third Amendment and Restatement) (“2008 Plan”). Up to 14,000,000 of our common units may be issued as awards under the 1998 Plan. The maximum number of common units available for issuance under the 2008 Plan was 30,000,000 at September 30, 2015. This amount will automatically increase under the terms of the 2008 Plan by 5,000,000 common units on January 1, 2016 and will continue to automatically increase annually on January 1 thereafter during the term of the 2008 Plan; provided, however, that in no event shall the maximum aggregate number exceed 70,000,000 common units. After giving effect to awards granted under the 1998 Plan and 2008 Plan through September 30, 2015, a total of 3,040,506 and 16,277,823 additional common units were available for issuance 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 fulfilling service and other conditions) once a defined vesting period expires, subject to customary forfeiture provisions. Restricted common unit awards generally vest at a rate of 25% per year beginning one year after the grant date and are non-vested until the required service periods expire. Restricted common units are included in the number of common units outstanding as 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 our common units 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 indicated: Number of Units Weighted- Average Grant Date Fair Value per Unit Restricted common units at December 31, 2014 4,229,790 $ 26.96 Vested (1,997,194 ) $ 25.99 Forfeited (157,750 ) $ 27.64 Restricted common units at September 30, 2015 2,074,846 $ 27.85 (1) Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued. Each recipient of a restricted common unit award is 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 our common unitholders. These 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 indicated: For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 Cash distributions paid to restricted common unitholders $ 0.8 $ 1.6 $ 3.2 $ 5.7 Total intrinsic value of restricted common unit awards that vested during period 1.5 1.3 66.9 85.4 For the EPCO group of companies, the unrecognized compensation cost associated with restricted common unit awards was an aggregate $11.5 million at September 30, 2015, of which our share of the cost is currently estimated to be $9.6 million. Due to the graded vesting provisions of these awards, we expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 1.1 years. Phantom Unit Awards Phantom unit awards allow recipients to acquire our common units (at no cost to the recipient apart from fulfilling service and other conditions) once a defined vesting period expires, subject to customary forfeiture provisions. Phantom unit awards generally vest at a rate of 25% per year beginning one year after the grant date and are non-vested until the required service periods expire. At September 30, 2015, substantially all of our phantom unit awards are expected to result in the issuance of common units upon vesting; therefore, the applicable awards are accounted for as equity-classified awards. The grant date fair value of a phantom unit award is based on the market price per unit of our common units 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 phantom unit award activity for the period indicated: Number of Units Weighted- Average Grant Date Fair Value per Unit Phantom unit awards at December 31, 2014 3,342,390 $ 33.13 Granted (2) 3,491,040 $ 33.97 Vested (933,890 ) $ 33.13 Forfeited (275,356 ) $ 33.51 Phantom unit awards at September 30, 2015 5,624,184 $ 33.63 (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 phantom unit awards issued during 2015 was $118.6 million based on a grant date market price of our common units ranging from $27.31 to $34.40 per unit. An estimated annual forfeiture rate of 3.5% was applied to these awards. Our long-term incentive plans provide for the issuance of distribution equivalent rights (“DERs”) in connection with phantom unit awards. A DER entitles the participant to nonforfeitable cash payments equal to the product of the number of phantom unit awards outstanding for the participant and the cash distribution per common unit paid to our common unitholders. Cash payments made in connection with DERs are charged to partners’ equity when the phantom unit award is expected to result in the issuance of common units; otherwise, such amounts are expensed. The following table presents supplemental information regarding our phantom unit awards and DERs for the periods indicated: For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 Cash payments made in connection with DERs $ 2.2 $ 1.2 $ 5.6 $ 2.4 Total intrinsic value of phantom unit awards that vested during period 2.3 0.1 31.0 1.3 For the EPCO group of companies, the unrecognized compensation cost associated with phantom unit awards was $100.4 million at September 30, 2015, of which our share of the cost is currently estimated to be $91.7 million. Due to the graded vesting provisions of these awards, 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 denominated in our common units. In general, unit option awards 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, 2014 will expire on December 31, 2015). However, unit option awards 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 following table presents unit option award activity for the period indicated: Number of Units Weighted- Average Strike Price (dollars/unit) Weighted- Average Remaining Contractual Term (in years) Aggregate Intrinsic Value Unit option awards at December 31, 2014 1,270,000 $ 16.14 Exercised (1,080,000 ) $ 16.14 Unit option awards at September 30, 2015 190,000 $ 16.14 0.3 $ 1.7 (1) All of the unit option awards outstanding at September 30, 2015 were exercisable. None of the unit option awards outstanding at December 31, 2014 were exercisable. (2) Aggregate intrinsic value reflects fully vested unit option awards at the dates indicated. In order to fund its unit option award-related obligations, EPCO may purchase common units at fair value either in the open market or directly from us. When employees exercise unit option awards, 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 unit option awards during the periods indicated: For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 Total intrinsic value of unit option awards exercised during period $ 0.2 $ -- $ 19.8 $ 57.5 Cash received from EPCO in connection with the exercise of unit option awards 0.2 -- 11.5 33.4 Unit option award-related cash reimbursements to EPCO 0.2 -- 19.8 57.5 As of September 30, 2015, all compensation expense related to unit option awards had been recognized.

Derivative Instruments, Hedging

Derivative Instruments, Hedging Activities and Fair Value Measurements	9 Months Ended
	Sep. 30, 2015
Derivative Instruments, Hedging Activities and Fair Value Measurements [Abstract]
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 assets, liabilities and certain anticipated future transactions, we use derivative instruments such as futures, forward contracts, swaps, options and other instruments with similar characteristics. Substantially all of our derivatives are used for non-trading activities. 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. This strategy may be used in controlling our overall cost of capital associated with such borrowings. At December 31, 2014, we did not have any interest rate hedging derivative instruments outstanding. The following table summarizes our portfolio of interest rate swaps at September 30, 2015: Hedged Transaction Number and Type of Derivatives Outstanding Notional Amount Period of Hedge Rate Swap Accounting Treatment Senior Notes OO 10 fixed-to-floating swaps $ 750.0 5/2015 to 5/2018 1.65% to 0.79% Fair value hedge Interest rate swaps exchange the stated interest rate paid on a notional amount of existing debt for the fixed or floating interest rate stipulated in the derivative instrument. Commodity Hedging Activities The prices of natural gas, NGLs, crude oil, petrochemicals and refined 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 option contracts. The following table summarizes our portfolio of commodity derivative instruments outstanding at September 30, 2015 (volume measures as noted): Volume (1) Accounting Derivative Purpose Current Long-Term Treatment Derivatives designated as hedging instruments: Natural gas processing: Forecasted natural gas purchases for plant thermal reduction (Bcf) 4.9 n/a Cash flow hedge Forecasted sales of NGLs (MMBbls) (3) 1.1 n/a Cash flow hedge Octane enhancement: Forecasted purchases of NGLs (MMBbls) 0.1 n/a Cash flow hedge Forecasted sales of octane enhancement products (MMBbls) 0.5 n/a Cash flow hedge Natural gas marketing: Forecasted purchases of natural gas for fuel (Bcf) 6.4 n/a Cash flow hedge Forecasted sales of natural gas (Bcf) 0.1 n/a Cash flow hedge Natural gas storage inventory management activities (Bcf) 10.2 n/a Fair value hedge NGL marketing: Forecasted purchases of NGLs and related hydrocarbon products (MMBbls) 34.6 0.5 Cash flow hedge Forecasted sales of NGLs and related hydrocarbon products (MMBbls) 49.8 n/a Cash flow hedge Refined products marketing: Forecasted purchases of refined products (MMBbls) 0.4 n/a Cash flow hedge Forecasted sales of refined products (MMBbls) 0.7 n/a Cash flow hedge Refined products inventory management activities (MMBbls) 0.2 n/a Fair value hedge Crude oil marketing: Forecasted purchases of crude oil (MMBbls) 9.0 1.6 Cash flow hedge Forecasted sales of crude oil (MMBbls) 11.9 1.6 Cash flow hedge Derivatives not designated as hedging instruments: Natural gas risk management activities (Bcf) (4,5) 65.9 9.6 Mark-to-market NGL risk management activities (MMBbls) (5) 14.9 n/a Mark-to-market Crude oil risk management activities (MMBbls) (5) 5.8 0.4 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 2017, April 2016 and March 2018, respectively. (3) Forecasted sales of NGL volumes under natural gas processing exclude 0.7 MMBbls of additional hedges executed under contracts that have been designated as normal sales agreements. (4) Current and long-term volumes include 38.7 Bcf and 0.9 Bcf, respectively, of physical derivative instruments that are predominantly priced at a marked-based index plus a premium or minus a discount related to location differences. (5) Reflects the use of derivative instruments to manage risks associated with transportation, processing and storage assets. At September 30, 2015, our predominant commodity hedging strategies consisted of (i) hedging anticipated future purchases and sales of commodity products associated with transportation, storage and blending activities, (ii) hedging natural gas processing margins and (iii) hedging the fair value of commodity products held in inventory. § The objective of our anticipated future commodity purchases and sales hedging program is to hedge the margins of certain transportation, storage, blending and operational activities by locking in purchase and sale prices through the use of forward contracts and derivative instruments. § The objective of our natural gas processing hedging program is to hedge an amount of gross margin associated with these activities. We achieve this objective by executing forward fixed-price sales of a portion of our expected equity NGL production using forward contracts and commodity derivative instruments. For certain natural gas processing contracts, the hedging of expected equity NGL production also involves the purchase of natural gas for plant thermal reduction, which is hedged by executing forward fixed-price purchases using forward contracts and derivative instruments. § The objective of our inventory hedging program is to hedge the fair value of commodity products currently held in inventory by locking in the sales price of the inventory through the use of forward contracts and 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 September 30, 2015 December 31, 2014 September 30, 2015 December 31, 2014 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 Current assets $ 7.4 Current assets $ -- Other current liabilities $ -- Other current liabilities $ -- Interest rate derivatives Other assets 0.2 Other assets -- Other liabilities -- Other liabilities -- Total interest rate derivatives 7.6 -- -- -- Commodity derivatives Current assets 216.9 Current assets 217.9 Other current liabilities 178.5 Other current liabilities 145.3 Commodity derivatives Other assets 8.3 Other assets -- Other liabilities 8.2 Other liabilities -- Total commodity derivatives 225.2 217.9 186.7 145.3 Total derivatives designated as hedging instruments $ 232.8 $ 217.9 $ 186.7 $ 145.3 Derivatives not designated as hedging instruments Commodity derivatives Current assets $ 17.5 Current assets $ 8.1 Other current liabilities $ 9.4 Other current liabilities $ 0.7 Commodity derivatives Other assets 0.1 Other assets 0.6 Other liabilities 1.0 Other liabilities 1.4 Total commodity derivatives $ 17.6 $ 8.7 $ 10.4 $ 2.1 Certain of our commodity derivative instruments are subject to master netting arrangements or similar agreements. The following tables present our derivative instruments subject to such arrangements at the dates indicated: Offsetting of Financial Assets and Derivative Assets Gross Amounts of Recognized Assets Gross Amounts Offset in the Balance Sheet Amounts of Assets Presented in the Balance Sheet Gross Amounts Not Offset in the Balance Sheet Amounts That Would Have Been Presented On Net Basis Financial Instruments Cash Collateral Received Cash Collateral Paid (i) (ii) (iii) = (i) – (ii) (iv) (v) = (iii) + (iv) As of September 30, 2015: Interest rate derivatives $ 7.6 $ -- $ 7.6 $ -- $ -- $ -- $ 7.6 Commodity derivatives 242.8 -- 242.8 (180.3 ) (38.2 ) (9.6 ) 14.7 As of December 31, 2014: Commodity derivatives $ 226.6 $ -- $ 226.6 $ (147.3 ) $ (23.9 ) $ -- $ 55.4 Offsetting of Financial Liabilities and Derivative Liabilities Gross Amounts of Recognized Liabilities Gross Amounts Offset in the Balance Sheet Amounts of Liabilities Presented in the Balance Sheet Gross Amounts Not Offset in the Balance Sheet Amounts That Would Have Been Presented On Net Basis Financial Instruments Cash Collateral Paid (i) (ii) (iii) = (i) – (ii) (iv) (v) = (iii) + (iv) As of September 30, 2015: Commodity derivatives $ 197.1 $ -- $ 197.1 $ (180.3 ) $ -- $ 16.8 As of December 31, 2014: Commodity derivatives $ 147.4 $ -- $ 147.4 $ (147.3 ) $ -- $ 0.1 Derivative assets and liabilities recorded on our Unaudited Condensed Consolidated Balance Sheets are presented on a gross-basis and determined at the individual transaction level. The tabular presentation above provides a means for comparing the gross amount of derivative assets and liabilities, excluding associated accounts payable and receivable, to the net amount that would likely be receivable or payable under a default scenario based on the existence of rights of offset in the respective derivative agreements. Any cash collateral paid or received is reflected in these tables, but only to the extent that it represents variation margins. Any amounts associated with derivative prepayments or initial margins that are not influenced by the derivative asset or liability amounts or those that are determined solely on their volumetric notional amounts are excluded from these tables. 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 indicated: Derivatives in Fair Value Hedging Relationships Location Gain (Loss) Recognized in Income on Derivative For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 Interest rate derivatives Interest expense $ 5.9 $ (4.1 ) $ 5.1 $ (9.5 ) Commodity derivatives Revenue 3.6 (0.3 ) 4.0 0.6 Total $ 9.5 $ (4.4 ) $ 9.1 $ (8.9 ) Derivatives in Fair Value Hedging Relationships Location Gain (Loss) Recognized in Income on Hedged Item For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 Interest rate derivatives Interest expense $ (5.7 ) $ 3.9 $ (5.2 ) $ 9.3 Commodity derivatives Revenue (2.5 ) 1.0 7.4 (1.4 ) Total $ (8.2 ) $ 4.9 $ 2.2 $ 7.9 With respect to our derivative instruments designated as fair value hedges, amounts attributable to ineffectiveness and those excluded from the assessment of hedge effectiveness were not material to our consolidated financial statements during the periods presented. 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 indicated: Derivatives in Cash Flow Hedging Relationships Change in Value Recognized in Other Comprehensive Income (Loss) on Derivative (Effective Portion) For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 Commodity derivatives – Revenue (1) $ 87.4 $ 58.8 $ 113.9 $ 15.2 Commodity derivatives – Operating costs and expenses (1) (1.6 ) (0.7 ) (1.6 ) 0.9 Total $ 85.8 $ 58.1 $ 112.3 $ 16.1 (1) The fair value of these derivative instruments will be reclassified to their respective locations on the Unaudited Condensed Statement of Consolidated Operations upon settlement of the underlying derivative transactions, as appropriate. Derivatives in Cash Flow Hedging Relationships Location Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income (Effective Portion) For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 Interest rate derivatives Interest expense $ (8.9 ) $ (8.0 ) $ (26.3 ) $ (23.9 ) Commodity derivatives Revenue 46.8 17.8 128.6 (14.5 ) Commodity derivatives Operating costs and expenses -- 0.2 (0.5 ) 1.6 Total $ 37.9 $ 10.0 $ 101.8 $ (36.8 ) Derivatives in Cash Flow Hedging Relationships Location Gain (Loss) Recognized in Income on Derivative (Ineffective Portion) For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 Commodity derivatives Revenue $ (3.5 ) $ 0.1 $ (3.1 ) $ -- Commodity derivatives Operating costs and expenses -- (0.1 ) -- -- Total $ (3.5 ) $ -- $ (3.1 ) $ -- Over the next twelve months, we expect to reclassify $36.8 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 $54.1 million of net gains attributable to commodity derivative instruments from accumulated other comprehensive income to earnings, $55.7 million as an increase in revenue and $1.6 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 indicated: Derivatives Not Designated as Hedging Instruments Location Gain (Loss) Recognized in Income on Derivative For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 Interest rate derivatives Interest expense $ -- $ -- $ -- $ (0.1 ) Commodity derivatives Revenue -- 0.8 3.9 (26.8 ) Commodity derivatives Operating costs and expenses (0.3 ) -- -- -- Total $ (0.3 ) $ 0.8 $ 3.9 $ (26.9 ) 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 measurement 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 highest 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 tables set forth, by level within the fair value hierarchy, the carrying values of our financial assets and liabilities at the dates indicated. These assets and liabilities are measured on a recurring basis and are classified based on the lowest level of input used to estimate their fair value. Our assessment of the relative significance of such inputs requires judgment. September 30, 2015 Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Financial assets: Interest rate derivatives $ -- $ 7.6 $ -- $ 7.6 Commodity derivatives 84.1 157.7 1.0 242.8 Total $ 84.1 $ 165.3 $ 1.0 $ 250.4 Financial liabilities: Liquidity Option Agreement $ -- $ -- $ 235.5 $ 235.5 Commodity derivatives 37.4 142.7 17.0 197.1 Total $ 37.4 $ 142.7 $ 252.5 $ 432.6 December 31, 2014 Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Financial assets: Commodity derivatives $ 37.8 $ 187.8 $ 1.0 $ 226.6 Financial liabilities: Liquidity Option Agreement $ -- $ -- $ 219.7 $ 219.7 Commodity derivatives 13.8 133.0 0.6 147.4 Total $ 13.8 $ 133.0 $ 220.3 $ 367.1 The following table sets forth a reconciliation of changes in the fair values of our recurring Level 3 financial assets and liabilities on a combined basis for the periods indicated: For the Nine Months Ended September 30, Location 2015 2014 Financial asset (liability) balance, net, January 1 $ (219.3 ) $ 3.2 Total gains (losses) included in: Net income (1) Revenue (0.4 ) 4.6 Other comprehensive income Commodity derivative instruments – changes in fair value of cash flow hedges (1.5 ) -- Settlements Revenue (0.5 ) (0.1 ) Transfers out of Level 3 0.1 -- Financial asset (liability) balance, net, March 31 (221.6 ) 7.7 Total gains (losses) included in: Net income (1) Revenue (0.4 ) (3.3 ) Net income Other expense, net (11.5 ) -- Other comprehensive income Commodity derivative instruments – changes in fair value of cash flow hedges (1.0 ) -- Settlements Revenue 0.2 (1.8 ) Transfers out of Level 3 1.5 -- Financial asset (liability) balance, net, June 30 (232.8 ) 2.6 Total gains (losses) included in: Net income (1) Revenue (0.3 ) (0.9 ) Net income Other expense, net (4.3 ) -- Other comprehensive income Commodity derivative instruments – changes in fair value of cash flow hedges (15.5 ) (2.5 ) Settlements Revenue 0.3 0.1 Transfers out of Level 3 1.1 -- Financial asset (liability) balance, net, September 30 $ (251.5 ) $ (0.7 ) (1) There were $1.1 million of unrealized losses included in these amounts for the nine months ended September 30, 2015. There were unrealized gains of $0.8 million and $1.3 million included in these amounts for the three and nine months ended September 30, 2014, respectively. The following Fair Value Financial Assets Financial Liabilities Valuation Techniques Unobservable Input Range Commodity derivatives – Crude oil $ 0.7 $ 1.3 Discounted cash flow Forward commodity prices $44.47-$50.74/barrel Commodity derivatives – Natural gasoline 0.3 15.6 Discounted cash flow Forward commodity prices $0.93-$1.00/gallon Commodity derivatives – Propane -- 0.1 Discounted cash flow Forward commodity prices $0.50/gallon Total $ 1.0 $ 17.0 With respect to commodity derivatives, we believe forward commodity prices are the most significant unobservable inputs in determining our Level 3 recurring fair value measurements at September 30, 2015. 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. As described in Note 15, we adjusted the expected life of OTA following exercise of the Liquidity Option Agreement to reflect an equal probability of the dissolution of OTA over each of the 30 years in our forecast period. None of the other key valuation assumptions we listed in our 2014 Form 10-K for the Liquidity Option Agreement have changed. Nonrecurring Fair Value Measurements Long-lived assets (including intangible assets with finite useful lives and property, plant and equipment) are reviewed for impairment (i.e., subject to nonrecurring fair value measurements) when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Long-lived assets with carrying values that are not expected to be recovered through future cash flows are written-down to their estimated fair values. The following table summarizes our non-cash impairment charges by segment during each of the periods indicated: For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 NGL Pipelines & Services $ 14.6 $ 1.2 $ 20.6 $ 6.6 Crude Oil Pipelines & Services -- 0.4 25.9 2.2 Natural Gas Pipelines & Services -- 0.4 21.5 0.7 Petrochemical & Refined Products Services 12.2 3.7 12.6 8.7 Offshore Pipelines & Services -- -- 58.5 -- Total $ 26.8 $ 5.7 $ 139.1 $ 18.2 Impairment charges are a component of “Operating costs and expenses” on our Unaudited Condensed Statements of Consolidated Operations. Our non-cash asset impairment charges for the third quarter of 2015 primarily relate to the planned abandonment of natural gas processing assets in southern Louisiana and the reclassification of certain marine vessels to held for sale status. Our non-cash asset impairment charges for the nine months ended September 30, 2015 primarily reflect the $54.8 million charge we recorded in connection with the sale of our Offshore Business (see Note 6) and the abandonment of certain natural gas and crude oil pipeline assets in Texas. Our non-cash asset impairment charges for the nine months ended September 30, 2014 primarily reflect the abandonment of assets classified as property, plant and equipment. The following table presents categories of long-lived assets that were subject to non-recurring fair value measurements during the nine months ended September 30, 2015: Fair Value Measurements at the End of the Reporting Period Using Carrying Value at September 30, 2015 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Non-Cash Impairment Loss Long-lived assets disposed of other than by sale $ 0.4 $ -- $ -- $ 0.4 $ 69.9 Long-lived assets held for sale 34.2 -- -- 34.2 14.2 Long-lived assets disposed of by sale (1) -- -- -- -- 55.0 Total $ 139.1 (1) Primarily represents the impairment charge recorded in second quarter of 2015 upon reclassification of our Offshore Business to held for sale status. The following table presents categories of long-lived assets that were subject to non-recurring fair value measurements during the nine months ended September 30, 2014: Fair Value Measurements at the End of the Reporting Period Using Carrying Value at September 30, 2014 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Non-Cash Impairment Loss Long-lived assets disposed of other than by sale $ -- $ -- $ -- $ -- $ 11.7 Long-lived assets held for sale 1.1 -- -- 1.1 6.5 Total $ 18.2 Other Fair Value Information The carrying amounts of cash and cash equivalents (including restricted cash balances), accounts receivable, commercial paper notes 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 $20.77 billion and $22.16 billion at September 30, 2015 and December 31, 2014, respectively. The aggregate carrying value of these debt obligations was $20.88 billion and $20.48 billion at September 30, 2015 and December 31, 2014, 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 amounts reported for fixed-rate debt obligations as of September 30, 2015, exclude those amounts hedged using fixed-to-floating interest rate swaps. See “ Interest Rate Hedging Activities

Inventories

Inventories	9 Months Ended
	Sep. 30, 2015
Inventories [Abstract]
Inventories	Our inventory amounts by product type were as follows at the dates indicated: September 30, 2015 December 31, 2014 NGLs $ 740.5 $ 579.1 Petrochemicals and refined products 158.0 295.6 Crude oil 152.2 97.8 Natural gas 34.7 41.7 Total $ 1,085.4 $ 1,014.2 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. 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 September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 Cost of sales (1) $ 4,419.9 $ 10,455.1 $ 15,355.9 $ 32,213.1 Lower of cost or market adjustments 2.1 6.7 6.1 14.6 (1) Cost of sales is a component of “Operating costs and expenses” as presented on our Unaudited Condensed Statements of Consolidated Operations. 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

Property, Plant and Equipment	9 Months Ended
	Sep. 30, 2015
Property, Plant and Equipment [Abstract]
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 September 30, 2015 December 31, 2014 Plants, pipelines and facilities (1) 3-45 (6) $ 31,686.3 $ 30,834.9 Underground and other storage facilities (2) 5-40 (7) 2,847.7 2,584.2 Platforms and facilities (3) 20-31 -- 659.7 Transportation equipment (4) 3-10 164.8 154.2 Marine vessels (5) 15-30 787.5 796.4 Land 261.3 262.6 Construction in progress 3,777.2 2,754.7 Total historical cost of property, plant and equipment 39,524.8 38,046.7 Less accumulated depreciation 8,310.7 8,165.1 Total property, plant and equipment, net $ 31,214.1 $ 29,881.6 (1) Plants, pipelines and facilities 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 included offshore platforms and related facilities and other associated assets located in the Gulf of Mexico prior to the sale of our Offshore Business (see below). (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 indicated: For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 Depreciation expense (1) $ 286.2 $ 283.2 $ 870.1 $ 822.1 Capitalized interest (2) 40.3 17.2 105.6 53.4 (1) Depreciation expense is a component of “Costs and expenses” as presented on our Unaudited Condensed Statements of Consolidated Operations. (2) We capitalize interest costs incurred on funds used to construct property, plant and equipment while the asset is in its construction phase. 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. When capitalized interest is recorded, it reduces interest expense from what it would be otherwise. Sale of Offshore Business On July 24, 2015, we consummated a sale to Genesis of our Offshore Business, which primarily consisted of our Offshore Pipelines & Services business segment, for approximately $1.53 billion in cash. Our Offshore Business served drilling and development regions, including deepwater production fields, in the northern Gulf of Mexico offshore Texas, Louisiana, Mississippi and Alabama. As of December 31, 2014, our Offshore Business included approximately 2,350 miles of offshore natural gas and crude oil pipelines and six offshore hub platforms. Our results of operations reflect ownership of the Offshore Business through July 24, 2015. We viewed our Offshore Business as an extension of our midstream energy services network. As such, the sale of these assets did not represent a strategic shift in our consolidated operations, and their sale does not have a major effect on our financial results. At December 31, 2014 and June 30, 2015, segment assets for our Offshore Pipelines & Services segment represented 4.3% and 4.1%, respectively, of consolidated total segment assets. Likewise, gross operating margin from this business segment represented only 3.1% and 3.4% of our consolidated total gross operating margin for the year ended December 31, 2014 and six months ended June 30, 2015, respectively. The sale of this non-strategic business allowed us to redeploy capital to other business opportunities that we believe will generate a higher rate of return for us in the future (e.g., our recent acquisition of EFS Midstream (see Note 8)). Also, proceeds from the closing of this sale will reduce our need to issue additional equity and debt to support our ongoing capital spending program. We recorded a non-cash asset impairment charge at June 30, 2015 of approximately $54.8 million, which reflects the excess of the carrying value of net assets of the Offshore Business at June 30, 2015 over their comparable estimated fair value based on the transaction price. The carrying value of the net assets of the Offshore Business at June 30, 2015 totaled approximately $1.59 billion, which included current assets of $26.9 million, property plant and equipment of $1.14 billion, investments in unconsolidated affiliates of $482.4 million, intangible assets of $37.1 million and goodwill of $82.0 million. Total liabilities were $116.4 million and noncontrolling interests were $62.2 million at that date. The fair value of the Offshore Business based on the transaction price was approximately $1.53 billion. Upon closing of the transaction, we recorded a loss on the sale of $12.6 million based on the difference between the proceeds received and the carrying value of the net assets at July 24, 2015. Operating costs and expenses for the nine months ended September 30, 2015 include $40.1 million of depreciation expense associated with the Offshore Business. Likewise, for the three and nine months ended September 30, 2014, we recognized $21.5 million and $62.3 million, respectively, of depreciation expense associated with these assets. Asset Retirement Obligations We record asset retirement obligations (“AROs”) in connection with legal requirements to perform specified retirement activities under contractual arrangements and/or governmental regulations. Our contractual AROs primarily result from right-of-way agreements associated with our pipeline operations and real estate leases associated with our plant sites. In addition, we record AROs in connection with governmental regulations associated with the abandonment or retirement of above-ground brine storage pits and certain marine vessels. We also record AROs in connection with regulatory requirements associated with the renovation or demolition of certain assets containing hazardous substances such as asbestos. We typically fund our AROs using cash flow from operations. Property, plant and equipment at September 30, 2015 and December 31, 2014 includes $17.8 million and $31.3 million, respectively, of asset retirement costs capitalized as an increase in the associated long-lived asset. The following table presents information regarding our AROs since December 31, 2014: ARO liability balance, December 31, 2014 $ 98.3 Liabilities incurred 2.7 Liabilities settled (5.9 ) Revisions in estimated cash flows 49.0 Accretion expense 4.2 AROs related to Offshore Business sold in July 2015 (91.1 ) ARO liability balance, September 30, 2015 $ 57.2 Revisions to estimated cash flows include a $39.5 million adjustment made in the second quarter of 2015 related to the Matagorda Gathering System, which was a component of the Offshore Business. In June 2015, we were notified by the U.S. Army Corps of Engineers (the “CoE”) to fully remove two pipeline segments included in this system that we had originally requested to abandon in-place. As a result, we adjusted the ARO liabilities for those pipeline segments under CoE jurisdiction to account for the estimated cost of removal. All ARO liabilities related to our Offshore Business (including those of the Matagorda Gathering System) were removed from our Unaudited Condensed Consolidated Balance Sheet upon the sale of the Offshore Business on July 24, 2015. Certain of our unconsolidated affiliates have AROs recorded at September 30, 2015 and December 31, 2014 relating to contractual agreements and regulatory requirements. These amounts are immaterial to our consolidated financial statements.

Investments in Unconsolidated A

Investments in Unconsolidated Affiliates	9 Months Ended
	Sep. 30, 2015
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. We account for these investments using the equity method. Ownership Interest at September 30, 2015 September 30, 2015 December 31, 2014 NGL Pipelines & Services: Venice Energy Service Company, L.L.C. 13.1% $ 26.4 $ 27.7 K/D/S Promix, L.L.C. 50% 42.8 38.5 Baton Rouge Fractionators LLC 32.2% 18.4 18.8 Skelly-Belvieu Pipeline Company, L.L.C. 50% 40.3 40.1 Texas Express Pipeline LLC 35% 343.4 349.3 Texas Express Gathering LLC 45% 37.2 37.9 Front Range Pipeline LLC 33.3% 171.7 170.0 Delaware Basin Gas Processing LLC (1) 50% 28.7 -- Crude Oil Pipelines & Services: Seaway Crude Pipeline Company LLC 50% 1,403.1 1,431.2 Eagle Ford Pipeline LLC 50% 391.4 336.5 Eagle Ford Terminals Corpus Christi LLC (2) 50% 23.4 -- Natural Gas Pipelines & Services: White River Hub, LLC 50% 23.1 23.2 Petrochemical & Refined Products Services: Baton Rouge Propylene Concentrator, LLC 30% 5.8 6.5 Centennial Pipeline LLC (“Centennial”) 50% 67.2 66.1 Other Various 2.4 2.5 Offshore Pipelines & Services: Poseidon Oil Pipeline Company, L.L.C. -- -- 31.8 Cameron Highway Oil Pipeline Company -- -- 201.3 Deepwater Gateway, L.L.C. -- -- 79.6 Neptune Pipeline Company, L.L.C. -- -- 34.9 Southeast Keathley Canyon Pipeline Company L.L.C. -- -- 146.1 Total investments in unconsolidated affiliates $ 2,625.3 $ 3,042.0 (1) New joint venture formed with Oxy Delaware Basin Plant, LLC, a subsidiary of Occidental Petroleum Corporation, in April 2015 that will plan, design and construct a new cryogenic natural gas processing plant to accommodate the growing production of NGL-rich natural gas in the Delaware Basin. (2) New joint venture formed with Plains Marketing, L.P., a subsidiary of Plains All American Pipeline, L.P., in March 2015 to construct and operate a marine terminal that will handle crude oil delivered by Eagle Ford Pipeline LLC. (3) Our investments in unconsolidated affiliates classified within the Offshore Pipelines & Services segment were sold to Genesis on July 24, 2015 (see Note 6). At June 30, 2015, the carrying value of these investments was $482.4 million. The following table presents our equity in income (loss) of unconsolidated affiliates by business segment for the periods indicated: For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 NGL Pipelines & Services $ 18.9 $ 11.7 $ 43.0 $ 19.2 Crude Oil Pipelines & Services 81.2 46.8 220.5 131.7 Natural Gas Pipelines & Services 0.9 0.9 2.8 2.7 Petrochemical & Refined Products Services (3.3 ) (4.2 ) (10.4 ) (10.3 ) Offshore Pipelines & Services 5.4 17.1 46.6 35.8 Total $ 103.1 $ 72.3 $ 302.5 $ 179.1 The following table presents our unamortized excess cost amounts by business segment at the dates indicated: September 30, 2015 December 31, 2014 NGL Pipelines & Services $ 25.6 $ 26.5 Crude Oil Pipelines & Services 20.9 21.7 Petrochemical & Refined Products Services 2.4 2.4 Offshore Pipelines & Services (1) -- 9.0 Total $ 48.9 $ 59.6 (1) Our investments in unconsolidated affiliates classified within the Offshore Pipelines & Services segment were sold to Genesis in July 2015. The following table presents our amortization of excess cost amounts by business segment for the periods indicated: For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 NGL Pipelines & Services $ 0.3 $ 0.2 $ 0.9 $ 0.9 Crude Oil Pipelines & Services 0.3 0.2 0.8 0.5 Petrochemical & Refined Products Services -- -- -- 0.1 Offshore Pipelines & Services -- 0.3 2.8 0.8 Total $ 0.6 $ 0.7 $ 4.5 $ 2.3 Other Centennial’s credit agreement restricts its ability to pay cash dividends if a default or event of default (as defined in the credit agreement) has occurred and is continuing at the time such payments are scheduled to be paid. This business was in compliance with the terms of its credit agreement at September 30, 2015.

Business Acquisitions

Business Acquisitions	9 Months Ended
	Sep. 30, 2015
Business Combinations [Abstract]
Business Combinations	Acquisition of Eagle Ford Midstream Assets In June 2015, we announced the execution of definitive agreements to purchase all of the member interests in EFS Midstream from affiliates of Pioneer and Reliance for approximately $2.1 billion. The purchase price will be paid in two installments. The first installment of approximately $1.1 billion was paid at closing on July 8, 2015 and the final installment of $1.0 billion will be paid no later than the first anniversary of the closing date. The effective date of the acquisition was July 1, 2015. We funded the cash consideration for the first installment using proceeds from the issuance of short-term notes under our commercial paper program and cash on hand. EFS Midstream provides natural gas gathering, treating and compression and condensate gathering and processing services in the Eagle Ford Shale. The EFS Midstream system includes approximately 460 miles of natural gas and condensate gathering pipelines, ten central gathering plants, 780 million cubic feet per day (“MMcf/d”) of natural gas treating capacity and 119 thousand barrels per day (“MBPD”) of condensate stabilization capacity. Under terms of the associated agreements, Pioneer and Reliance have dedicated certain of their Eagle Ford Shale acreage to us under 20-year, fixed-fee gathering agreements that include minimum volume requirement for the first seven years. Pioneer and Reliance have also entered into related 20-year fee-based agreements with us for natural gas transportation and processing, NGL transportation and fractionation, and for processed condensate and crude oil transportation services. We account for business acquisitions by applying the acquisition method of accounting. The acquisition method of accounting requires, among other things, that the assets acquired and liabilities assumed in a business combination be measured at their fair values as of the effective date of the acquisition. We engaged an independent third party business valuation expert to assist us in estimating the fair values of the tangible and intangible assets of EFS Midstream. The following table summarizes the consideration paid in the EFS Midstream acquisition and the amounts of the assets acquired and liabilities assumed as of July 1, 2015: Consideration: Cash $ 1,058.5 Accrued liability related to EFS Midstream acquisition 997.7 Total consideration $ 2,056.2 Identifiable assets acquired in business combination: Current assets, including cash of $13.4 million $ 64.0 Property, plant and equipment 636.0 Customer relationship intangible assets 1,409.8 Total assets acquired 2,109.8 Liabilities assumed in business combination: Current liabilities (9.6 ) Long-term debt (125.0 ) Other long-term liabilities (1.3 ) Total liabilities assumed (135.9 ) Total assets acquired less liabilities assumed 1,973.9 Total consideration given for EFS Midstream 2,056.2 Goodwill $ 82.3 The estimated fair value of the acquired property, plant and equipment was determined using the cost approach. Of the $636 million of fair value assigned to property, plant and equipment, $366 million was assigned to pipelines and rights of way, $112 million to processing equipment, $84 million to electrical and metering equipment, $42 million to pumps and compressors and $32 million to other assets. The estimated fair value of the acquired customer relationship intangible assets was determined using an income approach, specifically a discounted cash flow analysis. Of the total assets acquired, $1.41 billion, or 67%, was assigned to customer relationship intangible assets. In the context of EFS Midstream, a customer relationship intangible asset is broadly defined as a relationship between an asset network and the underlying production fields and producers (e.g., Pioneer and Reliance) supported by that network. The customer relationships we acquired in this transaction provide us with long-term access to the natural gas, NGL and condensate resources supported by the EFS Midstream assets. Infrastructure such as that owned by EFS Midstream requires a significant investment, both in terms of initial construction costs and ongoing maintenance, and is generally supported by long-term contracts with producers that establish a customer base. The level of expenditures involved in constructing such asset networks can create significant economic barriers to entry that effectively limit competition (i.e., akin to a franchise). The long-term nature of the underlying producer contracts and limited risk of competition ensure a long commercial relationship with existing producers. The discounted cash flow analysis used to estimate the fair value of the EFS Midstream customer relationships relied on Level 3 fair value inputs. Level 3 fair values are based on unobservable inputs. Unobservable inputs are used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset at the measurement date. With respect to the EFS Midstream customer relationships, the Level 3 inputs include long-range cash flow forecasts that extend for the estimated economic life of the hydrocarbon resource base served by the asset network, anticipated contract renewals and resource base depletion rates. A discount rate of 15% was applied to the resulting cash flows. We recorded $82.3 million of goodwill in connection with this transaction. In general, we attribute this goodwill to our ability to leverage the acquired business with our existing asset base to create future business opportunities. In connection with the agreements to acquire EFS Midstream, we are obligated to spend up to an aggregate of $270 million on specified midstream gathering assets for Pioneer and Reliance, if requested by these producers, over a ten year period. If constructed, these new assets would be owned by us and be a component of the EFS Midstream asset network. Our consolidated revenues and net income included $56.7 million and $23.8 million, respectively, from EFS Midstream for the three months ended September 30, 2015. Since the effective date of the EFS Midstream acquisition was July 1, 2015, our Unaudited Condensed Statements of Consolidated Operations do not include earnings from this business prior to this date. The following table presents selected unaudited pro forma earnings information for the nine months ended September 30, 2015 and 2014 as if the acquisition had been completed on January 1, 2014. This pro forma information was prepared using historical financial data for EFS Midstream and reflects certain estimates and assumptions made by our management. Our unaudited pro forma financial information is not necessarily indicative of what our consolidated financial results would have been for the periods presented had we acquired EFS Midstream on January 1, 2014. For the Three Months Ended September 30, 2014 For the Nine Months Ended September 30, 2015 2014 Pro forma earnings data: Revenues $ 12,388.7 $ 20,993.5 $ 37,927.5 Costs and expenses 11,502.6 18,645.5 35,195.2 Operating income 958.4 2,650.5 2,911.4 Net income 715.3 1,900.9 2,195.5 Net income attributable to noncontrolling interests 8.1 28.5 24.8 Net income attributable to limited partners 707.2 1,872.4 2,170.7 Basic earnings per unit: As reported basic earnings per unit $ 0.38 $ 0.94 $ 1.16 Pro forma basic earnings per unit $ 0.38 $ 0.96 $ 1.18 Diluted earnings per unit: As reported diluted earnings per unit $ 0.37 $ 0.92 $ 1.13 Pro forma diluted earnings per unit $ 0.38 $ 0.94 $ 1.15

Intangible Assets and Goodwill

Intangible Assets and Goodwill	9 Months Ended
	Sep. 30, 2015
Intangible Assets and Goodwill [Abstract]
Intangible Assets and Goodwill	Intangible Assets The following table summarizes our intangible assets by business segment at the dates indicated: September 30, 2015 December 31, 2014 Gross Value Accumulated Amortization Carrying Value Gross Value Accumulated Amortization Carrying Value NGL Pipelines & Services: Customer relationship intangibles $ 550.8 $ (183.8 ) $ 367.0 $ 340.8 $ (183.2 ) $ 157.6 Contract-based intangibles 283.0 (189.6 ) 93.4 277.7 (178.7 ) 99.0 IDRs (1) -- -- -- 432.6 -- 432.6 Segment total 833.8 (373.4 ) 460.4 1,051.1 (361.9 ) 689.2 Crude Oil Pipelines & Services: Customer relationship intangibles 2,204.4 (28.1 ) 2,176.3 1,108.0 (7.7 ) 1,100.3 Contract-based intangibles 281.4 (55.4 ) 226.0 281.4 (13.5 ) 267.9 IDRs (1) -- -- -- 855.4 -- 855.4 Segment total 2,485.8 (83.5 ) 2,402.3 2,244.8 (21.2 ) 2,223.6 Natural Gas Pipelines & Services: Customer relationship intangibles 1,246.9 (327.8 ) 919.1 1,163.6 (308.9 ) 854.7 Contract-based intangibles 466.0 (359.4 ) 106.6 466.0 (347.8 ) 118.2 Segment total 1,712.9 (687.2 ) 1,025.7 1,629.6 (656.7 ) 972.9 Petrochemical & Refined Products Services: Customer relationship intangibles 185.5 (37.3 ) 148.2 198.4 (43.3 ) 155.1 Contract-based intangibles 56.3 (10.8 ) 45.5 56.3 (7.8 ) 48.5 IDRs (1) -- -- -- 171.2 -- 171.2 Segment total 241.8 (48.1 ) 193.7 425.9 (51.1 ) 374.8 Offshore Pipelines & Services: Customer relationship intangibles -- -- -- 195.8 (154.9 ) 40.9 Contract-based intangibles -- -- -- 1.2 (0.5 ) 0.7 Segment total -- -- -- 197.0 (155.4 ) 41.6 Total intangible assets $ 5,274.3 $ (1,192.2 ) 4,082.1 $ 5,548.4 $ (1,246.3 ) $ 4,302.1 (1) At December 31, 2014, we had indefinite-lived intangible assets outstanding with a carrying value of $1.46 billion recorded in connection with our acquisition of the Oiltanking IDRs in October 2014. The IDRs represented contractual rights to future cash incentive distributions to be paid by Oiltanking. In February 2015 (following completion of Step 2 of the Oiltanking acquisition), the Oiltanking IDRs were cancelled and the carrying value of the IDRs were reclassified to goodwill. (2) Our intangible assets classified within the Offshore Pipelines & Services segment were sold to Genesis in July 2015 (see Note 6). We acquired $1.41 billion of customer relationship intangible assets as part of the EFS Midstream acquisition (see Note 8). We assigned $1.1 billion of these intangible assets to our Crude Oil Pipelines & Services segment, $230.1 million to our NGL Pipelines & Services segment and $83.3 million to our Natural Gas Pipelines & Services segment based on the nature of the services provided in connection with these relationships. These customer relationships have estimated economic lives ranging from 26 to 29 years. Amortization expense attributable to these customer relationships is recorded using a units-of-production method that closely resembles the pattern in which the economic benefits we derive from such assets are expected to be consumed or otherwise used. The following table presents the amortization expense of our intangible assets by business segment for the periods indicated: For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 NGL Pipelines & Services $ 9.7 $ 8.1 $ 24.9 $ 25.4 Crude Oil Pipelines & Services 29.0 0.3 62.3 0.9 Natural Gas Pipelines & Services 10.7 11.1 30.5 34.2 Petrochemical & Refined Products Services 2.3 1.5 7.0 4.6 Offshore Pipelines & Services -- 2.5 4.5 7.6 Total $ 51.7 $ 23.5 $ 129.2 $ 72.7 The following table presents a forecast of amortization expense associated with our intangible assets for the periods indicated: Remainder of 2015 2016 2017 2018 2019 $ 50.3 $ 218.8 $ 223.5 $ 220.4 $ 208.6 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. The following table presents changes in the carrying amount of goodwill since December 31, 2014: NGL Pipelines & Services Crude Oil Pipelines & Services Natural Gas Pipelines & Services Petrochemical & Refined Products Services Offshore Pipelines & Services Consolidated Total Balance at December 31, 2014 $ 2,210.2 $ 918.7 $ 296.3 $ 793.0 $ 82.0 $ 4,300.2 Reclassification of Oiltanking IDR balances to goodwill in connection with the cancellation of such rights in February 2015 and other adjustments 432.6 850.7 -- 170.8 -- 1,454.1 Reduction in goodwill related to the sale of assets -- -- -- -- (82.0 ) (82.0 ) Addition to goodwill related to the acquisition of EFS Midstream 8.9 73.4 -- -- -- 82.3 Goodwill reclassified to assets held-for-sale -- -- -- (5.4 ) -- (5.4 ) Balance at September 30, 2015 $ 2,651.7 $ 1,842.8 $ 296.3 $ 958.4 $ -- $ 5,749.2 Upon completion of Step 2 of the Oiltanking acquisition in February 2015, the IDRs of Oiltanking were cancelled and the associated carrying values were reclassified from intangible assets to goodwill and allocated to the appropriate business segments. During 2015, we retrospectively adjusted our provisional fair value estimate of the Liquidity Option Agreement by $100.3 million, with a corresponding increase to goodwill, which was allocated to the appropriate business segments at December 31, 2014 as follows: $29.8 million to NGL Pipelines & Services; $58.8 million to Crude Oil Pipelines & Services; and $11.7 million to Petrochemical & Refined Products Services. See Note 15 for additional information regarding this change. In July 2015, in connection with the sale of the Offshore Business, we removed $82.0 million of goodwill, which was allocated to these assets (see Note 6). In July 2015, we recorded $82.3 million of goodwill in connection with our acquisition of EFS Midstream. In general, we attribute this goodwill to our ability to leverage the acquired business with our existing asset base to create future business opportunities.

Debt Obligations

Debt Obligations	9 Months Ended
	Sep. 30, 2015
Debt Obligations [Abstract]
Debt Obligations	The following table presents our consolidated debt obligations (arranged by company and maturity date) at the dates indicated: September 30, 2015 December 31, 2014 EPO senior debt obligations: Commercial Paper Notes, variable-rates $ 869.5 $ 906.5 Senior Notes I, 5.00% fixed-rate, due March 2015 -- 250.0 Senior Notes X, 3.70% fixed-rate, due June 2015 -- 400.0 Senior Notes FF, 1.25% fixed-rate, due August 2015 -- 650.0 Senior Notes AA, 3.20% fixed-rate, due February 2016 750.0 750.0 364-Day Credit Agreement, variable-rate, due September 2016 -- -- 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 OO, 1.65% fixed-rate, due May 2018 750.0 -- Senior Notes N, 6.50% fixed-rate, due January 2019 700.0 700.0 Senior Notes LL, 2.55% fixed-rate, due October 2019 800.0 800.0 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 Multi-Year Revolving Credit Facility, variable-rate, due September 2020 -- -- Senior Notes CC, 4.05% fixed-rate, due February 2022 650.0 650.0 Senior Notes HH, 3.35% fixed-rate, due March 2023 1,250.0 1,250.0 Senior Notes JJ, 3.90% fixed-rate, due February 2024 850.0 850.0 Senior Notes MM, 3.75% fixed-rate, due February 2025 1,150.0 1,150.0 Senior Notes PP, 3.70% fixed-rate, due February 2026 875.0 -- 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 750.0 750.0 Senior Notes GG, 4.45% fixed-rate, due February 2043 1,100.0 1,100.0 Senior Notes II, 4.85% fixed-rate, due March 2044 1,400.0 1,400.0 Senior Notes KK, 5.10% fixed-rate, due February 2045 1,150.0 1,150.0 Senior Notes QQ, 4.90% fixed-rate, due May 2046 875.0 -- Senior Notes NN, 4.95% fixed-rate, due October 2054 400.0 400.0 TEPPCO senior debt obligations: 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 21,019.5 19,856.5 EPO Junior Subordinated Notes A, fixed/variable-rate, due August 2066 (1) 521.9 550.0 EPO Junior Subordinated Notes C, fixed/variable-rate, due June 2067 259.5 285.8 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 22,497.8 21,389.2 Other, non-principal amounts (37.7 ) (25.4 ) Less current maturities of debt (4) (1,619.4 ) (2,206.4 ) Total long-term debt $ 20,840.7 $ 19,157.4 (1) Fixed rate of 8.375% through August 1, 2016 (i.e., first call date without a make-whole redemption premium); thereafter, variable rate based on 3-month LIBOR plus 3.7075%. During the third quarter of 2015, EPO retired $28.1 million of these junior notes. (2) Fixed rate of 7.0% through September 1, 2017 (i.e., first call date without a make-whole redemption premium); thereafter, variable rate based on 3-month LIBOR plus 2.7775%. During the third quarter of 2015, EPO retired $26.3 million of these junior notes. (3) Fixed rate of 7.034% through January 15, 2018 (i.e., first call date without a make-whole redemption premium); thereafter, the rate will be the greater of 7.034% or a variable rate based on 3-month LIBOR plus 2.68%. (4) We expect to refinance the current maturities of our debt obligations at or prior to their maturity . The following table presents contractually scheduled maturities of our consolidated debt obligations outstanding at September 30, 2015 for the next five years, and in total thereafter: Scheduled Maturities of Debt Total Remainder of 2015 2016 2017 2018 2019 After 2019 Commercial Paper Notes $ 869.5 $ 869.5 $ -- $ -- $ -- $ -- $ -- Senior Notes 20,150.0 -- 750.0 800.0 1,100.0 1,500.0 16,000.0 Junior Subordinated Notes 1,478.3 -- -- -- -- -- 1,478.3 Total $ 22,497.8 $ 869.5 $ 750.0 $ 800.0 $ 1,100.0 $ 1,500.0 $ 17,478.3 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 immaterial 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. Issuance of $2.5 Billion of Senior Notes in May 2015 In May 2015, EPO issued $750 million in principal amount of 1.65% senior notes due May 2018 (“Senior Notes OO”), $875 million in principal amount of 3.70% senior notes due February 2026 (“Senior Notes PP”) and $875 million in principal amount of 4.90% senior notes due May 2046 (“Senior Notes QQ”). Senior Notes OO, PP and QQ were issued at 99.881%, 99.635% and 99.635% of their principal amounts, respectively. Net proceeds from the issuance of these senior notes were used as follows: (i) the repayment of amounts outstanding under EPO’s commercial paper program, which included amounts we used to repay $250 million in principal amount of Senior Notes I that matured in March 2015, (ii) the repayment of amounts outstanding at the maturity of our $400 million in principal amount of Senior Notes X that matured in June 2015 and (iii) for general company purposes. Enterprise Products Partners L.P. has unconditionally guaranteed these senior notes on an unsecured and unsubordinated basis. These senior notes rank equal with EPO’s existing and future unsecured and unsubordinated indebtedness and are senior to any existing and future subordinated indebtedness of EPO. These senior notes are subject to make-whole redemption rights and were 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. Partial Retirement of Junior Subordinated Notes During Third Quarter of 2015 During the third quarter of 2015, EPO retired $28.1 million of its Junior Subordinated Notes A and $26.3 million of its Junior Subordinated Notes C with cash from operations. A $1.4 million gain on the extinguishment of these debt obligations is included in “Other, net” on our Unaudited Condensed Statements of Consolidated Operations. 364-Day Credit Agreement In September 2015, EPO amended its 364-Day Credit Agreement to extend its maturity date to September 2016. There are currently no principal amounts outstanding under this revolving credit agreement. Under the terms of the 364-Day Credit Agreement, EPO may borrow up to $1.5 billion (which may be increased by up to $200 million to $1.7 billion at EPO’s election, provided certain conditions are met) at a variable interest rate for a term of 364 days, subject to the terms and conditions set forth therein. To the extent that principal amounts are outstanding at the maturity date, EPO may elect to have the entire principal balance then outstanding continued as a non-revolving term loan for a period of one additional year, payable in September 2017. The remaining terms of the 364-Day Credit Agreement, as amended, remain materially the same as those reported for the 364-Day Credit Agreement in our 2014 Form 10-K. Multi-Year Revolving Credit Facility In September 2015, EPO amended its Multi-Year Revolving Credit Facility to increase its borrowing capacity from $3.5 billion to $4.0 billion and extend its maturity date from June 2018 to September 2020. The amended agreement also provides that EPO may increase its borrowing capacity to $4.5 billion by allowing existing lenders under the facility to increase their respective commitments or by adding one or more new lenders to the facility. The remaining terms of the Multi-Year Revolving Credit Facility, as amended, remain materially the same as those reported for the Multi-Year Revolving Credit Facility in our 2014 Form 10-K. Letters of Credit At September 30, 2015, EPO had $2.5 million of letters of credit outstanding related to operations at our facilities and motor fuel tax obligations. Lender Financial Covenants We were in compliance with the financial covenants of our consolidated debt agreements at September 30, 2015. 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 during the nine months ended September 30, 2015: Range of Interest Rates Paid Weighted-Average Interest Rate Paid Commercial Paper Notes 0.35% to 0.78% 0.59% EPO Multi-Year Revolving Credit Facility 1.15% to 3.25% 1.30%

Equity and Distributions

Equity and Distributions	9 Months Ended
	Sep. 30, 2015
Equity and Distributions [Abstract]
Equity and Distributions	Partners’ equity reflects the various classes of limited partner interests (i.e., common units, including restricted common units) that we have outstanding. The following table summarizes changes in the number of our outstanding units since December 31, 2014: Common Units (Unrestricted) Restricted Common Units Total Common Units Number of units outstanding at December 31, 2014 1,933,095,027 4,229,790 1,937,324,817 Common units issued in connection with ATM program 23,258,453 -- 23,258,453 Common units issued in connection with DRIP and EUPP 8,251,315 -- 8,251,315 Common units issued in connection with Step 2 of Oiltanking acquisition 36,827,517 -- 36,827,517 Common units issued in connection with the vesting and exercise of unit options 333,002 -- 333,002 Common units issued in connection with the vesting of phantom unit awards 613,689 -- 613,689 Common units issued in connection with the vesting of restricted common unit awards 1,997,194 (1,997,194) -- Forfeiture of restricted common unit awards -- (157,750) (157,750) Acquisition and cancellation of treasury units in connection with the vesting of equity-based awards (680,496) -- (680,496) Other 15,054 -- 15,054 Number of units outstanding at September 30, 2015 2,003,710,755 2,074,846 2,005,785,601 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 “2013 Shelf”) on file with the SEC. The 2013 Shelf allows Enterprise Products Partners L.P. and EPO (on a standalone basis) to issue an unlimited amount of equity and debt securities. On July 1, 2015, we filed a registration statement with the SEC covering the issuance of up to $1.92 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 (“ATM program”), we may sell common units under an equity distribution agreement between Enterprise Products Partners L.P. and certain broker-dealers 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. The new registration statement was declared effective on August 3, 2015 and replaced our prior registration statement with respect to the ATM program, which was filed with the SEC in October 2013 and covered the issuance of up to $1.25 billion of our common units. Immediately prior to the effectiveness of the new registration statement, we had the capacity to issue additional common units under the ATM program up to an aggregate sales price of $424.6 million (after giving effect to sales of common units previously made under the program). Following the effectiveness of the new registration statement and after taking into account the aggregate sales price of common units sold under our ATM program through September 30, 2015 as described below, we now have the capacity to issue additional common units under our ATM program up to an aggregate sales price of $1.92 billion. During the nine months ended September 30, 2015, we issued 23,258,453 common units under the ATM program for aggregate gross proceeds of $767.1 million. This includes 3,225,057 common units sold in March 2015 to a privately held affiliate of EPCO, which generated gross proceeds of $100 million. After taking into account applicable costs, our transactions under the ATM program resulted in aggregate net cash proceeds of $759.7 million during the nine months ended September 30, 2015. During the nine months ended September 30, 2014, we issued 1,590,334 common units under this program for aggregate gross cash proceeds of $58.3 million, resulting in total net cash proceeds of $57.7 million. We also have registration statements on file with the SEC collectively authorizing the issuance of up to 140,000,000 of our common units in connection with a distribution reinvestment plan (“DRIP”). We issued a total of 7,965,318 common units under our DRIP during the nine months ended September 30, 2015, which generated net cash proceeds of $242.8 million. During the nine months ended September 30, 2014, we issued 7,148,778 common units under our DRIP, which generated net cash proceeds of $239.8 million. Privately held affiliates of EPCO reinvested $50 million and $75 million through the DRIP in each of the nine month periods ending September 30, 2015 and 2014, respectively (this amount being a component of the net cash proceeds presented for both periods). After taking into account the number of common units issued under the DRIP through September 30, 2015, we have the capacity to issue an additional 19,516,031 common units under this plan. In addition to the DRIP, we have registration statements on file with the SEC authorizing the issuance of up to 8,000,000 of our common units in connection with our employee unit purchase plan (“EUPP”). We issued 285,997 common units under our EUPP during the nine months ended September 30, 2015, which generated net cash proceeds of $8.9 million. During the nine months ended September 30, 2014, we issued 207,126 common units under our EUPP, which generated net cash proceeds of $7.4 million. After taking into account the number of common units issued under the EUPP through September 30, 2015, we may issue an additional 6,867,071 common units under this plan. The net cash proceeds we received from the issuance of common units during the nine months ended September 30, 2015 were used to temporarily reduce amounts outstanding under EPO’s commercial paper program and revolving credit facilities and for general company purposes. Completion of Oiltanking Acquisition In October 2014, we completed the first step (“Step 1”) of a two-step acquisition of Oiltanking by paying approximately $4.41 billion to OTA for Oiltanking GP, the related IDRs and approximately 65.9% of the limited partner interests of Oiltanking. As a second step (“Step 2”) of the Oiltanking acquisition (separately negotiated by the conflicts committee of Oiltanking GP on behalf of Oiltanking), we entered into an Agreement and Plan of Merger (the “merger agreement”) with Oiltanking in November 2014 that provided for the following: § the merger of a wholly owned subsidiary of Enterprise with and into Oiltanking, with Oiltanking surviving the merger as a wholly owned subsidiary of Enterprise; and § all outstanding common units of Oiltanking at the effective time of the merger held by Oiltanking’s public unitholders (which consisted of Oiltanking unitholders other than Enterprise and its subsidiaries) to be cancelled and converted into Enterprise common units based on an exchange ratio of 1.30 Enterprise common units for each Oiltanking common unit. In accordance with the merger agreement and Oiltanking’s partnership agreement, the merger was submitted to a vote of Oiltanking’s common unitholders, with the required majority of unitholders (including our ownership interests) voting to approve the merger on February 13, 2015. Upon approval of the merger, a total of 36,827,517 of our common units were issued to Oiltanking’s former public unitholders. With the completion of Step 2, total consideration paid by Enterprise for Oiltanking was approximately $5.9 billion. Step 2 of the acquisition was accounted for in accordance with ASC Topic 810, Consolidations – Overall – Changes in Parent’s Ownership Interest in a Subsidiary See Note 15 for information regarding requests from the Federal Trade Commission (“FTC”) and the Attorney General of the State of Texas in connection with the Oiltanking acquisition. We consider our purchase price allocation for the Oiltanking acquisition to be final. We finalized the determination of the fair value of the Liquidity Option Agreement during the third quarter of 2015. Subsequent changes in the fair value of this option will be recorded in earnings each reporting period until the option expires or is exercised. Noncontrolling Interests Noncontrolling interests represent third party equity ownership interests in our consolidated subsidiaries, including Enterprise EF78 LLC, Rio Grande Pipeline Company, Tri-States NGL Pipeline L.L.C., Panola Pipeline Company, LLC and Wilprise Pipeline Company LLC. In July 2015, as part of the sale of our Offshore Business to Genesis, we sold our ownership interests in Independence Hub LLC and no longer report this third party ownership as noncontrolling interests. As previously described, we reclassified approximately $1.4 billion of noncontrolling interests to limited partners’ equity in connection with completing Step 2 of the Oiltanking acquisition in February 2015. Cash distributions paid in the first quarter of 2015 to the limited partners of Oiltanking other than EPO and its subsidiaries are presented as amounts paid to noncontrolling interests. In February 2015, we formed a joint venture involving our Panola NGL Pipeline with affiliates of Anadarko Petroleum Corporation (“Anadarko”), DCP Midstream Partners, LP (“DCP”) and MarkWest Energy Partners, L.P. (“MarkWest”). We will continue to serve as operator of the Panola Pipeline and own 55% of the member interests in the joint venture. Affiliates of Anadarko, DCP and MarkWest will own the remaining 45% member interests, with each holding a 15% interest. The Panola Pipeline transports mixed NGLs from points near Carthage, Texas to Mont Belvieu, Texas and supports the Haynesville and Cotton Valley oil and gas production areas. Accumulated Other Comprehensive Income (Loss) The following tables present the components of accumulated other comprehensive income (loss) as reported on our Unaudited Condensed Consolidated Balance Sheets at the dates indicated: Gains (Losses) on Cash Flow Hedges Commodity Derivative Instruments Interest Rate Derivative Instruments Other Total Balance, December 31, 2014 $ 69.9 $ (314.8 ) $ 3.3 $ (241.6 ) Other comprehensive income before reclassifications 112.3 -- 0.4 112.7 Amounts reclassified from accumulated other comprehensive loss (income) (128.1 ) 26.3 -- (101.8 ) Total other comprehensive income (loss) (15.8 ) 26.3 0.4 10.9 Balance, September 30, 2015 $ 54.1 $ (288.5 ) $ 3.7 $ (230.7 ) Gains (Losses) on Cash Flow Hedges Commodity Derivative Instruments Interest Rate Derivative Instruments Other Total Balance, December 31, 2013 $ (14.7 ) $ (347.2 ) $ 2.9 $ (359.0 ) Other comprehensive income before reclassifications 16.1 -- -- 16.1 Amounts reclassified from accumulated other comprehensive loss 12.9 23.9 -- 36.8 Total other comprehensive income 29.0 23.9 -- 52.9 Balance, September 30, 2014 $ 14.3 $ (323.3 ) $ 2.9 $ (306.1 ) The following table presents reclassifications out of accumulated other comprehensive income (loss) into net income during the periods indicated: For the Three Months Ended September 30, For the Nine Months Ended September 30, Location 2015 2014 2015 2014 Losses (gains) on cash flow hedges: Interest rate derivatives Interest expense $ 8.9 $ 8.0 $ 26.3 $ 23.9 Commodity derivatives Revenue (46.8 ) (17.8 ) (128.6 ) 14.5 Commodity derivatives Operating costs and expenses -- (0.2 ) 0.5 (1.6 ) Total $ (37.9 ) $ (10.0 ) $ (101.8 ) $ 36.8 Cash Distributions The following table presents our declared quarterly cash distribution rates per common unit with respect to the quarter indicated: Distribution Per Common Unit Record Date Payment Date 2014: 1st Quarter $ 0.3550 4/30/2014 5/7/2014 2nd Quarter $ 0.3600 7/31/2014 8/7/2014 3rd Quarter $ 0.3650 10/31/2014 11/7/2014 2015: 1st Quarter $ 0.3750 4/30/2015 5/7/2015 2nd Quarter $ 0.3800 7/31/2015 8/7/2015 3rd Quarter $ 0.3850 10/30/2015 11/6/2015 In November 2010, we completed our merger with Enterprise GP Holdings L.P. (the “Holdings Merger”). In connection with the Holdings Merger, a privately held affiliate of EPCO agreed to temporarily waive the regular cash distributions it would otherwise receive from us with respect to a certain number of our common units it owns (the “Designated Units”). Distributions paid by us to this privately held affiliate of EPCO during 2015 excluded 35,380,000 Designated Units. The temporary distribution waiver expires at the end of calendar year 2015; therefore, distributions to be paid, if any, during calendar year 2016 will include all common units owned by the privately held affiliates of EPCO.

Business Segments

Business Segments	9 Months Ended
	Sep. 30, 2015
Business Segments [Abstract]
Business Segments	Our historical operations are reported under five business segments: (i) NGL Pipelines & Services, (ii) Crude Oil Pipelines & Services, (iii) Natural Gas Pipelines & Services, (iv) Petrochemical & Refined Products Services and (v) Offshore Pipelines & Services. Our business segments are generally organized and managed according to the types of services rendered (or technologies employed) and products produced and/or sold. Our consolidated financial statements reflect ownership of the Offshore Business through July 24, 2015, which was the closing date of the sales transaction. See Note 6 for additional information related to the sale of our Offshore Business. Segment revenues include intersegment and intrasegment transactions, which are generally based on transactions made at market-based rates. Our consolidated revenues reflect the elimination of intercompany transactions. Substantially all of our consolidated revenues are earned in the U.S. and derived from a wide customer base. 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 executive 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. In total, gross operating margin represents operating income exclusive of (1) depreciation, amortization and accretion expenses, (2) impairment charges, (3) gains and losses attributable to asset sales and insurance recoveries and (4) general and administrative costs. Gross operating margin includes equity in income of unconsolidated affiliates and non-refundable deferred transportation revenues relating to the make-up rights of committed shippers associated with certain pipelines. Gross operating margin by segment is calculated by subtracting segment operating costs and expenses (net of the adjustments noted above) from segment revenues, with both segment totals before the elimination of intercompany transactions. In accordance with GAAP, intercompany accounts and transactions are eliminated in consolidation. Gross operating margin is exclusive of other income and expense transactions, 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. Segment assets consist of property, plant and equipment, investments in unconsolidated affiliates, intangible assets and goodwill. The carrying values of such amounts are assigned to each segment based on each asset’s or investment’s principal operations and contribution to the gross operating margin of that particular segment. Since construction-in-progress amounts (a component of property, plant and equipment) generally do not contribute to segment gross operating margin, such amounts are excluded from segment asset totals until the underlying assets are placed in service. Intangible assets and goodwill are assigned to each segment based on the classification of the assets to which they relate. Substantially all of our plants, pipelines and other fixed assets are located in the U.S. The following table presents our measurement of non-GAAP total segment gross operating margin for the periods indicated: For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 Revenues $ 6,307.9 $ 12,330.2 $ 20,872.9 $ 37,760.9 Subtract operating costs and expenses (5,452.6 ) (11,414.8 ) (18,426.5 ) (34,934.4 ) Add equity in income of unconsolidated affiliates 103.1 72.3 302.5 179.1 Add depreciation, amortization and accretion expense amounts not reflected in gross operating margin 351.1 322.7 1,082.0 936.5 Add impairment charges not reflected in gross operating margin 26.8 5.7 139.1 18.2 Add net losses or subtract net gains attributable to asset sales and insurance recoveries not reflected in gross operating margin (see Note 16) 12.3 (2.6 ) 14.7 (99.0 ) Add non-refundable deferred revenues attributable to shipper make-up rights on new pipeline projects reflected in gross operating margin 3.4 21.6 39.3 66.8 Subtract subsequent recognition of deferred revenues attributable to make-up rights not reflected in gross operating margin (10.9 ) -- (45.3 ) -- Total segment gross operating margin $ 1,341.1 $ 1,335.1 $ 3,978.7 $ 3,928.1 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 September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 Total segment gross operating margin $ 1,341.1 $ 1,335.1 $ 3,978.7 $ 3,928.1 Adjustments to reconcile total segment gross operating margin to operating income: Subtract depreciation, amortization and accretion expense amounts not reflected in gross operating margin (351.1 ) (322.7 ) (1,082.0 ) (936.5 ) Subtract impairment charges not reflected in gross operating margin (26.8 ) (5.7 ) (139.1 ) (18.2 ) Add net gains or subtract net losses attributable to asset sales and insurance recoveries not reflected in gross operating margin (12.3 ) 2.6 (14.7 ) 99.0 Subtract non-refundable deferred revenues attributable to shipper make-up rights on new pipeline projects reflected in gross operating margin (3.4 ) (21.6 ) (39.3 ) (66.8 ) Add subsequent recognition of deferred revenues attributable to make-up rights not reflected in gross operating margin 10.9 -- 45.3 -- Subtract general and administrative costs not reflected in gross operating margin (49.0 ) (50.0 ) (143.2 ) (150.9 ) Operating income 909.4 937.7 2,605.7 2,854.7 Other expense, net (246.2 ) (230.8 ) (736.4 ) (679.8 ) Income before income taxes $ 663.2 $ 706.9 $ 1,869.3 $ 2,174.9 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 Crude Oil Pipelines & Services Natural Gas Pipelines & Services Petrochemical & Refined Products Services Offshore Pipelines & Services Adjustments and Eliminations Consolidated Total Revenues from third parties: Three months ended September 30, 2015 $ 2,284.6 $ 2,316.4 $ 705.2 $ 980.0 $ 7.8 $ -- $ 6,294.0 Three months ended September 30, 2014 4,024.0 5,435.6 1,026.5 1,792.0 41.1 -- 12,319.2 Nine months ended September 30, 2015 7,223.2 8,080.4 2,117.5 3,347.6 76.9 -- 20,845.6 Nine months ended September 30, 2014 13,217.2 16,236.6 3,261.0 4,869.9 112.4 -- 37,697.1 Revenues from related parties: Three months ended September 30, 2015 2.2 6.2 4.5 -- 1.0 -- 13.9 Three months ended September 30, 2014 2.7 1.5 5.4 -- 1.4 -- 11.0 Nine months ended September 30, 2015 6.0 8.6 10.8 -- 1.9 -- 27.3 Nine months ended September 30, 2014 10.2 31.1 16.5 -- 6.0 -- 63.8 Intersegment and intrasegment revenues: Three months ended September 30, 2015 2,461.0 1,142.1 180.2 267.3 0.1 (4,050.7 ) -- Three months ended September 30, 2014 3,603.8 2,529.5 231.0 452.2 1.2 (6,817.7 ) -- Nine months ended September 30, 2015 7,685.1 3,958.9 519.7 875.8 0.6 (13,040.1 ) -- Nine months ended September 30, 2014 10,789.7 10,714.5 835.8 1,317.6 4.8 (23,662.4 ) -- Total revenues: Three months ended September 30, 2015 4,747.8 3,464.7 889.9 1,247.3 8.9 (4,050.7 ) 6,307.9 Three months ended September 30, 2014 7,630.5 7,966.6 1,262.9 2,244.2 43.7 (6,817.7 ) 12,330.2 Nine months ended September 30, 2015 14,914.3 12,047.9 2,648.0 4,223.4 79.4 (13,040.1 ) 20,872.9 Nine months ended September 30, 2014 24,017.1 26,982.2 4,113.3 6,187.5 123.2 (23,662.4 ) 37,760.9 Equity in income (loss) of unconsolidated affiliates: Three months ended September 30, 2015 18.9 81.2 0.9 (3.3 ) 5.4 -- 103.1 Three months ended September 30, 2014 11.7 46.8 0.9 (4.2 ) 17.1 -- 72.3 Nine months ended September 30, 2015 43.0 220.5 2.8 (10.4 ) 46.6 -- 302.5 Nine months ended September 30, 2014 19.2 131.7 2.7 (10.3 ) 35.8 -- 179.1 Gross operating margin: Three months ended September 30, 2015 695.5 254.6 192.4 191.5 7.1 -- 1,341.1 Three months ended September 30, 2014 711.5 190.8 195.4 190.3 47.1 -- 1,335.1 Nine months ended September 30, 2015 2,041.3 704.2 588.3 547.4 97.5 -- 3,978.7 Nine months ended September 30, 2014 2,172.4 534.5 618.8 482.4 120.0 -- 3,928.1 Property, plant and equipment, net: (see Note 6) At September 30, 2015 12,192.8 3,550.0 8,680.6 3,013.5 -- 3,777.2 31,214.1 At December 31, 2014 11,766.9 2,332.2 8,835.5 3,047.2 1,145.1 2,754.7 29,881.6 Investments in unconsolidated affiliates: (see Note 7) At September 30, 2015 708.9 1,817.9 23.1 75.4 -- -- 2,625.3 At December 31, 2014 682.3 1,767.7 23.2 75.1 493.7 -- 3,042.0 Intangible assets, net: At September 30, 2015 460.4 2,402.3 1,025.7 193.7 -- -- 4,082.1 At December 31, 2014 689.2 2,223.6 972.9 374.8 41.6 -- 4,302.1 Goodwill: At September 30, 2015 2,651.7 1,842.8 296.3 958.4 -- -- 5,749.2 At December 31, 2014 2,210.2 918.7 296.3 793.0 82.0 -- 4,300.2 Segment assets: At September 30, 2015 16,013.8 9,613.0 10,025.7 4,241.0 -- 3,777.2 43,670.7 At December 31, 2014 15,348.6 7,242.2 10,127.9 4,290.1 1,762.4 2,754.7 41,525.9 The following table presents additional information regarding our consolidated revenues and costs and expenses for the periods indicated: For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 NGL Pipelines & Services: Sales of NGLs and related products $ 1,844.9 $ 3,603.4 $ 5,936.2 $ 12,029.8 Midstream services 441.9 423.3 1,293.0 1,197.6 Total 2,286.8 4,026.7 7,229.2 13,227.4 Crude Oil Pipelines & Services: Sales of crude oil 2,147.3 5,348.2 7,689.3 16,003.5 Midstream services 175.3 88.9 399.7 264.2 Total 2,322.6 5,437.1 8,089.0 16,267.7 Natural Gas Pipelines & Services: Sales of natural gas 455.0 775.5 1,361.2 2,515.7 Midstream services 254.7 256.4 767.1 761.8 Total 709.7 1,031.9 2,128.3 3,277.5 Petrochemical & Refined Products Services: Sales of petrochemicals and refined products 780.5 1,605.4 2,764.2 4,338.2 Midstream services 199.5 186.6 583.4 531.7 Total 980.0 1,792.0 3,347.6 4,869.9 Offshore Pipelines & Services: Sales of natural gas -- -- -- 0.2 Sales of crude oil 0.4 2.5 3.2 7.5 Midstream services 8.4 40.0 75.6 110.7 Total 8.8 42.5 78.8 118.4 Total consolidated revenues $ 6,307.9 $ 12,330.2 $ 20,872.9 $ 37,760.9 Consolidated costs and expenses Operating costs and expenses: Cost of sales $ 4,419.9 $ 10,455.1 $ 15,355.9 $ 32,213.1 Other operating costs and expenses (1) 642.5 633.9 1,834.8 1,865.6 Depreciation, amortization and accretion 351.1 322.7 1,082.0 936.5 Ne t losses (g and insurance recoveries 12.3 (2.6 ) 14.7 (99.0 ) Non-cash asset impairment charges 26.8 5.7 139.1 18.2 General and administrative costs 49.0 50.0 143.2 150.9 Total consolidated costs and expenses $ 5,501.6 $ 11,464.8 $ 18,569.7 $ 35,085.3 (1) Represents cost of operating our plants, pipelines and other fixed assets, excluding depreciation, amortization and accretion charges. 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 same correlation would be true in the case of higher energy commodity sales prices and purchase costs.

Related Party Transactions

Related Party Transactions	9 Months Ended
	Sep. 30, 2015
Related Party Transactions [Abstract]
Related Party Transactions	The following table summarizes our related party transactions for the periods indicated: For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 Revenues – related parties: Unconsolidated affiliates $ 13.9 $ 11.0 $ 27.3 $ 63.8 Costs and expenses – related parties: EPCO and its privately held affiliates $ 246.0 $ 212.8 $ 703.9 $ 688.0 Unconsolidated affiliates 66.9 35.8 165.3 138.4 Total $ 312.9 $ 248.6 $ 869.2 $ 826.4 The following table summarizes our related party accounts receivable and accounts payable balances at the dates indicated: September 30, 2015 December 31, 2014 Accounts receivable - related parties: Unconsolidated affiliates $ 1.7 $ 2.8 Accounts payable - related parties: EPCO and its privately held affiliates $ 64.6 $ 98.1 Unconsolidated affiliates 15.7 20.8 Total $ 80.3 $ 118.9 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 its Privately Held Affiliates We have an extensive and ongoing relationship with EPCO and its privately held affiliates (including Enterprise GP, our general partner), which are not a part of our consolidated group of companies. At September 30, 2015, EPCO and its privately held affiliates (including Dan Duncan LLC and certain Duncan family trusts) beneficially owned the following limited partner interests in us: Total Number of Units Percentage of Total Units Outstanding 675,259,617 33.7% Of the total number of units held by EPCO and its privately held affiliates, 118,000,000 have been pledged as security under the credit facilities of certain of the privately held affiliates at September 30, 2015. These credit facilities contain customary and other events of default, including defaults by us and other affiliates of EPCO. An event of default, followed by a foreclosure on the pledged collateral, could ultimately result in a change in ownership of these units and affect the market price of our common units. 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 activities and to meet their debt obligations. During the nine months ended September 30, 2015 and 2014, we paid EPCO and its privately held affiliates cash distributions totaling $705.9 million and $652.8 million, respectively. Distributions paid during the nine months ended September 30, 2015 excluded 35,380,000 Designated Units (see Note 11). Likewise, distributions paid during the nine months ended September 30, 2014 excluded 45,120,000 Designated Units. From time-to-time, EPCO and its privately held affiliates elect to reinvest a portion of the cash distributions they receive from us into the purchase of additional common units under our DRIP. These purchases totaled $50 million and $75 million for the nine months ended September 30, 2015 and 2014, respectively. In addition, a total of $50 million of distributions were reinvested in connection with the distribution we paid on November 6, 2015. In March 2015, a privately held affiliate of EPCO purchased 3,225,057 common units from us under our ATM program for $31.01 per unit. See Note 11 for additional information regarding our DRIP and ATM program. 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 our related party costs and expenses attributable to the ASA with EPCO for the periods indicated: For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 Operating costs and expenses $ 215.3 $ 179.0 $ 612.2 $ 591.6 General and administrative expenses 26.4 29.6 78.8 84.5 Total costs and expenses $ 241.7 $ 208.6 $ 691.0 $ 676.1

Earnings Per Unit

Earnings Per Unit	9 Months Ended
	Sep. 30, 2015
Earnings Per Unit [Abstract]
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 September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 BASIC EARNINGS PER UNIT Net income attributable to limited partners $ 649.3 $ 691.1 $ 1,836.4 $ 2,127.6 Undistributed earnings allocated and cash payments on phantom unit awards (1) (2.2 ) (1.3 ) (6.6 ) (4.0 ) Net income available to common unitholders $ 647.1 $ 689.8 $ 1,829.8 $ 2,123.6 Basic weighted-average number of common units outstanding 1,969.3 1,834.2 1,952.3 1,831.1 Basic earnings per unit $ 0.33 $ 0.38 $ 0.94 $ 1.16 DILUTED EARNINGS PER UNIT Net income attributable to limited partners $ 649.3 $ 691.1 $ 1,836.4 $ 2,127.6 Diluted weighted-average number of units outstanding: Distribution-bearing common units 1,969.3 1,834.2 1,952.3 1,831.1 Designated Units 35.4 45.1 35.4 45.1 Phantom units (1) 5.7 3.4 5.4 2.8 Incremental option units 0.1 0.7 0.2 1.0 Total 2,010.5 1,883.4 1,993.3 1,880.0 Diluted earnings per unit $ 0.32 $ 0.37 $ 0.92 $ 1.13 (1) Each phantom unit award includes a DER, which entitles the recipient to receive cash payments equal to the product of the number of phantom unit awards and the cash distribution per unit paid to our common unitholders. Cash payments made in connection with DERs are nonforfeitable. As a result, the phantom units are considered participating securities for purposes of computing basic earnings per unit. Phantom unit awards were first issued in February 2014.

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2015
Commitments and Contingencies [Abstract]
Commitments and Contingencies	Litigation 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 probable loss 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 September 30, 2015 and December 31, 2014, our accruals for litigation contingencies were $4.6 million and $2.4 million, respectively, and were recorded in our Unaudited Condensed Consolidated Balance Sheets as a component of “Other current liabilities.” 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. ETP Matter In connection with a proposed pipeline project, we and Energy Transfer Partners, L.P. (“ETP”) signed a non-binding letter of intent in April 2011 that disclaimed any partnership or joint venture related to such project absent executed definitive documents and board approvals of the respective companies. Definitive agreements were never executed and board approval was never obtained for the potential pipeline project. In August 2011, the proposed pipeline project was cancelled due to a lack of customer support. In September 2011, ETP filed suit against us and a third party in connection with the cancelled project alleging, among other things, that we and ETP had formed a “partnership.” The case was tried in the District Court of Dallas County, Texas, 298th Judicial District. While we firmly believe, and argued during our defense, that no agreement was ever executed forming a legal joint venture or partnership between the parties, the jury found that the actions of the two companies, nevertheless, constituted a legal partnership. As a result, the jury found that ETP was wrongfully excluded from a subsequent pipeline project involving a third party, and awarded ETP $319.4 million in actual damages on March 4, 2014. On July 29, 2014, the court entered judgment against us in an aggregate amount of $535.8 million, which includes (i) $319.4 million as the amount of actual damages awarded by the jury, (ii) an additional $150.0 million in disgorgement for the alleged benefit we received due to a breach of fiduciary duties by us against ETP and (iii) prejudgment interest in the amount of $66.4 million. The court also awarded post-judgment interest on such aggregate amount, to accrue at a rate of 5% per annum, compounded annually. We do not believe that the verdict or the judgment entered against us is supported by the evidence or the law. We filed our Brief of the Appellant in the Court of Appeals for the Fifth District of Dallas, Texas on March 30, 2015 and ETP filed its Brief of Appellees on June 29, 2015. We filed our Reply Brief of Appellant on September 18, 2015. We intend to vigorously oppose the judgment through the appeals process. As of September 30, 2015, we have not recorded a provision for this matter as management believes payment of damages in this case is not probable. FTC Matter On February 23, 2015, we received a Civil Investigative Demand and a related Subpoena Duces Tecum Contractual Obligations Scheduled Maturities of Debt We have long-term and short-term payment obligations under debt agreements. See Note 10 for additional information regarding our scheduled future maturities of debt principal. Operating Lease Obligations Consolidated lease and rental expense was $28.8 million and $23.5 million during the third quarters of 2015 and 2014, respectively. For the nine months ended September 30, 2015 and 2014, consolidated lease and rental expense was $76.4 million and $69.2 million, respectively. Our operating lease commitments at September 30, 2015 did not differ materially from those reported in our 2014 Form 10-K. Purchase Obligations Our consolidated purchase obligations at September 30, 2015 did not differ materially from those reported in our 2014 Form 10-K. Other Commitments In connection with the agreements to acquire EFS Midstream (see Note 8), we are obligated to spend up to an aggregate of $270 million on specified midstream gathering assets for Pioneer and Reliance, if requested by these producers, over a ten year period. If constructed, these new assets would be owned by us and be a component of the EFS Midstream asset network. Liquidity Option Agreement As described in Note 18 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of our 2014 Form 10-K, we entered into a put option agreement (the “Liquidity Option Agreement”) with OTA and Marquard & Bahls (“M&B”) in connection with the Oiltanking acquisition. Under the Liquidity Option Agreement, we granted M&B the option to sell to us 100% of the issued and outstanding capital stock of OTA at any time within a 90-day period commencing on February 1, 2020. At that time, OTA’s only significant asset is expected to be the Enterprise common units it received in Step 1 of the Oiltanking acquisition, to the extent that such common units are not sold by M&B prior to the option exercise date pursuant to a related registration rights agreement. During 2015, we retrospectively adjusted our provisional fair value estimate for the Liquidity Option Agreement from $119.4 million to $219.7 million. The retrospective adjustment was applied in our December 31, 2014 Consolidated Balance Sheet as a $100.3 million increase in goodwill and a corresponding increase in the Liquidity Option Agreement liability, which is a component of “Other long-term liabilities.” The retrospective adjustment did not impact our historical results of operations, cash flows or other balance sheet amounts. As described in our 2014 Form 10-K, the provisional estimate represents the present value at October 1, 2014 of estimated federal and state income tax payments that we would make on the taxable income of OTA, a corporation, over a stated period of time following exercise of the option. We expect that OTA’s taxable income would, in turn, be based on an allocation of our partnership’s taxable income to the common units held by OTA and reflect any tax mitigation strategies that we believe could be employed. Our initial fair value estimate of $119.4 million was based on a variety of assumptions (each a Level 3 input), including a key assumption that a market participant would maintain the OTA corporate structure and not divest of its Enterprise common units for 30 years following exercise of the option in 2020. After further consideration, we revised this key assumption to reflect that a market participant might elect to dissolve the OTA corporate structure and sell the Enterprise common units at earlier dates. Accordingly, for purposes of our discounted cash flow model, we assigned an equal probability to the divesture of OTA and its assets over each of the 30 years in our forecast period. As a result, our provisional fair value estimate at October 1, 2014 increased by $100.3 million to $219.7 million, with a corresponding $100.3 million increase in goodwill which has been retrospectively adjusted as of December 31, 2014. This change is not considered material to our consolidated financial statements. None of the other key valuation assumptions we listed in our 2014 Form 10-K for the Liquidity Option Agreement have changed. We finalized the determination of the initial fair value of the Liquidity Option Agreement during the third quarter of 2015. Results for the three and nine months ended September 30, 2015 include $4.3 million and $15.8 million, respectively, of non-cash accretion expense associated with the change in fair value of the Liquidity Option Agreement from October 1, 2014 through September 30, 2015. The carrying value of the Liquidity Option Agreement, which is a component of “Other long-term liabilities” on our Unaudited Condensed Consolidated Balance Sheet, increased to $235.5 million at September 30, 2015 as of result of accretion.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	9 Months Ended
	Sep. 30, 2015
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	The following table presents the net effect of changes in our operating accounts for the periods indicated: For the Nine Months Ended September 30, 2015 2014 Decrease (increase) in: Accounts receivable – trade $ 1,042.5 $ 153.6 Accounts receivable – related parties 1.2 4.0 Inventories (143.2 ) (536.9 ) Prepaid and other current assets (32.7 ) (44.5 ) Other assets 2.1 20.0 Increase (decrease) in: Accounts payable – trade (72.7 ) (14.2 ) Accounts payable – related parties (38.6 ) (27.7 ) Accrued product payables (1,248.4 ) (13.1 ) Accrued interest (136.7 ) (131.7 ) Other current liabilities (13.8 ) 143.5 Other liabilities 12.4 11.2 Net effect of changes in operating accounts $ (627.9 ) $ (435.8 ) We incurred liabilities for construction in progress that had not been paid at September 30, 2015 and December 31, 2014 of $495.1 million and $372.8 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 activities 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. In addition, we incurred a $1.0 billion payable in connection with our acquisition of EFS Midstream in July 2015 that will be paid no later than the first anniversary of the closing date of the acquisition (see Note 8). In February 2011, we experienced an NGL release and fire at the West Storage location of our Mont Belvieu, Texas underground storage facility. As a final installment on the property damage claim we filed in connection with this incident, we received $95.0 million of nonrefundable cash insurance proceeds during the first quarter of 2014. Operating income for the nine months ended September 30, 2014 includes $95.0 million of gains related to these proceeds. This gain was classified as a reduction in operating costs and expenses for the period. The following table presents our cash proceeds from asset sales and insurance recoveries for the periods indicated: For the Nine Months Ended September 30, 2015 2014 Sale of Offshore Business (see Note 6) $ 1,528.6 $ -- Insurance recoveries attributable to West Storage claims -- 95.0 Other cash proceeds 8.7 26.5 Total $ 1,537.3 $ 121.5 The following table presents net gains (losses) attributable to asset sales and insurance recoveries for the periods indicated: For the Nine Months Ended September 30, 2015 2014 Sale of Offshore Business (see Note 6) $ (12.6 ) $ -- Gains attributable to West Storage insurance recoveries -- 95.0 Ne (2.1 ) 4.0 Total $ (14.7 ) $ 99.0

Condensed Consolidating Financi

Condensed Consolidating Financial Information	9 Months Ended
	Sep. 30, 2015
Condensed Consolidating Financial Information [Abstract]
Condensed Consolidating Financial Information	EPO conducts 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. As the parent company of EPO, Enterprise Products Partners L.P. guarantees substantially all of the debt obligations of EPO. 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. See Note 10 for additional information regarding our consolidated debt obligations. EPO’s consolidated subsidiaries have no significant restrictions on their ability to pay distributions or make loans to Enterprise Products Partners L.P. Enterprise Products Partners L.P. Unaudited Condensed Consolidating Balance Sheet September 30, 2015 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 $ 46.9 $ 85.3 $ (5.5 ) $ 126.7 $ -- $ -- $ 126.7 Accounts receivable – trade, net 791.0 2,011.3 (0.3 ) 2,802.0 -- -- 2,802.0 Accounts receivable – related parties 123.1 780.8 (901.5 ) 2.4 -- (0.7 ) 1.7 Inventories 889.1 196.6 (0.3 ) 1,085.4 -- -- 1,085.4 Derivative assets 139.1 102.7 -- 241.8 -- -- 241.8 Prepaid and other current assets 164.7 247.7 (10.2 ) 402.2 0.2 -- 402.4 Total current assets 2,153.9 3,424.4 (917.8 ) 4,660.5 0.2 (0.7 ) 4,660.0 Property, plant and equipment, net 3,432.3 27,780.4 1.4 31,214.1 -- -- 31,214.1 Investments in unconsolidated affiliates 38,310.0 4,094.7 (39,779.4 ) 2,625.3 20,397.5 (20,397.5 ) 2,625.3 Intangible assets, net 726.8 3,370.1 (14.8 ) 4,082.1 -- -- 4,082.1 Goodwill 459.1 5,290.1 -- 5,749.2 -- -- 5,749.2 Other assets 226.4 49.0 (78.8 ) 196.6 0.5 -- 197.1 Total assets $ 45,308.5 $ 44,008.7 $ (40,789.4 ) $ 48,527.8 $ 20,398.2 $ (20,398.2 ) $ 48,527.8 LIABILITIES AND EQUITY Current liabilities: Current maturities of debt $ 1,619.3 $ 0.1 $ -- $ 1,619.4 $ -- $ -- $ 1,619.4 Accounts payable – trade 331.4 519.0 (5.5 ) 844.9 -- -- 844.9 Accounts payable – related parties 866.7 130.1 (916.5 ) 80.3 0.7 (0.7 ) 80.3 Accrued product payables 938.0 1,611.2 (1.3 ) 2,547.9 -- -- 2,547.9 Accrued liability related to EFS Midstream acquisition -- 997.7 -- 997.7 -- -- 997.7 Accrued interest 198.6 0.3 -- 198.9 -- -- 198.9 Other current liabilities 174.3 425.1 (10.0 ) 589.4 (0.1 ) 0.5 589.8 Total current liabilities 4,128.3 3,683.5 (933.3 ) 6,878.5 0.6 (0.2 ) 6,878.9 Long-term debt 20,825.4 15.3 -- 20,840.7 -- -- 20,840.7 Deferred tax liabilities 3.2 47.4 (1.0 ) 49.6 -- 3.8 53.4 Other long-term liabilities 10.6 234.3 (78.5 ) 166.4 235.5 -- 401.9 Commitments and contingencies Equity: Partners’ and other owners’ equity 20,341.0 39,986.1 (39,954.0 ) 20,373.1 20,162.1 (20,373.1 ) 20,162.1 Noncontrolling interests -- 42.1 177.4 219.5 -- (28.7 ) 190.8 Total equity 20,341.0 40,028.2 (39,776.6 ) 20,592.6 20,162.1 (20,401.8 ) 20,352.9 Total liabilities and equity $ 45,308.5 $ 44,008.7 $ (40,789.4 ) $ 48,527.8 $ 20,398.2 $ (20,398.2 ) $ 48,527.8 Enterprise Products Partners L.P. Unaudited Condensed Consolidating Balance Sheet December 31, 2014 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 $ 18.7 $ 70.4 $ (14.7 ) $ 74.4 $ -- $ -- $ 74.4 Accounts receivable – trade, net 1,128.5 2,698.2 (3.7 ) 3,823.0 -- -- 3,823.0 Accounts receivable – related parties 158.8 1,114.6 (1,266.6 ) 6.8 -- (4.0 ) 2.8 Inventories 831.8 182.8 (0.4 ) 1,014.2 -- -- 1,014.2 Derivative assets 102.0 124.0 -- 226.0 -- -- 226.0 Prepaid and other current assets 435.7 222.3 (308.5 ) 349.5 -- 0.8 350.3 Total current assets 2,675.5 4,412.3 (1,593.9 ) 5,493.9 -- (3.2 ) 5,490.7 Property, plant and equipment, net 2,871.7 26,912.0 97.9 29,881.6 -- -- 29,881.6 Investments in unconsolidated affiliates 36,937.5 3,556.4 (37,451.9 ) 3,042.0 18,287.5 (18,287.5 ) 3,042.0 Intangible assets, net 2,527.3 1,292.4 482.4 4,302.1 -- -- 4,302.1 Goodwill 1,956.1 1,721.4 622.7 4,300.2 -- -- 4,300.2 Other assets 139.3 45.8 (0.7 ) 184.4 -- -- 184.4 Total assets $ 47,107.4 $ 37,940.3 $ (37,843.5 ) $ 47,204.2 $ 18,287.5 $ (18,290.7 ) $ 47,201.0 LIABILITIES AND EQUITY Current liabilities: Current maturities of debt $ 2,206.4 $ -- $ -- $ 2,206.4 $ -- $ -- $ 2,206.4 Accounts payable – trade 216.6 571.4 (14.8 ) 773.2 0.6 -- 773.8 Accounts payable – related parties 1,226.5 173.3 (1,280.9 ) 118.9 4.0 (4.0 ) 118.9 Accrued product payables 1,570.0 2,287.9 (4.6 ) 3,853.3 -- -- 3,853.3 Accrued interest 335.4 0.7 (0.6 ) 335.5 -- -- 335.5 Other current liabilities 130.8 763.7 (308.7 ) 585.8 -- -- 585.8 Total current liabilities 5,685.7 3,797.0 (1,609.6 ) 7,873.1 4.6 (4.0 ) 7,873.7 Long-term debt 19,142.5 14.9 -- 19,157.4 -- -- 19,157.4 Deferred tax liabilities 4.9 58.5 (0.9 ) 62.5 -- 4.1 66.6 Other long-term liabilities 10.9 180.8 (0.3 ) 191.4 219.7 -- 411.1 Commitments and contingencies Equity: Partners’ and other owners’ equity 22,263.4 33,820.9 (37,820.6 ) 18,263.7 18,063.2 (18,263.7 ) 18,063.2 Noncontrolling interests -- 68.2 1,587.9 1,656.1 -- (27.1 ) 1,629.0 Total equity 22,263.4 33,889.1 (36,232.7 ) 19,919.8 18,063.2 (18,290.8 ) 19,692.2 Total liabilities and equity $ 47,107.4 $ 37,940.3 $ (37,843.5 ) $ 47,204.2 $ 18,287.5 $ (18,290.7 ) $ 47,201.0 Enterprise Products Partners L.P. Unaudited Condensed Consolidating Statement of Operations For the Three Months Ended September 30, 2015 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 $ 4,685.2 $ 4,531.1 $ (2,908.4 ) $ 6,307.9 $ -- $ -- $ 6,307.9 Costs and expenses: Operating costs and expenses 4,506.7 3,854.5 (2,908.6 ) 5,452.6 -- -- 5,452.6 General and administrative costs 11.1 38.3 -- 49.4 (0.4 ) -- 49.0 Total costs and expenses 4,517.8 3,892.8 (2,908.6 ) 5,502.0 (0.4 ) -- 5,501.6 Equity in income of unconsolidated affiliates 725.5 116.5 (738.9 ) 103.1 653.2 (653.2 ) 103.1 Operating income 892.9 754.8 (738.7 ) 909.0 653.6 (653.2 ) 909.4 Other income (expense): Interest expense (239.5 ) (4.2 ) -- (243.7 ) -- -- (243.7 ) Other, net 1.7 0.1 -- 1.8 (4.3 ) -- (2.5 ) Total other expense, net (237.8 ) (4.1 ) -- (241.9 ) (4.3 ) -- (246.2 ) Income before income taxes 655.1 750.7 (738.7 ) 667.1 649.3 (653.2 ) 663.2 Provision for income taxes (3.3 ) (2.2 ) -- (5.5 ) -- -- (5.5 ) Net income 651.8 748.5 (738.7 ) 661.6 649.3 (653.2 ) 657.7 Net loss (income) att -- -- (9.7 ) (9.7 ) -- 1.3 (8.4 ) Net income attributable to entity $ 651.8 $ 748.5 $ (748.4 ) $ 651.9 $ 649.3 $ (651.9 ) $ 649.3 Enterprise Products Partners L.P. Unaudited Condensed Consolidating Statement of Operations For the Three Months Ended September 30, 2014 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 $ 8,121.5 $ 8,598.2 $ (4,389.5 ) $ 12,330.2 $ -- $ -- $ 12,330.2 Costs and expenses: Operating costs and expenses 7,950.9 7,853.5 (4,389.6 ) 11,414.8 -- -- 11,414.8 General and administrative costs 8.2 40.4 -- 48.6 1.4 -- 50.0 Total costs and expenses 7,959.1 7,893.9 (4,389.6 ) 11,463.4 1.4 -- 11,464.8 Equity in income of unconsolidated affiliates 762.5 94.4 (784.6 ) 72.3 692.5 (692.5 ) 72.3 Operating income 924.9 798.7 (784.5 ) 939.1 691.1 (692.5 ) 937.7 Other income (expense): Interest expense (229.2 ) (0.6 ) -- (229.8 ) -- -- (229.8 ) Other, net 0.2 (1.2 ) -- (1.0 ) -- -- (1.0 ) Total other expense, net (229.0 ) (1.8 ) -- (230.8 ) -- -- (230.8 ) Income before income taxes 695.9 796.9 (784.5 ) 708.3 691.1 (692.5 ) 706.9 Provision for income taxes (4.0 ) (2.8 ) -- (6.8 ) -- (0.9 ) (7.7 ) Net income 691.9 794.1 (784.5 ) 701.5 691.1 (693.4 ) 699.2 Net income attributable to noncontrolling interests -- 0.1 (9.5 ) (9.4 ) -- 1.3 (8.1 ) Net income attributable to entity $ 691.9 $ 794.2 $ (794.0 ) $ 692.1 $ 691.1 $ (692.1 ) $ 691.1 Enterprise Products Partners L.P. Unaudited Condensed Consolidating Statement of Operations For the Nine Months Ended September 30, 2015 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 $ 15,301.0 $ 14,751.0 $ (9,179.1 ) $ 20,872.9 $ -- $ -- $ 20,872.9 Costs and expenses: Operating costs and expenses 14,696.2 12,909.8 (9,179.5 ) 18,426.5 -- -- 18,426.5 General and administrative costs 28.9 113.9 -- 142.8 0.4 -- 143.2 Total costs and expenses 14,725.1 13,023.7 (9,179.5 ) 18,569.3 0.4 -- 18,569.7 Equity in income of unconsolidated affiliates 1,996.4 314.5 (2,008.4 ) 302.5 1,852.6 (1,852.6 ) 302.5 Operating income 2,572.3 2,041.8 (2,008.0 ) 2,606.1 1,852.2 (1,852.6 ) 2,605.7 Other income (expense): Interest expense (717.9 ) (7.3 ) 2.0 (723.2 ) -- -- (723.2 ) Other, net 4.0 0.6 (2.0 ) 2.6 (15.8 ) -- (13.2 ) Total other expense, net (713.9 ) (6.7 ) -- (720.6 ) (15.8 ) -- (736.4 ) Income before income taxes 1,858.4 2,035.1 (2,008.0 ) 1,885.5 1,836.4 (1,852.6 ) 1,869.3 Benefit from (provision for) income taxes (8.9 ) 5.4 -- (3.5 ) -- (0.9 ) (4.4 ) Net income 1,849.5 2,040.5 (2,008.0 ) 1,882.0 1,836.4 (1,853.5 ) 1,864.9 Ne t loss (income) at -- 0.8 (32.9 ) (32.1 ) -- 3.6 (28.5 ) Net income attributable to entity $ 1,849.5 $ 2,041.3 $ (2,040.9 ) $ 1,849.9 $ 1,836.4 $ (1,849.9 ) $ 1,836.4 Enterprise Products Partners L.P. Unaudited Condensed Consolidating Statement of Operations For the Nine Months Ended September 30, 2014 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 $ 25,190.1 $ 25,859.9 $ (13,289.1 ) $ 37,760.9 $ -- $ -- $ 37,760.9 Costs and expenses: Operating costs and expenses 24,516.6 23,707.6 (13,289.8 ) 34,934.4 -- -- 34,934.4 General and administrative costs 23.1 126.0 -- 149.1 1.8 -- 150.9 Total costs and expenses 24,539.7 23,833.6 (13,289.8 ) 35,083.5 1.8 -- 35,085.3 Equity in income of unconsolidated affiliates 2,169.5 256.1 (2,246.5 ) 179.1 2,129.4 (2,129.4 ) 179.1 Operating income 2,819.9 2,282.4 (2,245.8 ) 2,856.5 2,127.6 (2,129.4 ) 2,854.7 Other income (expense): Interest expense (678.6 ) (1.0 ) -- (679.6 ) -- -- (679.6 ) Other, net 0.7 (0.9 ) -- (0.2 ) -- -- (0.2 ) Total other expense, net (677.9 ) (1.9 ) -- (679.8 ) -- -- (679.8 ) Income before income taxes 2,142.0 2,280.5 (2,245.8 ) 2,176.7 2,127.6 (2,129.4 ) 2,174.9 Provision for income taxes (15.5 ) (5.8 ) 0.2 (21.1 ) -- (1.4 ) (22.5 ) Net income 2,126.5 2,274.7 (2,245.6 ) 2,155.6 2,127.6 (2,130.8 ) 2,152.4 Net income attributable to noncontrolling interests -- 0.2 (28.8 ) (28.6 ) -- 3.8 (24.8 ) Net income attributable to entity $ 2,126.5 $ 2,274.9 $ (2,274.4 ) $ 2,127.0 $ 2,127.6 $ (2,127.0 ) $ 2,127.6 Enterprise Products Partners L.P. Unaudited Condensed Consolidating Statement of Comprehensive Income For the Three Months Ended September 30, 2015 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 $ 676.0 $ 797.3 $ (763.9 ) $ 709.4 $ 697.2 $ (701.0 ) $ 705.6 Comprehen sive loss (income) attribu -- -- (9.7 ) (9.7 ) -- 1.3 (8.4 ) Comprehensive income attributable to entity $ 676.0 $ 797.3 $ (773.6 ) $ 699.7 $ 697.2 $ (699.7 ) $ 697.2 Enterprise Products Partners L.P. Unaudited Condensed Consolidating Statement of Comprehensive Income For the Three Months Ended September 30, 2014 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 $ 708.9 $ 825.2 $ (784.5 ) $ 749.6 $ 739.2 $ (741.5 ) $ 747.3 Comprehensive loss (income) attributable to noncontrolling interests -- 0.1 (9.5 ) (9.4 ) -- 1.3 (8.1 ) Comprehensive income attributable to entity $ 708.9 $ 825.3 $ (794.0 ) $ 740.2 $ 739.2 $ (740.2 ) $ 739.2 Enterprise Products Partners L.P. Unaudited Condensed Consolidating Statement of Comprehensive Income For the Nine Months Ended September 30, 2015 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 $ 1,869.9 $ 2,056.1 $ (2,033.2 ) $ 1,892.8 $ 1,847.3 $ (1,864.3 ) $ 1,875.8 Comp rehensive loss (income) attrib -- 0.8 (32.9 ) (32.1 ) -- 3.6 (28.5 ) Comprehensive income attributable to entity $ 1,869.9 $ 2,056.9 $ (2,066.1 ) $ 1,860.7 $ 1,847.3 $ (1,860.7 ) $ 1,847.3 Enterprise Products Partners L.P. Unaudited Condensed Consolidating Statement of Comprehensive Income For the Nine Months Ended September 30, 2014 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 $ 2,161.8 $ 2,292.2 $ (2,245.5 ) $ 2,208.5 $ 2,180.5 $ (2,183.7 ) $ 2,205.3 Comprehensive loss (income) attributable to noncontrolling interests -- 0.2 (28.8 ) (28.6 ) -- 3.8 (24.8 ) Comprehensive income attributable to entity $ 2,161.8 $ 2,292.4 $ (2,274.3 ) $ 2,179.9 $ 2,180.5 $ (2,179.9 ) $ 2,180.5 Enterprise Products Partners L.P. Unaudited Condensed Consolidating Statement of Cash Flows For the Nine Months Ended September 30, 2015 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 $ 1,849.5 $ 2,040.5 $ (2,008.0 ) $ 1,882.0 $ 1,836.4 $ (1,853.5 ) $ 1,864.9 Reconciliation of net income to net cash flows provided by operating activities: Depreciation, amortization and accretion 106.0 1,042.1 (0.4 ) 1,147.7 -- -- 1,147.7 Equity in income of unconsolidated affiliates (1,996.4 ) (314.5 ) 2,008.4 (302.5 ) (1,852.6 ) 1,852.6 (302.5 ) Distributions received from unconsolidated affiliates 1,705.4 227.1 (1,570.1 ) 362.4 2,241.1 (2,241.1 ) 362.4 Net effect of changes in operating accounts and other operating activities (52.9 ) (450.6 ) 9.3 (494.2 ) 12.0 0.9 (481.3 ) Net cash flows provided by operating activities 1,611.6 2,544.6 (1,560.8 ) 2,595.4 2,236.9 (2,241.1 ) 2,591.2 Investing activities: Capital expenditures, net of contributions in aid of construction costs (725.5 ) (1,893.6 ) -- (2,619.1 ) -- -- (2,619.1 ) Cash used for business combinations, net of cash received (1,058.4 ) 13.3 -- (1,045.1 ) -- -- (1,045.1 ) Proceeds from asset sales and insurance recoveries 1,532.1 5.2 -- 1,537.3 -- -- 1,537.3 Other investing activities (1,091.2 ) (43.5 ) 953.4 (181.3 ) (1,005.2 ) 1,005.2 (181.3 ) Cash used in investing activities (1,343.0 ) (1,918.6 ) 953.4 (2,308.2 ) (1,005.2 ) 1,005.2 (2,308.2 ) Financing activities: Borrowings under debt agreements 17,113.7 77.9 (77.9 ) 17,113.7 -- -- 17,113.7 Repayments of debt (16,139.2 ) -- -- (16,139.2 ) -- -- (16,139.2 ) Cash distributions paid to partners (2,241.1 ) (1,602.4 ) 1,602.4 (2,241.1 ) (2,185.1 ) 2,241.1 (2,185.1 ) Cash payments made in connection with DERs -- -- -- -- (5.6 ) -- (5.6 ) Cash distributions paid to noncontrolling interests -- (0.8 ) (32.4 ) (33.2 ) -- -- (33.2 ) Cash contributions from noncontrolling interests -- 37.8 (0.4 ) 37.4 -- -- 37.4 Net cash proceeds from issuance of common units -- -- -- -- 1,011.4 -- 1,011.4 Cash contributions from owners 1,005.2 875.1 (875.1 ) 1,005.2 -- (1,005.2 ) -- Other financing activities (23.9 ) -- -- (23.9 ) (52.4 ) -- (76.3 ) Cash used in financing activities (285.3 ) (612.4 ) 616.6 (281.1 ) (1,231.7 ) 1,235.9 (276.9 ) Net change in cash and cash equivalents (16.7 ) 13.6 9.2 6.1 -- -- 6.1 Cash and cash equivalents, January 1 18.7 70.4 (14.7 ) 74.4 -- -- 74.4 Cash and cash equivalents, September 30 $ 2.0 $ 84.0 $ (5.5 ) $ 80.5 $ -- $ -- $ 80.5 Enterprise Products Partners L.P. Unaudited Condensed Consolidating Statement of Cash Flows For the Nine Months Ended September 30, 2014 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 $ 2,126.5 $ 2,274.7 $ (2,245.6 ) $ 2,155.6 $ 2,127.6 $ (2,130.8 ) $ 2,152.4 Reconciliation of net income to net cash flows provided by operating activities: Depreciation, amortization and accretion 114.3 878.5 (0.4 ) 992.4 -- -- 992.4 Equity in income of unconsolidated affiliates (2,169.5 ) (256.1 ) 2,246.5 (179.1 ) (2,129.4 ) 2,129.4 (179.1 ) Distributions received from unconsolidated affiliates 3,475.8 229.0 (3,444.1 ) 260.7 2,007.4 (2,007.4 ) 260.7 Net effect of changes in operating accounts and other operating activities (764.6 ) 230.1 16.7 (517.8 ) (5.6 ) 1.4 (522.0 ) Net cash flows provided by operating activities 2,782.5 3,356.2 (3,426.9 ) 2,711.8 2,000.0 (2,007.4 ) 2,704.4 Investing activities: Capital expenditures, net of contributions in aid of construction costs (329.1 ) (1,530.4 ) -- (1,859.5 ) -- -- (1,859.5 ) Proceeds from asset sales and insurance recoveries 4.2 117.3 -- 121.5 -- -- 121.5 Other investing activities (2,059.3 ) (526.9 ) 2,056.1 (530.1 ) (300.7 ) 300.7 (530.1 ) Cash used in investing activities (2,384.2 ) (1,940.0 ) 2,056.1 (2,268.1 ) (300.7 ) 300.7 (2,268.1 ) Financing activities: Borrowings under debt agreements 7,167.5 -- -- 7,167.5 -- -- 7,167.5 Repayments of debt (4,856.3 ) -- -- (4,856.3 ) -- -- (4,856.3 ) Cash distributions paid to partners (2,007.4 ) (3,473.6 ) 3,473.6 (2,007.4 ) (1,948.2 ) 2,007.4 (1,948.2 ) Cash payments made in connection with DERs -- -- -- -- (2.4 ) -- (2.4 ) Cash distributions paid to noncontrolling interests -- -- (29.4 ) (29.4 ) -- -- (29.4 ) Cash contributions from noncontrolling interests -- -- 4.0 4.0 -- -- 4.0 Net cash proceeds from issuance of common units -- -- -- -- 304.9 -- 304.9 Cash contributions from owners 300.7 2,060.0 (2,060.0 ) 300.7 -- (300.7 ) -- Other financing activities (18.1 ) -- -- (18.1 ) (53.6 ) -- (71.7 ) Cash provided by (used in) financing activities 586.4 (1,413.6 ) 1,388.2 561.0 (1,699.3 ) 1,706.7 568.4 Net change in cash and cash equivalents 984.7 2.6 17.4 1,004.7 -- -- 1,004.7 Cash and cash equivalents, January 1 28.4 49.5 (21.0 ) 56.9 -- -- 56.9 Cash and cash equivalents, September 30 $ 1,013.1 $ 52.1 $ (3.6 ) $ 1,061.6 $ -- $ -- $ 1,061.6

General Accounting and Disclo25

General Accounting and Disclosure Matters (Policies)	9 Months Ended
	Sep. 30, 2015
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 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. Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed. See Note 15 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 and certain anticipated future commodity transactions. To qualify for hedge accounting, the hedged item must expose us to risk and the related derivative instrument must reduce the exposure to that risk 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 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 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 transactions are recognized during the period when volumes are physically delivered or received. Physical forward commodity contracts subject to this exception 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 physical delivery in the future. See Note 4 for additional information regarding our derivative instruments.
Estimates	Estimates Preparing our consolidated financial statements in conformity with U.S. 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.
Restricted Cash	Restricted Cash Restricted cash represents amounts held in segregated bank accounts by our clearing brokers as margin in support of our commodity derivative instruments portfolio and related physical purchases and sales of natural gas, NGLs, crude oil and refined products. Additional cash may be restricted to maintain our commodity derivative instruments portfolio as prices fluctuate or deposit requirements change. At September 30, 2015, our restricted cash amounts were $46.2 million. We did not have any restricted cash as of December 31, 2014. See Note 4 for information regarding our derivative instruments and hedging activities.

Equity-based Awards (Tables)

Equity-based Awards (Tables)	9 Months Ended
	Sep. 30, 2015
Equity-based Awards [Abstract]
Equity-based Award Expense	An allocated portion of the fair value of EPCO’s equity-based awards is charged to us under the ASA. The following table summarizes compensation expense we recognized in connection with equity-based awards for the periods indicated: For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 Equity-classified awards: Restricted common unit awards $ 3.1 $ 8.7 $ 13.1 $ 29.3 Phantom unit awards 20.3 12.9 60.2 32.3 Liability-classified awards -- 0.1 0.2 0.4 Total $ 23.4 $ 21.7 $ 73.5 $ 62.0
Restricted Common Unit Awards	The following table presents information regarding restricted common unit awards for the period indicated: Number of Units Weighted- Average Grant Date Fair Value per Unit Restricted common units at December 31, 2014 4,229,790 $ 26.96 Vested (1,997,194 ) $ 25.99 Forfeited (157,750 ) $ 27.64 Restricted common units at September 30, 2015 2,074,846 $ 27.85 (1) Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued.
Cash Distributions and Total Intrinsic Value of Restricted Common Unit Awards	The following table presents supplemental information regarding our restricted common unit awards for the periods indicated: For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 Cash distributions paid to restricted common unitholders $ 0.8 $ 1.6 $ 3.2 $ 5.7 Total intrinsic value of restricted common unit awards that vested during period 1.5 1.3 66.9 85.4
Phantom Unit Awards	The following table presents phantom unit award activity for the period indicated: Number of Units Weighted- Average Grant Date Fair Value per Unit Phantom unit awards at December 31, 2014 3,342,390 $ 33.13 Granted (2) 3,491,040 $ 33.97 Vested (933,890 ) $ 33.13 Forfeited (275,356 ) $ 33.51 Phantom unit awards at September 30, 2015 5,624,184 $ 33.63 (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 phantom unit awards issued during 2015 was $118.6 million based on a grant date market price of our common units ranging from $27.31 to $34.40 per unit. An estimated annual forfeiture rate of 3.5% was applied to these awards.
Cash Distributions and Total Intrinsic Value of Phantom Unit Awards	The following table presents supplemental information regarding our phantom unit awards and DERs for the periods indicated: For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 Cash payments made in connection with DERs $ 2.2 $ 1.2 $ 5.6 $ 2.4 Total intrinsic value of phantom unit awards that vested during period 2.3 0.1 31.0 1.3
Unit Option Awards	The following table presents unit option award activity for the period indicated: Number of Units Weighted- Average Strike Price (dollars/unit) Weighted- Average Remaining Contractual Term (in years) Aggregate Intrinsic Value Unit option awards at December 31, 2014 1,270,000 $ 16.14 Exercised (1,080,000 ) $ 16.14 Unit option awards at September 30, 2015 190,000 $ 16.14 0.3 $ 1.7 (1) All of the unit option awards outstanding at September 30, 2015 were exercisable. None of the unit option awards outstanding at December 31, 2014 were exercisable. (2) Aggregate intrinsic value reflects fully vested unit option awards at the dates indicated.
Supplemental Information Regarding Unit Option Awards	The following table presents supplemental information regarding unit option awards during the periods indicated: For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 Total intrinsic value of unit option awards exercised during period $ 0.2 $ -- $ 19.8 $ 57.5 Cash received from EPCO in connection with the exercise of unit option awards 0.2 -- 11.5 33.4 Unit option award-related cash reimbursements to EPCO 0.2 -- 19.8 57.5

Derivative Instruments, Hedgi27

Derivative Instruments, Hedging Activities and Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2015
Derivative Instruments, Hedging Activities and Fair Value Measurements [Abstract]
Hedging Instruments Under the FASB's Derivative and Hedging Guidance	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. This strategy may be used in controlling our overall cost of capital associated with such borrowings. At December 31, 2014, we did not have any interest rate hedging derivative instruments outstanding. The following table summarizes our portfolio of interest rate swaps at September 30, 2015: Hedged Transaction Number and Type of Derivatives Outstanding Notional Amount Period of Hedge Rate Swap Accounting Treatment Senior Notes OO 10 fixed-to-floating swaps $ 750.0 5/2015 to 5/2018 1.65% to 0.79% Fair value hedge The prices of natural gas, NGLs, crude oil, petrochemicals and refined 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 option contracts. The following table summarizes our portfolio of commodity derivative instruments outstanding at September 30, 2015 (volume measures as noted): Volume (1) Accounting Derivative Purpose Current Long-Term Treatment Derivatives designated as hedging instruments: Natural gas processing: Forecasted natural gas purchases for plant thermal reduction (Bcf) 4.9 n/a Cash flow hedge Forecasted sales of NGLs (MMBbls) (3) 1.1 n/a Cash flow hedge Octane enhancement: Forecasted purchases of NGLs (MMBbls) 0.1 n/a Cash flow hedge Forecasted sales of octane enhancement products (MMBbls) 0.5 n/a Cash flow hedge Natural gas marketing: Forecasted purchases of natural gas for fuel (Bcf) 6.4 n/a Cash flow hedge Forecasted sales of natural gas (Bcf) 0.1 n/a Cash flow hedge Natural gas storage inventory management activities (Bcf) 10.2 n/a Fair value hedge NGL marketing: Forecasted purchases of NGLs and related hydrocarbon products (MMBbls) 34.6 0.5 Cash flow hedge Forecasted sales of NGLs and related hydrocarbon products (MMBbls) 49.8 n/a Cash flow hedge Refined products marketing: Forecasted purchases of refined products (MMBbls) 0.4 n/a Cash flow hedge Forecasted sales of refined products (MMBbls) 0.7 n/a Cash flow hedge Refined products inventory management activities (MMBbls) 0.2 n/a Fair value hedge Crude oil marketing: Forecasted purchases of crude oil (MMBbls) 9.0 1.6 Cash flow hedge Forecasted sales of crude oil (MMBbls) 11.9 1.6 Cash flow hedge Derivatives not designated as hedging instruments: Natural gas risk management activities (Bcf) (4,5) 65.9 9.6 Mark-to-market NGL risk management activities (MMBbls) (5) 14.9 n/a Mark-to-market Crude oil risk management activities (MMBbls) (5) 5.8 0.4 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 2017, April 2016 and March 2018, respectively. (3) Forecasted sales of NGL volumes under natural gas processing exclude 0.7 MMBbls of additional hedges executed under contracts that have been designated as normal sales agreements. (4) Current and long-term volumes include 38.7 Bcf and 0.9 Bcf, respectively, of physical derivative instruments that are predominantly priced at a marked-based index plus a premium or minus a discount related to location differences. (5) 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 September 30, 2015 December 31, 2014 September 30, 2015 December 31, 2014 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 Current assets $ 7.4 Current assets $ -- Other current liabilities $ -- Other current liabilities $ -- Interest rate derivatives Other assets 0.2 Other assets -- Other liabilities -- Other liabilities -- Total interest rate derivatives 7.6 -- -- -- Commodity derivatives Current assets 216.9 Current assets 217.9 Other current liabilities 178.5 Other current liabilities 145.3 Commodity derivatives Other assets 8.3 Other assets -- Other liabilities 8.2 Other liabilities -- Total commodity derivatives 225.2 217.9 186.7 145.3 Total derivatives designated as hedging instruments $ 232.8 $ 217.9 $ 186.7 $ 145.3 Derivatives not designated as hedging instruments Commodity derivatives Current assets $ 17.5 Current assets $ 8.1 Other current liabilities $ 9.4 Other current liabilities $ 0.7 Commodity derivatives Other assets 0.1 Other assets 0.6 Other liabilities 1.0 Other liabilities 1.4 Total commodity derivatives $ 17.6 $ 8.7 $ 10.4 $ 2.1
Offsetting Financial Assets	Certain of our commodity derivative instruments are subject to master netting arrangements or similar agreements. The following tables present our derivative instruments subject to such arrangements at the dates indicated: Offsetting of Financial Assets and Derivative Assets Gross Amounts of Recognized Assets Gross Amounts Offset in the Balance Sheet Amounts of Assets Presented in the Balance Sheet Gross Amounts Not Offset in the Balance Sheet Amounts That Would Have Been Presented On Net Basis Financial Instruments Cash Collateral Received Cash Collateral Paid (i) (ii) (iii) = (i) – (ii) (iv) (v) = (iii) + (iv) As of September 30, 2015: Interest rate derivatives $ 7.6 $ -- $ 7.6 $ -- $ -- $ -- $ 7.6 Commodity derivatives 242.8 -- 242.8 (180.3 ) (38.2 ) (9.6 ) 14.7 As of December 31, 2014: Commodity derivatives $ 226.6 $ -- $ 226.6 $ (147.3 ) $ (23.9 ) $ -- $ 55.4
Offsetting Financial Liabilities	Offsetting of Financial Liabilities and Derivative Liabilities Gross Amounts of Recognized Liabilities Gross Amounts Offset in the Balance Sheet Amounts of Liabilities Presented in the Balance Sheet Gross Amounts Not Offset in the Balance Sheet Amounts That Would Have Been Presented On Net Basis Financial Instruments Cash Collateral Paid (i) (ii) (iii) = (i) – (ii) (iv) (v) = (iii) + (iv) As of September 30, 2015: Commodity derivatives $ 197.1 $ -- $ 197.1 $ (180.3 ) $ -- $ 16.8 As of December 31, 2014: Commodity derivatives $ 147.4 $ -- $ 147.4 $ (147.3 ) $ -- $ 0.1
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 indicated: Derivatives in Fair Value Hedging Relationships Location Gain (Loss) Recognized in Income on Derivative For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 Interest rate derivatives Interest expense $ 5.9 $ (4.1 ) $ 5.1 $ (9.5 ) Commodity derivatives Revenue 3.6 (0.3 ) 4.0 0.6 Total $ 9.5 $ (4.4 ) $ 9.1 $ (8.9 ) Derivatives in Fair Value Hedging Relationships Location Gain (Loss) Recognized in Income on Hedged Item For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 Interest rate derivatives Interest expense $ (5.7 ) $ 3.9 $ (5.2 ) $ 9.3 Commodity derivatives Revenue (2.5 ) 1.0 7.4 (1.4 ) Total $ (8.2 ) $ 4.9 $ 2.2 $ 7.9
Derivative Instruments Effects on Statements of Comprehensive Income	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 indicated: Derivatives in Cash Flow Hedging Relationships Change in Value Recognized in Other Comprehensive Income (Loss) on Derivative (Effective Portion) For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 Commodity derivatives – Revenue (1) $ 87.4 $ 58.8 $ 113.9 $ 15.2 Commodity derivatives – Operating costs and expenses (1) (1.6 ) (0.7 ) (1.6 ) 0.9 Total $ 85.8 $ 58.1 $ 112.3 $ 16.1 (1) The fair value of these derivative instruments will be reclassified to their respective locations on the Unaudited Condensed Statement of Consolidated Operations upon settlement of the underlying derivative transactions, as appropriate.
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 Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 Interest rate derivatives Interest expense $ (8.9 ) $ (8.0 ) $ (26.3 ) $ (23.9 ) Commodity derivatives Revenue 46.8 17.8 128.6 (14.5 ) Commodity derivatives Operating costs and expenses -- 0.2 (0.5 ) 1.6 Total $ 37.9 $ 10.0 $ 101.8 $ (36.8 )
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 Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 Commodity derivatives Revenue $ (3.5 ) $ 0.1 $ (3.1 ) $ -- Commodity derivatives Operating costs and expenses -- (0.1 ) -- -- Total $ (3.5 ) $ -- $ (3.1 ) $ --
Gain/(Loss) Recognized in Income on Derivative	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 indicated: Derivatives Not Designated as Hedging Instruments Location Gain (Loss) Recognized in Income on Derivative For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 Interest rate derivatives Interest expense $ -- $ -- $ -- $ (0.1 ) Commodity derivatives Revenue -- 0.8 3.9 (26.8 ) Commodity derivatives Operating costs and expenses (0.3 ) -- -- -- Total $ (0.3 ) $ 0.8 $ 3.9 $ (26.9 )
Fair Value Measurements of Financial Assets and Liabilities Measured on a Recurring Basis	The following tables set forth, by level within the fair value hierarchy, the carrying values of our financial assets and liabilities at the dates indicated. These assets and liabilities are measured on a recurring basis and are classified based on the lowest level of input used to estimate their fair value. Our assessment of the relative significance of such inputs requires judgment. September 30, 2015 Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Financial assets: Interest rate derivatives $ -- $ 7.6 $ -- $ 7.6 Commodity derivatives 84.1 157.7 1.0 242.8 Total $ 84.1 $ 165.3 $ 1.0 $ 250.4 Financial liabilities: Liquidity Option Agreement $ -- $ -- $ 235.5 $ 235.5 Commodity derivatives 37.4 142.7 17.0 197.1 Total $ 37.4 $ 142.7 $ 252.5 $ 432.6 December 31, 2014 Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Financial assets: Commodity derivatives $ 37.8 $ 187.8 $ 1.0 $ 226.6 Financial liabilities: Liquidity Option Agreement $ -- $ -- $ 219.7 $ 219.7 Commodity derivatives 13.8 133.0 0.6 147.4 Total $ 13.8 $ 133.0 $ 220.3 $ 367.1
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 fair values of our recurring Level 3 financial assets and liabilities on a combined basis for the periods indicated: For the Nine Months Ended September 30, Location 2015 2014 Financial asset (liability) balance, net, January 1 $ (219.3 ) $ 3.2 Total gains (losses) included in: Net income (1) Revenue (0.4 ) 4.6 Other comprehensive income Commodity derivative instruments – changes in fair value of cash flow hedges (1.5 ) -- Settlements Revenue (0.5 ) (0.1 ) Transfers out of Level 3 0.1 -- Financial asset (liability) balance, net, March 31 (221.6 ) 7.7 Total gains (losses) included in: Net income (1) Revenue (0.4 ) (3.3 ) Net income Other expense, net (11.5 ) -- Other comprehensive income Commodity derivative instruments – changes in fair value of cash flow hedges (1.0 ) -- Settlements Revenue 0.2 (1.8 ) Transfers out of Level 3 1.5 -- Financial asset (liability) balance, net, June 30 (232.8 ) 2.6 Total gains (losses) included in: Net income (1) Revenue (0.3 ) (0.9 ) Net income Other expense, net (4.3 ) -- Other comprehensive income Commodity derivative instruments – changes in fair value of cash flow hedges (15.5 ) (2.5 ) Settlements Revenue 0.3 0.1 Transfers out of Level 3 1.1 -- Financial asset (liability) balance, net, September 30 $ (251.5 ) $ (0.7 ) (1) There were $1.1 million of unrealized losses included in these amounts for the nine months ended September 30, 2015. There were unrealized gains of $0.8 million and $1.3 million included in these amounts for the three and nine months ended September 30, 2014, respectively.
Fair Value Measurements, Valuation Techniques	The following Fair Value Financial Assets Financial Liabilities Valuation Techniques Unobservable Input Range Commodity derivatives – Crude oil $ 0.7 $ 1.3 Discounted cash flow Forward commodity prices $44.47-$50.74/barrel Commodity derivatives – Natural gasoline 0.3 15.6 Discounted cash flow Forward commodity prices $0.93-$1.00/gallon Commodity derivatives – Propane -- 0.1 Discounted cash flow Forward commodity prices $0.50/gallon Total $ 1.0 $ 17.0
Noncash Impairment Charges by Segment	Long-lived assets (including intangible assets with finite useful lives and property, plant and equipment) are reviewed for impairment (i.e., subject to nonrecurring fair value measurements) when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Long-lived assets with carrying values that are not expected to be recovered through future cash flows are written-down to their estimated fair values. The following table summarizes our non-cash impairment charges by segment during each of the periods indicated: For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 NGL Pipelines & Services $ 14.6 $ 1.2 $ 20.6 $ 6.6 Crude Oil Pipelines & Services -- 0.4 25.9 2.2 Natural Gas Pipelines & Services -- 0.4 21.5 0.7 Petrochemical & Refined Products Services 12.2 3.7 12.6 8.7 Offshore Pipelines & Services -- -- 58.5 -- Total $ 26.8 $ 5.7 $ 139.1 $ 18.2
Nonrecurring Fair Value Measurements	The following table presents categories of long-lived assets that were subject to non-recurring fair value measurements during the nine months ended September 30, 2015: Fair Value Measurements at the End of the Reporting Period Using Carrying Value at September 30, 2015 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Non-Cash Impairment Loss Long-lived assets disposed of other than by sale $ 0.4 $ -- $ -- $ 0.4 $ 69.9 Long-lived assets held for sale 34.2 -- -- 34.2 14.2 Long-lived assets disposed of by sale (1) -- -- -- -- 55.0 Total $ 139.1 (1) Primarily represents the impairment charge recorded in second quarter of 2015 upon reclassification of our Offshore Business to held for sale status. The following table presents categories of long-lived assets that were subject to non-recurring fair value measurements during the nine months ended September 30, 2014: Fair Value Measurements at the End of the Reporting Period Using Carrying Value at September 30, 2014 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Non-Cash Impairment Loss Long-lived assets disposed of other than by sale $ -- $ -- $ -- $ -- $ 11.7 Long-lived assets held for sale 1.1 -- -- 1.1 6.5 Total $ 18.2

Inventories (Tables)

Inventories (Tables)	9 Months Ended
	Sep. 30, 2015
Inventories [Abstract]
Inventory Amounts by Product Type	Our inventory amounts by product type were as follows at the dates indicated: September 30, 2015 December 31, 2014 NGLs $ 740.5 $ 579.1 Petrochemicals and refined products 158.0 295.6 Crude oil 152.2 97.8 Natural gas 34.7 41.7 Total $ 1,085.4 $ 1,014.2
Cost of Sales and Lower of Cost or Market Adjustments	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. 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 September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 Cost of sales (1) $ 4,419.9 $ 10,455.1 $ 15,355.9 $ 32,213.1 Lower of cost or market adjustments 2.1 6.7 6.1 14.6 (1) Cost of sales is a component of “Operating costs and expenses” as presented on our Unaudited Condensed Statements of Consolidated Operations. 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 (

Property, Plant and Equipment (Tables)	9 Months Ended
	Sep. 30, 2015
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 September 30, 2015 December 31, 2014 Plants, pipelines and facilities (1) 3-45 (6) $ 31,686.3 $ 30,834.9 Underground and other storage facilities (2) 5-40 (7) 2,847.7 2,584.2 Platforms and facilities (3) 20-31 -- 659.7 Transportation equipment (4) 3-10 164.8 154.2 Marine vessels (5) 15-30 787.5 796.4 Land 261.3 262.6 Construction in progress 3,777.2 2,754.7 Total historical cost of property, plant and equipment 39,524.8 38,046.7 Less accumulated depreciation 8,310.7 8,165.1 Total property, plant and equipment, net $ 31,214.1 $ 29,881.6 (1) Plants, pipelines and facilities 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 included offshore platforms and related facilities and other associated assets located in the Gulf of Mexico prior to the sale of our Offshore Business (see below). (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 indicated: For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 Depreciation expense (1) $ 286.2 $ 283.2 $ 870.1 $ 822.1 Capitalized interest (2) 40.3 17.2 105.6 53.4 (1) Depreciation expense is a component of “Costs and expenses” as presented on our Unaudited Condensed Statements of Consolidated Operations. (2) We capitalize interest costs incurred on funds used to construct property, plant and equipment while the asset is in its construction phase. 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. When capitalized interest is recorded, it reduces interest expense from what it would be otherwise.
AROs	The following table presents information regarding our AROs since December 31, 2014: ARO liability balance, December 31, 2014 $ 98.3 Liabilities incurred 2.7 Liabilities settled (5.9 ) Revisions in estimated cash flows 49.0 Accretion expense 4.2 AROs related to Offshore Business sold in July 2015 (91.1 ) ARO liability balance, September 30, 2015 $ 57.2

Investments in Unconsolidated30

Investments in Unconsolidated Affiliates (Tables)	9 Months Ended
	Sep. 30, 2015
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. We account for these investments using the equity method. Ownership Interest at September 30, 2015 September 30, 2015 December 31, 2014 NGL Pipelines & Services: Venice Energy Service Company, L.L.C. 13.1% $ 26.4 $ 27.7 K/D/S Promix, L.L.C. 50% 42.8 38.5 Baton Rouge Fractionators LLC 32.2% 18.4 18.8 Skelly-Belvieu Pipeline Company, L.L.C. 50% 40.3 40.1 Texas Express Pipeline LLC 35% 343.4 349.3 Texas Express Gathering LLC 45% 37.2 37.9 Front Range Pipeline LLC 33.3% 171.7 170.0 Delaware Basin Gas Processing LLC (1) 50% 28.7 -- Crude Oil Pipelines & Services: Seaway Crude Pipeline Company LLC 50% 1,403.1 1,431.2 Eagle Ford Pipeline LLC 50% 391.4 336.5 Eagle Ford Terminals Corpus Christi LLC (2) 50% 23.4 -- Natural Gas Pipelines & Services: White River Hub, LLC 50% 23.1 23.2 Petrochemical & Refined Products Services: Baton Rouge Propylene Concentrator, LLC 30% 5.8 6.5 Centennial Pipeline LLC (“Centennial”) 50% 67.2 66.1 Other Various 2.4 2.5 Offshore Pipelines & Services: Poseidon Oil Pipeline Company, L.L.C. -- -- 31.8 Cameron Highway Oil Pipeline Company -- -- 201.3 Deepwater Gateway, L.L.C. -- -- 79.6 Neptune Pipeline Company, L.L.C. -- -- 34.9 Southeast Keathley Canyon Pipeline Company L.L.C. -- -- 146.1 Total investments in unconsolidated affiliates $ 2,625.3 $ 3,042.0 (1) New joint venture formed with Oxy Delaware Basin Plant, LLC, a subsidiary of Occidental Petroleum Corporation, in April 2015 that will plan, design and construct a new cryogenic natural gas processing plant to accommodate the growing production of NGL-rich natural gas in the Delaware Basin. (2) New joint venture formed with Plains Marketing, L.P., a subsidiary of Plains All American Pipeline, L.P., in March 2015 to construct and operate a marine terminal that will handle crude oil delivered by Eagle Ford Pipeline LLC. (3) Our investments in unconsolidated affiliates classified within the Offshore Pipelines & Services segment were sold to Genesis on July 24, 2015 (see Note 6). At June 30, 2015, the carrying value of these investments was $482.4 million. The following table presents our equity in income (loss) of unconsolidated affiliates by business segment for the periods indicated: For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 NGL Pipelines & Services $ 18.9 $ 11.7 $ 43.0 $ 19.2 Crude Oil Pipelines & Services 81.2 46.8 220.5 131.7 Natural Gas Pipelines & Services 0.9 0.9 2.8 2.7 Petrochemical & Refined Products Services (3.3 ) (4.2 ) (10.4 ) (10.3 ) Offshore Pipelines & Services 5.4 17.1 46.6 35.8 Total $ 103.1 $ 72.3 $ 302.5 $ 179.1 The following table presents our unamortized excess cost amounts by business segment at the dates indicated: September 30, 2015 December 31, 2014 NGL Pipelines & Services $ 25.6 $ 26.5 Crude Oil Pipelines & Services 20.9 21.7 Petrochemical & Refined Products Services 2.4 2.4 Offshore Pipelines & Services (1) -- 9.0 Total $ 48.9 $ 59.6 (1) Our investments in unconsolidated affiliates classified within the Offshore Pipelines & Services segment were sold to Genesis in July 2015. The following table presents our amortization of excess cost amounts by business segment for the periods indicated: For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 NGL Pipelines & Services $ 0.3 $ 0.2 $ 0.9 $ 0.9 Crude Oil Pipelines & Services 0.3 0.2 0.8 0.5 Petrochemical & Refined Products Services -- -- -- 0.1 Offshore Pipelines & Services -- 0.3 2.8 0.8 Total $ 0.6 $ 0.7 $ 4.5 $ 2.3

Business Acquisitions (Tables)

Business Acquisitions (Tables)	9 Months Ended
	Sep. 30, 2015
Business Combinations [Abstract]
Allocation of Total Purchase Prices Paid in Connection with Business Combinations	The following table summarizes the consideration paid in the EFS Midstream acquisition and the amounts of the assets acquired and liabilities assumed as of July 1, 2015: Consideration: Cash $ 1,058.5 Accrued liability related to EFS Midstream acquisition 997.7 Total consideration $ 2,056.2 Identifiable assets acquired in business combination: Current assets, including cash of $13.4 million $ 64.0 Property, plant and equipment 636.0 Customer relationship intangible assets 1,409.8 Total assets acquired 2,109.8 Liabilities assumed in business combination: Current liabilities (9.6 ) Long-term debt (125.0 ) Other long-term liabilities (1.3 ) Total liabilities assumed (135.9 ) Total assets acquired less liabilities assumed 1,973.9 Total consideration given for EFS Midstream 2,056.2 Goodwill $ 82.3
Unaudited Pro Forma Earnings Information	Since the effective date of the EFS Midstream acquisition was July 1, 2015, our Unaudited Condensed Statements of Consolidated Operations do not include earnings from this business prior to this date. The following table presents selected unaudited pro forma earnings information for the nine months ended September 30, 2015 and 2014 as if the acquisition had been completed on January 1, 2014. This pro forma information was prepared using historical financial data for EFS Midstream and reflects certain estimates and assumptions made by our management. Our unaudited pro forma financial information is not necessarily indicative of what our consolidated financial results would have been for the periods presented had we acquired EFS Midstream on January 1, 2014. For the Three Months Ended September 30, 2014 For the Nine Months Ended September 30, 2015 2014 Pro forma earnings data: Revenues $ 12,388.7 $ 20,993.5 $ 37,927.5 Costs and expenses 11,502.6 18,645.5 35,195.2 Operating income 958.4 2,650.5 2,911.4 Net income 715.3 1,900.9 2,195.5 Net income attributable to noncontrolling interests 8.1 28.5 24.8 Net income attributable to limited partners 707.2 1,872.4 2,170.7 Basic earnings per unit: As reported basic earnings per unit $ 0.38 $ 0.94 $ 1.16 Pro forma basic earnings per unit $ 0.38 $ 0.96 $ 1.18 Diluted earnings per unit: As reported diluted earnings per unit $ 0.37 $ 0.92 $ 1.13 Pro forma diluted earnings per unit $ 0.38 $ 0.94 $ 1.15

Intangible Assets and Goodwill

Intangible Assets and Goodwill (Tables)	9 Months Ended
	Sep. 30, 2015
Intangible Assets and Goodwill [Abstract]
Intangible Assets by Segment	The following table summarizes our intangible assets by business segment at the dates indicated: September 30, 2015 December 31, 2014 Gross Value Accumulated Amortization Carrying Value Gross Value Accumulated Amortization Carrying Value NGL Pipelines & Services: Customer relationship intangibles $ 550.8 $ (183.8 ) $ 367.0 $ 340.8 $ (183.2 ) $ 157.6 Contract-based intangibles 283.0 (189.6 ) 93.4 277.7 (178.7 ) 99.0 IDRs (1) -- -- -- 432.6 -- 432.6 Segment total 833.8 (373.4 ) 460.4 1,051.1 (361.9 ) 689.2 Crude Oil Pipelines & Services: Customer relationship intangibles 2,204.4 (28.1 ) 2,176.3 1,108.0 (7.7 ) 1,100.3 Contract-based intangibles 281.4 (55.4 ) 226.0 281.4 (13.5 ) 267.9 IDRs (1) -- -- -- 855.4 -- 855.4 Segment total 2,485.8 (83.5 ) 2,402.3 2,244.8 (21.2 ) 2,223.6 Natural Gas Pipelines & Services: Customer relationship intangibles 1,246.9 (327.8 ) 919.1 1,163.6 (308.9 ) 854.7 Contract-based intangibles 466.0 (359.4 ) 106.6 466.0 (347.8 ) 118.2 Segment total 1,712.9 (687.2 ) 1,025.7 1,629.6 (656.7 ) 972.9 Petrochemical & Refined Products Services: Customer relationship intangibles 185.5 (37.3 ) 148.2 198.4 (43.3 ) 155.1 Contract-based intangibles 56.3 (10.8 ) 45.5 56.3 (7.8 ) 48.5 IDRs (1) -- -- -- 171.2 -- 171.2 Segment total 241.8 (48.1 ) 193.7 425.9 (51.1 ) 374.8 Offshore Pipelines & Services: Customer relationship intangibles -- -- -- 195.8 (154.9 ) 40.9 Contract-based intangibles -- -- -- 1.2 (0.5 ) 0.7 Segment total -- -- -- 197.0 (155.4 ) 41.6 Total intangible assets $ 5,274.3 $ (1,192.2 ) 4,082.1 $ 5,548.4 $ (1,246.3 ) $ 4,302.1 (1) At December 31, 2014, we had indefinite-lived intangible assets outstanding with a carrying value of $1.46 billion recorded in connection with our acquisition of the Oiltanking IDRs in October 2014. The IDRs represented contractual rights to future cash incentive distributions to be paid by Oiltanking. In February 2015 (following completion of Step 2 of the Oiltanking acquisition), the Oiltanking IDRs were cancelled and the carrying value of the IDRs were reclassified to goodwill. (2) Our intangible assets classified within the Offshore Pipelines & Services segment were sold to Genesis in July 2015 (see Note 6).
Amortization Expense of Intangible Assets by Segment	The following table presents the amortization expense of our intangible assets by business segment for the periods indicated: For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 NGL Pipelines & Services $ 9.7 $ 8.1 $ 24.9 $ 25.4 Crude Oil Pipelines & Services 29.0 0.3 62.3 0.9 Natural Gas Pipelines & Services 10.7 11.1 30.5 34.2 Petrochemical & Refined Products Services 2.3 1.5 7.0 4.6 Offshore Pipelines & Services -- 2.5 4.5 7.6 Total $ 51.7 $ 23.5 $ 129.2 $ 72.7
Forecasted Amortization Expense	The following table presents a forecast of amortization expense associated with our intangible assets for the periods indicated: Remainder of 2015 2016 2017 2018 2019 $ 50.3 $ 218.8 $ 223.5 $ 220.4 $ 208.6
Changes in Carrying Amount of 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. The following table presents changes in the carrying amount of goodwill since December 31, 2014: NGL Pipelines & Services Crude Oil Pipelines & Services Natural Gas Pipelines & Services Petrochemical & Refined Products Services Offshore Pipelines & Services Consolidated Total Balance at December 31, 2014 $ 2,210.2 $ 918.7 $ 296.3 $ 793.0 $ 82.0 $ 4,300.2 Reclassification of Oiltanking IDR balances to goodwill in connection with the cancellation of such rights in February 2015 and other adjustments 432.6 850.7 -- 170.8 -- 1,454.1 Reduction in goodwill related to the sale of assets -- -- -- -- (82.0 ) (82.0 ) Addition to goodwill related to the acquisition of EFS Midstream 8.9 73.4 -- -- -- 82.3 Goodwill reclassified to assets held-for-sale -- -- -- (5.4 ) -- (5.4 ) Balance at September 30, 2015 $ 2,651.7 $ 1,842.8 $ 296.3 $ 958.4 $ -- $ 5,749.2

Debt Obligations (Tables)

Debt Obligations (Tables)	9 Months Ended
	Sep. 30, 2015
Debt Obligations [Abstract]
Consolidated Debt Obligations	The following table presents our consolidated debt obligations (arranged by company and maturity date) at the dates indicated: September 30, 2015 December 31, 2014 EPO senior debt obligations: Commercial Paper Notes, variable-rates $ 869.5 $ 906.5 Senior Notes I, 5.00% fixed-rate, due March 2015 -- 250.0 Senior Notes X, 3.70% fixed-rate, due June 2015 -- 400.0 Senior Notes FF, 1.25% fixed-rate, due August 2015 -- 650.0 Senior Notes AA, 3.20% fixed-rate, due February 2016 750.0 750.0 364-Day Credit Agreement, variable-rate, due September 2016 -- -- 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 OO, 1.65% fixed-rate, due May 2018 750.0 -- Senior Notes N, 6.50% fixed-rate, due January 2019 700.0 700.0 Senior Notes LL, 2.55% fixed-rate, due October 2019 800.0 800.0 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 Multi-Year Revolving Credit Facility, variable-rate, due September 2020 -- -- Senior Notes CC, 4.05% fixed-rate, due February 2022 650.0 650.0 Senior Notes HH, 3.35% fixed-rate, due March 2023 1,250.0 1,250.0 Senior Notes JJ, 3.90% fixed-rate, due February 2024 850.0 850.0 Senior Notes MM, 3.75% fixed-rate, due February 2025 1,150.0 1,150.0 Senior Notes PP, 3.70% fixed-rate, due February 2026 875.0 -- 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 750.0 750.0 Senior Notes GG, 4.45% fixed-rate, due February 2043 1,100.0 1,100.0 Senior Notes II, 4.85% fixed-rate, due March 2044 1,400.0 1,400.0 Senior Notes KK, 5.10% fixed-rate, due February 2045 1,150.0 1,150.0 Senior Notes QQ, 4.90% fixed-rate, due May 2046 875.0 -- Senior Notes NN, 4.95% fixed-rate, due October 2054 400.0 400.0 TEPPCO senior debt obligations: 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 21,019.5 19,856.5 EPO Junior Subordinated Notes A, fixed/variable-rate, due August 2066 (1) 521.9 550.0 EPO Junior Subordinated Notes C, fixed/variable-rate, due June 2067 259.5 285.8 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 22,497.8 21,389.2 Other, non-principal amounts (37.7 ) (25.4 ) Less current maturities of debt (4) (1,619.4 ) (2,206.4 ) Total long-term debt $ 20,840.7 $ 19,157.4 (1) Fixed rate of 8.375% through August 1, 2016 (i.e., first call date without a make-whole redemption premium); thereafter, variable rate based on 3-month LIBOR plus 3.7075%. During the third quarter of 2015, EPO retired $28.1 million of these junior notes. (2) Fixed rate of 7.0% through September 1, 2017 (i.e., first call date without a make-whole redemption premium); thereafter, variable rate based on 3-month LIBOR plus 2.7775%. During the third quarter of 2015, EPO retired $26.3 million of these junior notes. (3) Fixed rate of 7.034% through January 15, 2018 (i.e., first call date without a make-whole redemption premium); thereafter, the rate will be the greater of 7.034% or a variable rate based on 3-month LIBOR plus 2.68%. (4) We expect to refinance the current maturities of our debt obligations at or prior to their maturity .
Consolidated Debt Maturities	The following table presents contractually scheduled maturities of our consolidated debt obligations outstanding at September 30, 2015 for the next five years, and in total thereafter: Scheduled Maturities of Debt Total Remainder of 2015 2016 2017 2018 2019 After 2019 Commercial Paper Notes $ 869.5 $ 869.5 $ -- $ -- $ -- $ -- $ -- Senior Notes 20,150.0 -- 750.0 800.0 1,100.0 1,500.0 16,000.0 Junior Subordinated Notes 1,478.3 -- -- -- -- -- 1,478.3 Total $ 22,497.8 $ 869.5 $ 750.0 $ 800.0 $ 1,100.0 $ 1,500.0 $ 17,478.3
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 during the nine months ended September 30, 2015: Range of Interest Rates Paid Weighted-Average Interest Rate Paid Commercial Paper Notes 0.35% to 0.78% 0.59% EPO Multi-Year Revolving Credit Facility 1.15% to 3.25% 1.30%

Equity and Distributions (Table

Equity and Distributions (Tables)	9 Months Ended
	Sep. 30, 2015
Equity and Distributions [Abstract]
Summary of Changes in Outstanding Units	Partners’ equity reflects the various classes of limited partner interests (i.e., common units, including restricted common units) that we have outstanding. The following table summarizes changes in the number of our outstanding units since December 31, 2014: Common Units (Unrestricted) Restricted Common Units Total Common Units Number of units outstanding at December 31, 2014 1,933,095,027 4,229,790 1,937,324,817 Common units issued in connection with ATM program 23,258,453 -- 23,258,453 Common units issued in connection with DRIP and EUPP 8,251,315 -- 8,251,315 Common units issued in connection with Step 2 of Oiltanking acquisition 36,827,517 -- 36,827,517 Common units issued in connection with the vesting and exercise of unit options 333,002 -- 333,002 Common units issued in connection with the vesting of phantom unit awards 613,689 -- 613,689 Common units issued in connection with the vesting of restricted common unit awards 1,997,194 (1,997,194) -- Forfeiture of restricted common unit awards -- (157,750) (157,750) Acquisition and cancellation of treasury units in connection with the vesting of equity-based awards (680,496) -- (680,496) Other 15,054 -- 15,054 Number of units outstanding at September 30, 2015 2,003,710,755 2,074,846 2,005,785,601
Components of Accumulated Other Comprehensive Income (Loss)	The following tables present the components of accumulated other comprehensive income (loss) as reported on our Unaudited Condensed Consolidated Balance Sheets at the dates indicated: Gains (Losses) on Cash Flow Hedges Commodity Derivative Instruments Interest Rate Derivative Instruments Other Total Balance, December 31, 2014 $ 69.9 $ (314.8 ) $ 3.3 $ (241.6 ) Other comprehensive income before reclassifications 112.3 -- 0.4 112.7 Amounts reclassified from accumulated other comprehensive loss (income) (128.1 ) 26.3 -- (101.8 ) Total other comprehensive income (loss) (15.8 ) 26.3 0.4 10.9 Balance, September 30, 2015 $ 54.1 $ (288.5 ) $ 3.7 $ (230.7 ) Gains (Losses) on Cash Flow Hedges Commodity Derivative Instruments Interest Rate Derivative Instruments Other Total Balance, December 31, 2013 $ (14.7 ) $ (347.2 ) $ 2.9 $ (359.0 ) Other comprehensive income before reclassifications 16.1 -- -- 16.1 Amounts reclassified from accumulated other comprehensive loss 12.9 23.9 -- 36.8 Total other comprehensive income 29.0 23.9 -- 52.9 Balance, September 30, 2014 $ 14.3 $ (323.3 ) $ 2.9 $ (306.1 )
Reclassification out of Accumulated Other Comprehensive Income (Loss)	The following table presents reclassifications out of accumulated other comprehensive income (loss) into net income during the periods indicated: For the Three Months Ended September 30, For the Nine Months Ended September 30, Location 2015 2014 2015 2014 Losses (gains) on cash flow hedges: Interest rate derivatives Interest expense $ 8.9 $ 8.0 $ 26.3 $ 23.9 Commodity derivatives Revenue (46.8 ) (17.8 ) (128.6 ) 14.5 Commodity derivatives Operating costs and expenses -- (0.2 ) 0.5 (1.6 ) Total $ (37.9 ) $ (10.0 ) $ (101.8 ) $ 36.8
Declared Quarterly Cash Distribution Rates	The following table presents our declared quarterly cash distribution rates per common unit with respect to the quarter indicated: Distribution Per Common Unit Record Date Payment Date 2014: 1st Quarter $ 0.3550 4/30/2014 5/7/2014 2nd Quarter $ 0.3600 7/31/2014 8/7/2014 3rd Quarter $ 0.3650 10/31/2014 11/7/2014 2015: 1st Quarter $ 0.3750 4/30/2015 5/7/2015 2nd Quarter $ 0.3800 7/31/2015 8/7/2015 3rd Quarter $ 0.3850 10/30/2015 11/6/2015

Business Segments (Tables)

Business Segments (Tables)	9 Months Ended
	Sep. 30, 2015
Business Segments [Abstract]
Measurement of Total Segment Gross Operating Margin	The following table presents our measurement of non-GAAP total segment gross operating margin for the periods indicated: For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 Revenues $ 6,307.9 $ 12,330.2 $ 20,872.9 $ 37,760.9 Subtract operating costs and expenses (5,452.6 ) (11,414.8 ) (18,426.5 ) (34,934.4 ) Add equity in income of unconsolidated affiliates 103.1 72.3 302.5 179.1 Add depreciation, amortization and accretion expense amounts not reflected in gross operating margin 351.1 322.7 1,082.0 936.5 Add impairment charges not reflected in gross operating margin 26.8 5.7 139.1 18.2 Add net losses or subtract net gains attributable to asset sales and insurance recoveries not reflected in gross operating margin (see Note 16) 12.3 (2.6 ) 14.7 (99.0 ) Add non-refundable deferred revenues attributable to shipper make-up rights on new pipeline projects reflected in gross operating margin 3.4 21.6 39.3 66.8 Subtract subsequent recognition of deferred revenues attributable to make-up rights not reflected in gross operating margin (10.9 ) -- (45.3 ) -- Total segment gross operating margin $ 1,341.1 $ 1,335.1 $ 3,978.7 $ 3,928.1
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 September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 Total segment gross operating margin $ 1,341.1 $ 1,335.1 $ 3,978.7 $ 3,928.1 Adjustments to reconcile total segment gross operating margin to operating income: Subtract depreciation, amortization and accretion expense amounts not reflected in gross operating margin (351.1 ) (322.7 ) (1,082.0 ) (936.5 ) Subtract impairment charges not reflected in gross operating margin (26.8 ) (5.7 ) (139.1 ) (18.2 ) Add net gains or subtract net losses attributable to asset sales and insurance recoveries not reflected in gross operating margin (12.3 ) 2.6 (14.7 ) 99.0 Subtract non-refundable deferred revenues attributable to shipper make-up rights on new pipeline projects reflected in gross operating margin (3.4 ) (21.6 ) (39.3 ) (66.8 ) Add subsequent recognition of deferred revenues attributable to make-up rights not reflected in gross operating margin 10.9 -- 45.3 -- Subtract general and administrative costs not reflected in gross operating margin (49.0 ) (50.0 ) (143.2 ) (150.9 ) Operating income 909.4 937.7 2,605.7 2,854.7 Other expense, net (246.2 ) (230.8 ) (736.4 ) (679.8 ) Income before income taxes $ 663.2 $ 706.9 $ 1,869.3 $ 2,174.9
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 Crude Oil Pipelines & Services Natural Gas Pipelines & Services Petrochemical & Refined Products Services Offshore Pipelines & Services Adjustments and Eliminations Consolidated Total Revenues from third parties: Three months ended September 30, 2015 $ 2,284.6 $ 2,316.4 $ 705.2 $ 980.0 $ 7.8 $ -- $ 6,294.0 Three months ended September 30, 2014 4,024.0 5,435.6 1,026.5 1,792.0 41.1 -- 12,319.2 Nine months ended September 30, 2015 7,223.2 8,080.4 2,117.5 3,347.6 76.9 -- 20,845.6 Nine months ended September 30, 2014 13,217.2 16,236.6 3,261.0 4,869.9 112.4 -- 37,697.1 Revenues from related parties: Three months ended September 30, 2015 2.2 6.2 4.5 -- 1.0 -- 13.9 Three months ended September 30, 2014 2.7 1.5 5.4 -- 1.4 -- 11.0 Nine months ended September 30, 2015 6.0 8.6 10.8 -- 1.9 -- 27.3 Nine months ended September 30, 2014 10.2 31.1 16.5 -- 6.0 -- 63.8 Intersegment and intrasegment revenues: Three months ended September 30, 2015 2,461.0 1,142.1 180.2 267.3 0.1 (4,050.7 ) -- Three months ended September 30, 2014 3,603.8 2,529.5 231.0 452.2 1.2 (6,817.7 ) -- Nine months ended September 30, 2015 7,685.1 3,958.9 519.7 875.8 0.6 (13,040.1 ) -- Nine months ended September 30, 2014 10,789.7 10,714.5 835.8 1,317.6 4.8 (23,662.4 ) -- Total revenues: Three months ended September 30, 2015 4,747.8 3,464.7 889.9 1,247.3 8.9 (4,050.7 ) 6,307.9 Three months ended September 30, 2014 7,630.5 7,966.6 1,262.9 2,244.2 43.7 (6,817.7 ) 12,330.2 Nine months ended September 30, 2015 14,914.3 12,047.9 2,648.0 4,223.4 79.4 (13,040.1 ) 20,872.9 Nine months ended September 30, 2014 24,017.1 26,982.2 4,113.3 6,187.5 123.2 (23,662.4 ) 37,760.9 Equity in income (loss) of unconsolidated affiliates: Three months ended September 30, 2015 18.9 81.2 0.9 (3.3 ) 5.4 -- 103.1 Three months ended September 30, 2014 11.7 46.8 0.9 (4.2 ) 17.1 -- 72.3 Nine months ended September 30, 2015 43.0 220.5 2.8 (10.4 ) 46.6 -- 302.5 Nine months ended September 30, 2014 19.2 131.7 2.7 (10.3 ) 35.8 -- 179.1 Gross operating margin: Three months ended September 30, 2015 695.5 254.6 192.4 191.5 7.1 -- 1,341.1 Three months ended September 30, 2014 711.5 190.8 195.4 190.3 47.1 -- 1,335.1 Nine months ended September 30, 2015 2,041.3 704.2 588.3 547.4 97.5 -- 3,978.7 Nine months ended September 30, 2014 2,172.4 534.5 618.8 482.4 120.0 -- 3,928.1 Property, plant and equipment, net: (see Note 6) At September 30, 2015 12,192.8 3,550.0 8,680.6 3,013.5 -- 3,777.2 31,214.1 At December 31, 2014 11,766.9 2,332.2 8,835.5 3,047.2 1,145.1 2,754.7 29,881.6 Investments in unconsolidated affiliates: (see Note 7) At September 30, 2015 708.9 1,817.9 23.1 75.4 -- -- 2,625.3 At December 31, 2014 682.3 1,767.7 23.2 75.1 493.7 -- 3,042.0 Intangible assets, net: At September 30, 2015 460.4 2,402.3 1,025.7 193.7 -- -- 4,082.1 At December 31, 2014 689.2 2,223.6 972.9 374.8 41.6 -- 4,302.1 Goodwill: At September 30, 2015 2,651.7 1,842.8 296.3 958.4 -- -- 5,749.2 At December 31, 2014 2,210.2 918.7 296.3 793.0 82.0 -- 4,300.2 Segment assets: At September 30, 2015 16,013.8 9,613.0 10,025.7 4,241.0 -- 3,777.2 43,670.7 At December 31, 2014 15,348.6 7,242.2 10,127.9 4,290.1 1,762.4 2,754.7 41,525.9
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 September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 NGL Pipelines & Services: Sales of NGLs and related products $ 1,844.9 $ 3,603.4 $ 5,936.2 $ 12,029.8 Midstream services 441.9 423.3 1,293.0 1,197.6 Total 2,286.8 4,026.7 7,229.2 13,227.4 Crude Oil Pipelines & Services: Sales of crude oil 2,147.3 5,348.2 7,689.3 16,003.5 Midstream services 175.3 88.9 399.7 264.2 Total 2,322.6 5,437.1 8,089.0 16,267.7 Natural Gas Pipelines & Services: Sales of natural gas 455.0 775.5 1,361.2 2,515.7 Midstream services 254.7 256.4 767.1 761.8 Total 709.7 1,031.9 2,128.3 3,277.5 Petrochemical & Refined Products Services: Sales of petrochemicals and refined products 780.5 1,605.4 2,764.2 4,338.2 Midstream services 199.5 186.6 583.4 531.7 Total 980.0 1,792.0 3,347.6 4,869.9 Offshore Pipelines & Services: Sales of natural gas -- -- -- 0.2 Sales of crude oil 0.4 2.5 3.2 7.5 Midstream services 8.4 40.0 75.6 110.7 Total 8.8 42.5 78.8 118.4 Total consolidated revenues $ 6,307.9 $ 12,330.2 $ 20,872.9 $ 37,760.9 Consolidated costs and expenses Operating costs and expenses: Cost of sales $ 4,419.9 $ 10,455.1 $ 15,355.9 $ 32,213.1 Other operating costs and expenses (1) 642.5 633.9 1,834.8 1,865.6 Depreciation, amortization and accretion 351.1 322.7 1,082.0 936.5 Ne t losses (g and insurance recoveries 12.3 (2.6 ) 14.7 (99.0 ) Non-cash asset impairment charges 26.8 5.7 139.1 18.2 General and administrative costs 49.0 50.0 143.2 150.9 Total consolidated costs and expenses $ 5,501.6 $ 11,464.8 $ 18,569.7 $ 35,085.3 (1) Represents cost of operating our plants, pipelines and other fixed assets, excluding depreciation, amortization and accretion charges.

Related Party Transactions (Tab

Related Party Transactions (Tables)	9 Months Ended
	Sep. 30, 2015
Related Party Transactions [Abstract]
Related Party Transactions	The following table summarizes our related party transactions for the periods indicated: For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 Revenues – related parties: Unconsolidated affiliates $ 13.9 $ 11.0 $ 27.3 $ 63.8 Costs and expenses – related parties: EPCO and its privately held affiliates $ 246.0 $ 212.8 $ 703.9 $ 688.0 Unconsolidated affiliates 66.9 35.8 165.3 138.4 Total $ 312.9 $ 248.6 $ 869.2 $ 826.4 The following table summarizes our related party accounts receivable and accounts payable balances at the dates indicated: September 30, 2015 December 31, 2014 Accounts receivable - related parties: Unconsolidated affiliates $ 1.7 $ 2.8 Accounts payable - related parties: EPCO and its privately held affiliates $ 64.6 $ 98.1 Unconsolidated affiliates 15.7 20.8 Total $ 80.3 $ 118.9 At September 30, 2015, EPCO and its privately held affiliates (including Dan Duncan LLC and certain Duncan family trusts) beneficially owned the following limited partner interests in us: Total Number of Units Percentage of Total Units Outstanding 675,259,617 33.7% 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 our related party costs and expenses attributable to the ASA with EPCO for the periods indicated: For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 Operating costs and expenses $ 215.3 $ 179.0 $ 612.2 $ 591.6 General and administrative expenses 26.4 29.6 78.8 84.5 Total costs and expenses $ 241.7 $ 208.6 $ 691.0 $ 676.1

Earnings Per Unit (Tables)

Earnings Per Unit (Tables)	9 Months Ended
	Sep. 30, 2015
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 September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 BASIC EARNINGS PER UNIT Net income attributable to limited partners $ 649.3 $ 691.1 $ 1,836.4 $ 2,127.6 Undistributed earnings allocated and cash payments on phantom unit awards (1) (2.2 ) (1.3 ) (6.6 ) (4.0 ) Net income available to common unitholders $ 647.1 $ 689.8 $ 1,829.8 $ 2,123.6 Basic weighted-average number of common units outstanding 1,969.3 1,834.2 1,952.3 1,831.1 Basic earnings per unit $ 0.33 $ 0.38 $ 0.94 $ 1.16 DILUTED EARNINGS PER UNIT Net income attributable to limited partners $ 649.3 $ 691.1 $ 1,836.4 $ 2,127.6 Diluted weighted-average number of units outstanding: Distribution-bearing common units 1,969.3 1,834.2 1,952.3 1,831.1 Designated Units 35.4 45.1 35.4 45.1 Phantom units (1) 5.7 3.4 5.4 2.8 Incremental option units 0.1 0.7 0.2 1.0 Total 2,010.5 1,883.4 1,993.3 1,880.0 Diluted earnings per unit $ 0.32 $ 0.37 $ 0.92 $ 1.13 (1) Each phantom unit award includes a DER, which entitles the recipient to receive cash payments equal to the product of the number of phantom unit awards and the cash distribution per unit paid to our common unitholders. Cash payments made in connection with DERs are nonforfeitable. As a result, the phantom units are considered participating securities for purposes of computing basic earnings per unit. Phantom unit awards were first issued in February 2014.

Supplemental Cash Flow Inform38

Supplemental Cash Flow Information (Tables)	9 Months Ended
	Sep. 30, 2015
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 Nine Months Ended September 30, 2015 2014 Decrease (increase) in: Accounts receivable – trade $ 1,042.5 $ 153.6 Accounts receivable – related parties 1.2 4.0 Inventories (143.2 ) (536.9 ) Prepaid and other current assets (32.7 ) (44.5 ) Other assets 2.1 20.0 Increase (decrease) in: Accounts payable – trade (72.7 ) (14.2 ) Accounts payable – related parties (38.6 ) (27.7 ) Accrued product payables (1,248.4 ) (13.1 ) Accrued interest (136.7 ) (131.7 ) Other current liabilities (13.8 ) 143.5 Other liabilities 12.4 11.2 Net effect of changes in operating accounts $ (627.9 ) $ (435.8 )
Schedule of Significant Acquisitions and Disposals	The following table presents our cash proceeds from asset sales and insurance recoveries for the periods indicated: For the Nine Months Ended September 30, 2015 2014 Sale of Offshore Business (see Note 6) $ 1,528.6 $ -- Insurance recoveries attributable to West Storage claims -- 95.0 Other cash proceeds 8.7 26.5 Total $ 1,537.3 $ 121.5 The following table presents net gains (losses) attributable to asset sales and insurance recoveries for the periods indicated: For the Nine Months Ended September 30, 2015 2014 Sale of Offshore Business (see Note 6) $ (12.6 ) $ -- Gains attributable to West Storage insurance recoveries -- 95.0 Ne (2.1 ) 4.0 Total $ (14.7 ) $ 99.0

Condensed Consolidating Finan39

Condensed Consolidating Financial Information (Tables)	9 Months Ended
	Sep. 30, 2015
Condensed Consolidating Financial Information [Abstract]
Condensed Consolidating Balance Sheet	Enterprise Products Partners L.P. Unaudited Condensed Consolidating Balance Sheet September 30, 2015 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 $ 46.9 $ 85.3 $ (5.5 ) $ 126.7 $ -- $ -- $ 126.7 Accounts receivable – trade, net 791.0 2,011.3 (0.3 ) 2,802.0 -- -- 2,802.0 Accounts receivable – related parties 123.1 780.8 (901.5 ) 2.4 -- (0.7 ) 1.7 Inventories 889.1 196.6 (0.3 ) 1,085.4 -- -- 1,085.4 Derivative assets 139.1 102.7 -- 241.8 -- -- 241.8 Prepaid and other current assets 164.7 247.7 (10.2 ) 402.2 0.2 -- 402.4 Total current assets 2,153.9 3,424.4 (917.8 ) 4,660.5 0.2 (0.7 ) 4,660.0 Property, plant and equipment, net 3,432.3 27,780.4 1.4 31,214.1 -- -- 31,214.1 Investments in unconsolidated affiliates 38,310.0 4,094.7 (39,779.4 ) 2,625.3 20,397.5 (20,397.5 ) 2,625.3 Intangible assets, net 726.8 3,370.1 (14.8 ) 4,082.1 -- -- 4,082.1 Goodwill 459.1 5,290.1 -- 5,749.2 -- -- 5,749.2 Other assets 226.4 49.0 (78.8 ) 196.6 0.5 -- 197.1 Total assets $ 45,308.5 $ 44,008.7 $ (40,789.4 ) $ 48,527.8 $ 20,398.2 $ (20,398.2 ) $ 48,527.8 LIABILITIES AND EQUITY Current liabilities: Current maturities of debt $ 1,619.3 $ 0.1 $ -- $ 1,619.4 $ -- $ -- $ 1,619.4 Accounts payable – trade 331.4 519.0 (5.5 ) 844.9 -- -- 844.9 Accounts payable – related parties 866.7 130.1 (916.5 ) 80.3 0.7 (0.7 ) 80.3 Accrued product payables 938.0 1,611.2 (1.3 ) 2,547.9 -- -- 2,547.9 Accrued liability related to EFS Midstream acquisition -- 997.7 -- 997.7 -- -- 997.7 Accrued interest 198.6 0.3 -- 198.9 -- -- 198.9 Other current liabilities 174.3 425.1 (10.0 ) 589.4 (0.1 ) 0.5 589.8 Total current liabilities 4,128.3 3,683.5 (933.3 ) 6,878.5 0.6 (0.2 ) 6,878.9 Long-term debt 20,825.4 15.3 -- 20,840.7 -- -- 20,840.7 Deferred tax liabilities 3.2 47.4 (1.0 ) 49.6 -- 3.8 53.4 Other long-term liabilities 10.6 234.3 (78.5 ) 166.4 235.5 -- 401.9 Commitments and contingencies Equity: Partners’ and other owners’ equity 20,341.0 39,986.1 (39,954.0 ) 20,373.1 20,162.1 (20,373.1 ) 20,162.1 Noncontrolling interests -- 42.1 177.4 219.5 -- (28.7 ) 190.8 Total equity 20,341.0 40,028.2 (39,776.6 ) 20,592.6 20,162.1 (20,401.8 ) 20,352.9 Total liabilities and equity $ 45,308.5 $ 44,008.7 $ (40,789.4 ) $ 48,527.8 $ 20,398.2 $ (20,398.2 ) $ 48,527.8 Enterprise Products Partners L.P. Unaudited Condensed Consolidating Balance Sheet December 31, 2014 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 $ 18.7 $ 70.4 $ (14.7 ) $ 74.4 $ -- $ -- $ 74.4 Accounts receivable – trade, net 1,128.5 2,698.2 (3.7 ) 3,823.0 -- -- 3,823.0 Accounts receivable – related parties 158.8 1,114.6 (1,266.6 ) 6.8 -- (4.0 ) 2.8 Inventories 831.8 182.8 (0.4 ) 1,014.2 -- -- 1,014.2 Derivative assets 102.0 124.0 -- 226.0 -- -- 226.0 Prepaid and other current assets 435.7 222.3 (308.5 ) 349.5 -- 0.8 350.3 Total current assets 2,675.5 4,412.3 (1,593.9 ) 5,493.9 -- (3.2 ) 5,490.7 Property, plant and equipment, net 2,871.7 26,912.0 97.9 29,881.6 -- -- 29,881.6 Investments in unconsolidated affiliates 36,937.5 3,556.4 (37,451.9 ) 3,042.0 18,287.5 (18,287.5 ) 3,042.0 Intangible assets, net 2,527.3 1,292.4 482.4 4,302.1 -- -- 4,302.1 Goodwill 1,956.1 1,721.4 622.7 4,300.2 -- -- 4,300.2 Other assets 139.3 45.8 (0.7 ) 184.4 -- -- 184.4 Total assets $ 47,107.4 $ 37,940.3 $ (37,843.5 ) $ 47,204.2 $ 18,287.5 $ (18,290.7 ) $ 47,201.0 LIABILITIES AND EQUITY Current liabilities: Current maturities of debt $ 2,206.4 $ -- $ -- $ 2,206.4 $ -- $ -- $ 2,206.4 Accounts payable – trade 216.6 571.4 (14.8 ) 773.2 0.6 -- 773.8 Accounts payable – related parties 1,226.5 173.3 (1,280.9 ) 118.9 4.0 (4.0 ) 118.9 Accrued product payables 1,570.0 2,287.9 (4.6 ) 3,853.3 -- -- 3,853.3 Accrued interest 335.4 0.7 (0.6 ) 335.5 -- -- 335.5 Other current liabilities 130.8 763.7 (308.7 ) 585.8 -- -- 585.8 Total current liabilities 5,685.7 3,797.0 (1,609.6 ) 7,873.1 4.6 (4.0 ) 7,873.7 Long-term debt 19,142.5 14.9 -- 19,157.4 -- -- 19,157.4 Deferred tax liabilities 4.9 58.5 (0.9 ) 62.5 -- 4.1 66.6 Other long-term liabilities 10.9 180.8 (0.3 ) 191.4 219.7 -- 411.1 Commitments and contingencies Equity: Partners’ and other owners’ equity 22,263.4 33,820.9 (37,820.6 ) 18,263.7 18,063.2 (18,263.7 ) 18,063.2 Noncontrolling interests -- 68.2 1,587.9 1,656.1 -- (27.1 ) 1,629.0 Total equity 22,263.4 33,889.1 (36,232.7 ) 19,919.8 18,063.2 (18,290.8 ) 19,692.2 Total liabilities and equity $ 47,107.4 $ 37,940.3 $ (37,843.5 ) $ 47,204.2 $ 18,287.5 $ (18,290.7 ) $ 47,201.0
Condensed Consolidating Statement of Operations	Enterprise Products Partners L.P. Unaudited Condensed Consolidating Statement of Operations For the Three Months Ended September 30, 2015 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 $ 4,685.2 $ 4,531.1 $ (2,908.4 ) $ 6,307.9 $ -- $ -- $ 6,307.9 Costs and expenses: Operating costs and expenses 4,506.7 3,854.5 (2,908.6 ) 5,452.6 -- -- 5,452.6 General and administrative costs 11.1 38.3 -- 49.4 (0.4 ) -- 49.0 Total costs and expenses 4,517.8 3,892.8 (2,908.6 ) 5,502.0 (0.4 ) -- 5,501.6 Equity in income of unconsolidated affiliates 725.5 116.5 (738.9 ) 103.1 653.2 (653.2 ) 103.1 Operating income 892.9 754.8 (738.7 ) 909.0 653.6 (653.2 ) 909.4 Other income (expense): Interest expense (239.5 ) (4.2 ) -- (243.7 ) -- -- (243.7 ) Other, net 1.7 0.1 -- 1.8 (4.3 ) -- (2.5 ) Total other expense, net (237.8 ) (4.1 ) -- (241.9 ) (4.3 ) -- (246.2 ) Income before income taxes 655.1 750.7 (738.7 ) 667.1 649.3 (653.2 ) 663.2 Provision for income taxes (3.3 ) (2.2 ) -- (5.5 ) -- -- (5.5 ) Net income 651.8 748.5 (738.7 ) 661.6 649.3 (653.2 ) 657.7 Net loss (income) att -- -- (9.7 ) (9.7 ) -- 1.3 (8.4 ) Net income attributable to entity $ 651.8 $ 748.5 $ (748.4 ) $ 651.9 $ 649.3 $ (651.9 ) $ 649.3 Enterprise Products Partners L.P. Unaudited Condensed Consolidating Statement of Operations For the Three Months Ended September 30, 2014 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 $ 8,121.5 $ 8,598.2 $ (4,389.5 ) $ 12,330.2 $ -- $ -- $ 12,330.2 Costs and expenses: Operating costs and expenses 7,950.9 7,853.5 (4,389.6 ) 11,414.8 -- -- 11,414.8 General and administrative costs 8.2 40.4 -- 48.6 1.4 -- 50.0 Total costs and expenses 7,959.1 7,893.9 (4,389.6 ) 11,463.4 1.4 -- 11,464.8 Equity in income of unconsolidated affiliates 762.5 94.4 (784.6 ) 72.3 692.5 (692.5 ) 72.3 Operating income 924.9 798.7 (784.5 ) 939.1 691.1 (692.5 ) 937.7 Other income (expense): Interest expense (229.2 ) (0.6 ) -- (229.8 ) -- -- (229.8 ) Other, net 0.2 (1.2 ) -- (1.0 ) -- -- (1.0 ) Total other expense, net (229.0 ) (1.8 ) -- (230.8 ) -- -- (230.8 ) Income before income taxes 695.9 796.9 (784.5 ) 708.3 691.1 (692.5 ) 706.9 Provision for income taxes (4.0 ) (2.8 ) -- (6.8 ) -- (0.9 ) (7.7 ) Net income 691.9 794.1 (784.5 ) 701.5 691.1 (693.4 ) 699.2 Net income attributable to noncontrolling interests -- 0.1 (9.5 ) (9.4 ) -- 1.3 (8.1 ) Net income attributable to entity $ 691.9 $ 794.2 $ (794.0 ) $ 692.1 $ 691.1 $ (692.1 ) $ 691.1 Enterprise Products Partners L.P. Unaudited Condensed Consolidating Statement of Operations For the Nine Months Ended September 30, 2015 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 $ 15,301.0 $ 14,751.0 $ (9,179.1 ) $ 20,872.9 $ -- $ -- $ 20,872.9 Costs and expenses: Operating costs and expenses 14,696.2 12,909.8 (9,179.5 ) 18,426.5 -- -- 18,426.5 General and administrative costs 28.9 113.9 -- 142.8 0.4 -- 143.2 Total costs and expenses 14,725.1 13,023.7 (9,179.5 ) 18,569.3 0.4 -- 18,569.7 Equity in income of unconsolidated affiliates 1,996.4 314.5 (2,008.4 ) 302.5 1,852.6 (1,852.6 ) 302.5 Operating income 2,572.3 2,041.8 (2,008.0 ) 2,606.1 1,852.2 (1,852.6 ) 2,605.7 Other income (expense): Interest expense (717.9 ) (7.3 ) 2.0 (723.2 ) -- -- (723.2 ) Other, net 4.0 0.6 (2.0 ) 2.6 (15.8 ) -- (13.2 ) Total other expense, net (713.9 ) (6.7 ) -- (720.6 ) (15.8 ) -- (736.4 ) Income before income taxes 1,858.4 2,035.1 (2,008.0 ) 1,885.5 1,836.4 (1,852.6 ) 1,869.3 Benefit from (provision for) income taxes (8.9 ) 5.4 -- (3.5 ) -- (0.9 ) (4.4 ) Net income 1,849.5 2,040.5 (2,008.0 ) 1,882.0 1,836.4 (1,853.5 ) 1,864.9 Ne t loss (income) at -- 0.8 (32.9 ) (32.1 ) -- 3.6 (28.5 ) Net income attributable to entity $ 1,849.5 $ 2,041.3 $ (2,040.9 ) $ 1,849.9 $ 1,836.4 $ (1,849.9 ) $ 1,836.4 Enterprise Products Partners L.P. Unaudited Condensed Consolidating Statement of Operations For the Nine Months Ended September 30, 2014 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 $ 25,190.1 $ 25,859.9 $ (13,289.1 ) $ 37,760.9 $ -- $ -- $ 37,760.9 Costs and expenses: Operating costs and expenses 24,516.6 23,707.6 (13,289.8 ) 34,934.4 -- -- 34,934.4 General and administrative costs 23.1 126.0 -- 149.1 1.8 -- 150.9 Total costs and expenses 24,539.7 23,833.6 (13,289.8 ) 35,083.5 1.8 -- 35,085.3 Equity in income of unconsolidated affiliates 2,169.5 256.1 (2,246.5 ) 179.1 2,129.4 (2,129.4 ) 179.1 Operating income 2,819.9 2,282.4 (2,245.8 ) 2,856.5 2,127.6 (2,129.4 ) 2,854.7 Other income (expense): Interest expense (678.6 ) (1.0 ) -- (679.6 ) -- -- (679.6 ) Other, net 0.7 (0.9 ) -- (0.2 ) -- -- (0.2 ) Total other expense, net (677.9 ) (1.9 ) -- (679.8 ) -- -- (679.8 ) Income before income taxes 2,142.0 2,280.5 (2,245.8 ) 2,176.7 2,127.6 (2,129.4 ) 2,174.9 Provision for income taxes (15.5 ) (5.8 ) 0.2 (21.1 ) -- (1.4 ) (22.5 ) Net income 2,126.5 2,274.7 (2,245.6 ) 2,155.6 2,127.6 (2,130.8 ) 2,152.4 Net income attributable to noncontrolling interests -- 0.2 (28.8 ) (28.6 ) -- 3.8 (24.8 ) Net income attributable to entity $ 2,126.5 $ 2,274.9 $ (2,274.4 ) $ 2,127.0 $ 2,127.6 $ (2,127.0 ) $ 2,127.6
Condensed Consolidating Statement of Comprehensive Income	Enterprise Products Partners L.P. Unaudited Condensed Consolidating Statement of Comprehensive Income For the Three Months Ended September 30, 2015 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 $ 676.0 $ 797.3 $ (763.9 ) $ 709.4 $ 697.2 $ (701.0 ) $ 705.6 Comprehen sive loss (income) attribu -- -- (9.7 ) (9.7 ) -- 1.3 (8.4 ) Comprehensive income attributable to entity $ 676.0 $ 797.3 $ (773.6 ) $ 699.7 $ 697.2 $ (699.7 ) $ 697.2 Enterprise Products Partners L.P. Unaudited Condensed Consolidating Statement of Comprehensive Income For the Three Months Ended September 30, 2014 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 $ 708.9 $ 825.2 $ (784.5 ) $ 749.6 $ 739.2 $ (741.5 ) $ 747.3 Comprehensive loss (income) attributable to noncontrolling interests -- 0.1 (9.5 ) (9.4 ) -- 1.3 (8.1 ) Comprehensive income attributable to entity $ 708.9 $ 825.3 $ (794.0 ) $ 740.2 $ 739.2 $ (740.2 ) $ 739.2 Enterprise Products Partners L.P. Unaudited Condensed Consolidating Statement of Comprehensive Income For the Nine Months Ended September 30, 2015 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 $ 1,869.9 $ 2,056.1 $ (2,033.2 ) $ 1,892.8 $ 1,847.3 $ (1,864.3 ) $ 1,875.8 Comp rehensive loss (income) attrib -- 0.8 (32.9 ) (32.1 ) -- 3.6 (28.5 ) Comprehensive income attributable to entity $ 1,869.9 $ 2,056.9 $ (2,066.1 ) $ 1,860.7 $ 1,847.3 $ (1,860.7 ) $ 1,847.3 Enterprise Products Partners L.P. Unaudited Condensed Consolidating Statement of Comprehensive Income For the Nine Months Ended September 30, 2014 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 $ 2,161.8 $ 2,292.2 $ (2,245.5 ) $ 2,208.5 $ 2,180.5 $ (2,183.7 ) $ 2,205.3 Comprehensive loss (income) attributable to noncontrolling interests -- 0.2 (28.8 ) (28.6 ) -- 3.8 (24.8 ) Comprehensive income attributable to entity $ 2,161.8 $ 2,292.4 $ (2,274.3 ) $ 2,179.9 $ 2,180.5 $ (2,179.9 ) $ 2,180.5
Condensed Consolidating Statement of Cash Flows	Enterprise Products Partners L.P. Unaudited Condensed Consolidating Statement of Cash Flows For the Nine Months Ended September 30, 2015 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 $ 1,849.5 $ 2,040.5 $ (2,008.0 ) $ 1,882.0 $ 1,836.4 $ (1,853.5 ) $ 1,864.9 Reconciliation of net income to net cash flows provided by operating activities: Depreciation, amortization and accretion 106.0 1,042.1 (0.4 ) 1,147.7 -- -- 1,147.7 Equity in income of unconsolidated affiliates (1,996.4 ) (314.5 ) 2,008.4 (302.5 ) (1,852.6 ) 1,852.6 (302.5 ) Distributions received from unconsolidated affiliates 1,705.4 227.1 (1,570.1 ) 362.4 2,241.1 (2,241.1 ) 362.4 Net effect of changes in operating accounts and other operating activities (52.9 ) (450.6 ) 9.3 (494.2 ) 12.0 0.9 (481.3 ) Net cash flows provided by operating activities 1,611.6 2,544.6 (1,560.8 ) 2,595.4 2,236.9 (2,241.1 ) 2,591.2 Investing activities: Capital expenditures, net of contributions in aid of construction costs (725.5 ) (1,893.6 ) -- (2,619.1 ) -- -- (2,619.1 ) Cash used for business combinations, net of cash received (1,058.4 ) 13.3 -- (1,045.1 ) -- -- (1,045.1 ) Proceeds from asset sales and insurance recoveries 1,532.1 5.2 -- 1,537.3 -- -- 1,537.3 Other investing activities (1,091.2 ) (43.5 ) 953.4 (181.3 ) (1,005.2 ) 1,005.2 (181.3 ) Cash used in investing activities (1,343.0 ) (1,918.6 ) 953.4 (2,308.2 ) (1,005.2 ) 1,005.2 (2,308.2 ) Financing activities: Borrowings under debt agreements 17,113.7 77.9 (77.9 ) 17,113.7 -- -- 17,113.7 Repayments of debt (16,139.2 ) -- -- (16,139.2 ) -- -- (16,139.2 ) Cash distributions paid to partners (2,241.1 ) (1,602.4 ) 1,602.4 (2,241.1 ) (2,185.1 ) 2,241.1 (2,185.1 ) Cash payments made in connection with DERs -- -- -- -- (5.6 ) -- (5.6 ) Cash distributions paid to noncontrolling interests -- (0.8 ) (32.4 ) (33.2 ) -- -- (33.2 ) Cash contributions from noncontrolling interests -- 37.8 (0.4 ) 37.4 -- -- 37.4 Net cash proceeds from issuance of common units -- -- -- -- 1,011.4 -- 1,011.4 Cash contributions from owners 1,005.2 875.1 (875.1 ) 1,005.2 -- (1,005.2 ) -- Other financing activities (23.9 ) -- -- (23.9 ) (52.4 ) -- (76.3 ) Cash used in financing activities (285.3 ) (612.4 ) 616.6 (281.1 ) (1,231.7 ) 1,235.9 (276.9 ) Net change in cash and cash equivalents (16.7 ) 13.6 9.2 6.1 -- -- 6.1 Cash and cash equivalents, January 1 18.7 70.4 (14.7 ) 74.4 -- -- 74.4 Cash and cash equivalents, September 30 $ 2.0 $ 84.0 $ (5.5 ) $ 80.5 $ -- $ -- $ 80.5 Enterprise Products Partners L.P. Unaudited Condensed Consolidating Statement of Cash Flows For the Nine Months Ended September 30, 2014 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 $ 2,126.5 $ 2,274.7 $ (2,245.6 ) $ 2,155.6 $ 2,127.6 $ (2,130.8 ) $ 2,152.4 Reconciliation of net income to net cash flows provided by operating activities: Depreciation, amortization and accretion 114.3 878.5 (0.4 ) 992.4 -- -- 992.4 Equity in income of unconsolidated affiliates (2,169.5 ) (256.1 ) 2,246.5 (179.1 ) (2,129.4 ) 2,129.4 (179.1 ) Distributions received from unconsolidated affiliates 3,475.8 229.0 (3,444.1 ) 260.7 2,007.4 (2,007.4 ) 260.7 Net effect of changes in operating accounts and other operating activities (764.6 ) 230.1 16.7 (517.8 ) (5.6 ) 1.4 (522.0 ) Net cash flows provided by operating activities 2,782.5 3,356.2 (3,426.9 ) 2,711.8 2,000.0 (2,007.4 ) 2,704.4 Investing activities: Capital expenditures, net of contributions in aid of construction costs (329.1 ) (1,530.4 ) -- (1,859.5 ) -- -- (1,859.5 ) Proceeds from asset sales and insurance recoveries 4.2 117.3 -- 121.5 -- -- 121.5 Other investing activities (2,059.3 ) (526.9 ) 2,056.1 (530.1 ) (300.7 ) 300.7 (530.1 ) Cash used in investing activities (2,384.2 ) (1,940.0 ) 2,056.1 (2,268.1 ) (300.7 ) 300.7 (2,268.1 ) Financing activities: Borrowings under debt agreements 7,167.5 -- -- 7,167.5 -- -- 7,167.5 Repayments of debt (4,856.3 ) -- -- (4,856.3 ) -- -- (4,856.3 ) Cash distributions paid to partners (2,007.4 ) (3,473.6 ) 3,473.6 (2,007.4 ) (1,948.2 ) 2,007.4 (1,948.2 ) Cash payments made in connection with DERs -- -- -- -- (2.4 ) -- (2.4 ) Cash distributions paid to noncontrolling interests -- -- (29.4 ) (29.4 ) -- -- (29.4 ) Cash contributions from noncontrolling interests -- -- 4.0 4.0 -- -- 4.0 Net cash proceeds from issuance of common units -- -- -- -- 304.9 -- 304.9 Cash contributions from owners 300.7 2,060.0 (2,060.0 ) 300.7 -- (300.7 ) -- Other financing activities (18.1 ) -- -- (18.1 ) (53.6 ) -- (71.7 ) Cash provided by (used in) financing activities 586.4 (1,413.6 ) 1,388.2 561.0 (1,699.3 ) 1,706.7 568.4 Net change in cash and cash equivalents 984.7 2.6 17.4 1,004.7 -- -- 1,004.7 Cash and cash equivalents, January 1 28.4 49.5 (21.0 ) 56.9 -- -- 56.9 Cash and cash equivalents, September 30 $ 1,013.1 $ 52.1 $ (3.6 ) $ 1,061.6 $ -- $ -- $ 1,061.6

Partnership Operations, Organ40

Partnership Operations, Organization and Basis for Presentation (Details) bbl in Millions, ft³ in Billions	9 Months Ended
	Sep. 30, 2015Segmentmibblft³	Dec. 31, 2014
Related Party Transaction [Line Items]
Number of miles of onshore and offshore pipelines | mi	49,000
Number of barrels of storage capacity | bbl	225
Number of cubic feet of storage capacity | ft³	14
Number of reportable segments	5
Limited partners ownership interest (in hundredths)	100.00%
EPCO and its privately held affiliates [Member]
Related Party Transaction [Line Items]
Percentage of Total Units Outstanding (in hundredths)	33.70%
Oiltanking Partners L.P. [Member]
Business Acquisition [Line Items]
Limited partner interests acquired (in hundredths)		65.90%

General Accounting and Disclo41

General Accounting and Disclosure Matters (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Restricted cash [Abstract]
Restricted cash	$ 46.2	$ 0

Equity-based Awards (Details)

Equity-based Awards (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Equity-based compensation expense [Abstract]
Total compensation expense	$ 23.4	$ 21.7	$ 73.5	$ 62
Equity-classified awards [Member] | Restricted Common Unit Awards [Member]
Equity-based compensation expense [Abstract]
Total compensation expense	3.1	8.7	13.1	29.3
Equity-classified awards [Member] | Phantom Unit Awards [Member]
Equity-based compensation expense [Abstract]
Total compensation expense	20.3	12.9	60.2	32.3
Liability-classified awards [Member]
Equity-based compensation expense [Abstract]
Total compensation expense	$ 0	$ 0.1	$ 0.2	$ 0.4
Long-Term Incentive Plan (2008) [Member]
Equity-based compensation expense [Abstract]
Maximum number of common units that may be issued as awards (in units)	30,000,000		30,000,000
Incremental number of units to be authorized annually (in units)			5,000,000
Maximum number of additional units to be authorized for issuance (in units)			70,000,000
Remaining number of common units available to be issued as awards (in units)	16,277,823		16,277,823
Long Term Incentive Plan (1998) [Member]
Equity-based compensation expense [Abstract]
Maximum number of common units that may be issued as awards (in units)	14,000,000		14,000,000
Remaining number of common units available to be issued as awards (in units)	3,040,506		3,040,506

Equity-based Awards, Restricted

Equity-based Awards, Restricted Unit Awards (Details) - Restricted Common Unit Awards [Member] - USD ($) $ / shares in Units, $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting rate of restricted common unit awards (in hundredths)		25.00%		25.00%
Summary of awards activity, equity instruments other than options [Roll Forward]
Beginning of period (in units)				4,229,790
Vested (in units)				(1,997,194)
Forfeited (in units)				(157,750)
End of period (in units)		2,074,846		2,074,846
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)	[1]			$ 26.96
Vested weighted-average grant date fair value per unit (in dollars per unit)	[1]			25.99
Forfeited weighted-average grant date fair value per unit (in dollars per unit)	[1]			27.64
Weighted-average grant date fair value per unit, at end of period (in dollars per unit)	[1]	$ 27.85		$ 27.85
Summary of awards activity, equity instruments other than options, additional disclosures [Abstract]
Cash distributions paid to restricted common unitholders		$ 0.8	$ 1.6	$ 3.2	$ 5.7
Total intrinsic value of our restricted common unit awards that vested during period		1.5	$ 1.3	66.9	$ 85.4
Unrecognized Compensation Expense [Abstract]
Unrecognized compensation cost		11.5		$ 11.5
Recognition period for total unrecognized compensation cost				1 year 1 month 6 days
Enterprise [Member]
Unrecognized Compensation Expense [Abstract]
Unrecognized compensation cost		$ 9.6		$ 9.6
[1]	Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued.

Equity-based Awards, Phantom Un

Equity-based Awards, Phantom Unit Awards (Details) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Summary of awards activity, equity instruments other than options, additional disclosures [Abstract]
Cash payments made in connection with DERs				$ 5.6	$ 2.4
Phantom Unit Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting rate of phantom unit awards (in hundredths)		25.00%		25.00%
Summary of awards activity, equity instruments other than options [Roll Forward]
Beginning of period (in units)				3,342,390
Granted (in units)	[1]			3,491,040
Vested (in units)				(933,890)
Forfeited (in units)				(275,356)
End of period (in units)		5,624,184		5,624,184
Phantom 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)	[2]			$ 33.13
Granted weighted-average grant date fair value per unit (in dollars per unit)	[1],[2]			33.97
Vested weighted-average grant date fair value per unit (in dollars per unit)	[2]			33.13
Forfeited weighted-average grant date fair value per unit (in dollars per unit)	[2]			33.51
Weighted-average grant date fair value per unit, at end of period (in dollars per unit)	[2]	$ 33.63		$ 33.63
Summary of awards activity, equity instruments other than options, additional disclosures [Abstract]
Aggregate grant date fair value				$ 118.6
Estimated forfeiture rate (in hundredths)				3.50%
Cash payments made in connection with DERs		$ 2.2	$ 1.2	$ 5.6	2.4
Total intrinsic value of phantom unit awards that vested during period		2.3	$ 0.1	31	$ 1.3
Unrecognized Compensation Expense [Abstract]
Unrecognized compensation cost		100.4		$ 100.4
Recognition period for total unrecognized compensation cost				2 years
Phantom 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)				$ 27.31
Phantom 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)				$ 34.40
Phantom Unit Awards [Member] | Enterprise [Member]
Unrecognized Compensation Expense [Abstract]
Unrecognized compensation cost		$ 91.7		$ 91.7
[1]	The aggregate grant date fair value of phantom unit awards issued during 2015 was $118.6 million based on a grant date market price of our common units ranging from $27.31 to $34.40 per unit. An estimated annual forfeiture rate of 3.5% was applied to these awards.
[2]	Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued.

Equity-based Awards, Unit Optio

Equity-based Awards, Unit Option Awards (Details) - Unit Option Awards [Member] - USD ($) $ / shares in Units, $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period				4 years
Summary of awards activity, options [Roll Forward]
Beginning of period (in units)	[1]			1,270,000
Exercised (in units)				(1,080,000)
End of period (in units)	[1]	190,000		190,000
Options outstanding, weighted-average strike price [Roll Forward]
Weighted average strike price, beginning of period (in dollars per unit)				$ 16.14
Weighted average strike price, exercised (in dollars per unit)				16.14
Weighted average strike price, end of period (in dollars per unit)		$ 16.14		$ 16.14
Weighted average remaining contractual term				3 months 18 days
Aggregate intrinsic value	[2]	$ 1.7		$ 1.7
Total intrinsic value of unit option awards exercised during period		0.2	$ 0	19.8	$ 57.5
Cash received from EPCO in connection with the exercise of unit option awards		0.2	0	11.5	33.4
Unit option award-related cash reimbursements to EPCO		$ 0.2	$ 0	$ 19.8	$ 57.5
[1]	All of the unit option awards outstanding at September 30, 2015 were exercisable. None of the unit option awards outstanding at December 31, 2014 were exercisable.
[2]	Aggregate intrinsic value reflects fully vested unit option awards at the dates indicated.

Derivative Instruments, Hedgi46

Derivative Instruments, Hedging Activities and Fair Value Measurements (Details) bbl in Millions, $ in Millions, ft³ in Billions	9 Months Ended
	Sep. 30, 2015USD ($)Contractbblft³
Interest rate derivatives [Member] | Derivatives in fair value hedging relationships [Member] | EPO Senior Notes OO [Member]
Derivative [Line Items]
Number of Derivatives Outstanding | Contract	10
Type of Derivatives Outstanding	fixed-to-floating swaps
Notional Amount | $	$ 750
Period of Hedge	5/2015 to 5/2018
Rate Swap, fixed rate (in hundredths)	1.65%
Rate Swap, floating rate (in hundredths)	0.79%
Commodity derivatives [Member] | Derivatives in cash flow hedging relationships [Member] | Natural gas processing: Forecasted natural gas purchases for plant thermal reduction (PTR) [Member]
Derivative [Line Items]
Current Volume | ft³	4.9	[1],[2]
Commodity derivatives [Member] | Derivatives in cash flow hedging relationships [Member] | Natural gas processing: Forecasted sales of NGLs [Member]
Derivative [Line Items]
Current Volume	1.1	[1],[2],[3]
Forecasted NGL sales designated as normal sales agreements	0.7
Commodity derivatives [Member] | Derivatives in cash flow hedging relationships [Member] | Octane enhancement: Forecasted purchases of NGLs [Member]
Derivative [Line Items]
Current Volume	0.1	[1],[2]
Commodity derivatives [Member] | Derivatives in cash flow hedging relationships [Member] | Octane enhancement: Forecasted sales of octane enhancement products [Member]
Derivative [Line Items]
Current Volume	0.5	[1],[2]
Commodity derivatives [Member] | Derivatives in cash flow hedging relationships [Member] | Natural gas marketing: Forecasted purchases of natural gas for fuel [Member]
Derivative [Line Items]
Current Volume | ft³	6.4	[1],[2]
Commodity derivatives [Member] | Derivatives in cash flow hedging relationships [Member] | Natural gas marketing: Forecasted sales of natural gas [Member]
Derivative [Line Items]
Current Volume | ft³	0.1	[1],[2]
Commodity derivatives [Member] | Derivatives in cash flow hedging relationships [Member] | NGL marketing: Forecasted purchases of NGLs and related hydrocarbon products [Member]
Derivative [Line Items]
Current Volume	34.6	[1],[2]
Long Term Volume	0.5	[1],[2]
Commodity derivatives [Member] | Derivatives in cash flow hedging relationships [Member] | NGL marketing: Forecasted sales of NGLs and related hydrocarbon products [Member]
Derivative [Line Items]
Current Volume	49.8	[1],[2]
Commodity derivatives [Member] | Derivatives in cash flow hedging relationships [Member] | Refined products marketing: Forecasted purchases of refined products [Member]
Derivative [Line Items]
Current Volume	0.4	[1],[2]
Commodity derivatives [Member] | Derivatives in cash flow hedging relationships [Member] | Refined products marketing: Forecasted sales of refined products [Member]
Derivative [Line Items]
Current Volume	0.7	[1],[2]
Commodity derivatives [Member] | Derivatives in cash flow hedging relationships [Member] | Crude oil marketing: Forecasted purchases of crude oil [Member]
Derivative [Line Items]
Current Volume	9	[1],[2]
Long Term Volume	1.6	[1],[2]
Commodity derivatives [Member] | Derivatives in cash flow hedging relationships [Member] | Crude oil marketing: Forecasted sales of crude oil [Member]
Derivative [Line Items]
Current Volume	11.9	[1],[2]
Long Term Volume	1.6	[1],[2]
Commodity derivatives [Member] | Derivatives in fair value hedging relationships [Member] | Natural gas marketing: Natural gas storage inventory management activities [Member]
Derivative [Line Items]
Current Volume | ft³	10.2	[1],[2]
Commodity derivatives [Member] | Derivatives in fair value hedging relationships [Member] | Refined products marketing: Refined products inventory management activities [Member]
Derivative [Line Items]
Current Volume	0.2	[1],[2]
Commodity derivatives [Member] | Derivatives in mark-to-market relationships [Member] | Natural gas risk management activities [Member]
Derivative [Line Items]
Current Volume | ft³	65.9	[1],[2],[4],[5]
Long Term Volume | ft³	9.6	[1],[2],[4],[5]
Current natural gas hedging volumes designated as an index plus or minus a discount | ft³	38.7
Long-term natural gas hedging volumes designated as an index plus or minus a discount | ft³	0.9
Commodity derivatives [Member] | Derivatives in mark-to-market relationships [Member] | NGL risk management activities [Member]
Derivative [Line Items]
Current Volume	14.9	[1],[2],[5]
Commodity derivatives [Member] | Derivatives in mark-to-market relationships [Member] | Crude oil risk management activities [Member]
Derivative [Line Items]
Current Volume	5.8	[1],[2],[5]
Long Term Volume	0.4	[1],[2],[5]
[1]	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 2017, April 2016 and March 2018, respectively.
[2]	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.
[3]	Forecasted sales of NGL volumes under natural gas processing exclude 0.7 MMBbls of additional hedges executed under contracts that have been designated as normal sales agreements.
[4]	Current and long-term volumes include 38.7 Bcf and 0.9 Bcf, respectively, of physical derivative instruments that are predominantly priced at a marked-based index plus a premium or minus a discount related to location differences.
[5]	Reflects the use of derivative instruments to manage risks associated with transportation, processing and storage assets.

Derivative Instruments, Hedgi47

Derivative Instruments, Hedging Activities and Fair Value Measurements, Derivative Fair Value Amounts (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Interest rate derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	$ 7.6
Commodity derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	242.8	$ 226.6
Liability Derivatives	197.1	147.4
Derivatives designated as hedging instruments [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	232.8	217.9
Liability Derivatives	186.7	145.3
Derivatives designated as hedging instruments [Member] | Interest rate derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	7.6	0
Liability Derivatives	0	0
Derivatives designated as hedging instruments [Member] | Interest rate derivatives [Member] | Current assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	7.4	0
Derivatives designated as hedging instruments [Member] | Interest rate derivatives [Member] | Other assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	0.2	0
Derivatives designated as hedging instruments [Member] | Interest rate derivatives [Member] | Other current liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	0	0
Derivatives designated as hedging instruments [Member] | Interest rate derivatives [Member] | Other liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	0	0
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	225.2	217.9
Liability Derivatives	186.7	145.3
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member] | Current assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	216.9	217.9
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member] | Other assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	8.3	0
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member] | Other current liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	178.5	145.3
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member] | Other liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	8.2	0
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	17.6	8.7
Liability Derivatives	10.4	2.1
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Current assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	17.5	8.1
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Other assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	0.1	0.6
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Other current liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	9.4	0.7
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Other liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	$ 1	$ 1.4

Derivative Instruments, Hedgi48

Derivative Instruments, Hedging Activities and Fair Value Measurements, Asset Balance Sheet Offsetting (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Interest rate derivatives [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	$ 7.6
Gross Amounts Offset in the Balance Sheet	0
Amounts of Assets Presented in the Balance Sheet	7.6
Financial Instruments	0
Cash Collateral Received	0
Cash Collateral Paid	0
Amounts That Would Have Been Presented On Net Basis	7.6
Commodity derivatives [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	242.8	$ 226.6
Gross Amounts Offset in the Balance Sheet	0	0
Amounts of Assets Presented in the Balance Sheet	242.8	226.6
Financial Instruments	(180.3)	(147.3)
Cash Collateral Received	(38.2)	(23.9)
Cash Collateral Paid	(9.6)	0
Amounts That Would Have Been Presented On Net Basis	$ 14.7	$ 55.4

Derivative Instruments, Hedgi49

Derivative Instruments, Hedging Activities and Fair Value Measurements, Liability Balance Sheet Offsetting (Details) - Commodity derivatives [Member] - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	$ 197.1	$ 147.4
Gross Amounts Offset in the Balance Sheet	0	0
Amounts of Liabilities Presented in the Balance Sheet	197.1	147.4
Financial Instruments	(180.3)	(147.3)
Cash Collateral Paid	0	0
Amounts That Would Have Been Presented On Net Basis	$ 16.8	$ 0.1

Derivative Instruments, Hedgi50

Derivative Instruments, Hedging Activities and Fair Value Measurements, Gains and Losses on Derivative Instruments and Related Hedged Items (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Derivatives in fair value hedging relationships [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Derivative		$ 9.5	$ (4.4)	$ 9.1	$ (8.9)
Gain (Loss) Recognized in Income on Hedged Item		(8.2)	4.9	2.2	7.9
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 Derivative		5.9	(4.1)	5.1	(9.5)
Gain (Loss) Recognized in Income on Hedged Item		(5.7)	3.9	(5.2)	9.3
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 Derivative		3.6	(0.3)	4	0.6
Gain (Loss) Recognized in Income on Hedged Item		(2.5)	1	7.4	(1.4)
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)		85.8	58.1	112.3	16.1
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income (Effective Portion)		37.9	10	101.8	(36.8)
Gain (Loss) Recognized in Income on Derivative (Ineffective Portion)		(3.5)	0	(3.1)	0
Derivatives in cash flow hedging relationships [Member] | Interest rate derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Accumulated other comprehensive loss related to interest rate derivative instruments expected to be reclassified to earnings in interest expense over the next twelve months		(36.8)		(36.8)
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)		(8.9)	(8)	(26.3)	(23.9)
Derivatives in cash flow hedging relationships [Member] | Commodity derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Net accumulated other comprehensive income (loss) related to commodity derivative instruments expected to be reclassified to earnings over the next twelve months		54.1		54.1
Accumulated other comprehensive income (loss) related to commodity derivative instruments expected to be reclassified to revenue over the next twelve months		55.7		55.7
Accumulated other comprehensive income (loss) related to commodity derivative instruments expected to be reclassified to operating costs and expenses over the next twelve months		(1.6)		(1.6)
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)	[1]	87.4	58.8	113.9	15.2
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income (Effective Portion)		46.8	17.8	128.6	(14.5)
Gain (Loss) Recognized in Income on Derivative (Ineffective Portion)		(3.5)	0.1	(3.1)	0
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)	[1]	(1.6)	(0.7)	(1.6)	0.9
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income (Effective Portion)		0	0.2	(0.5)	1.6
Gain (Loss) Recognized in Income on Derivative (Ineffective Portion)		0	(0.1)	0	0
Derivatives not designated as hedging instruments [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Derivative		(0.3)	0.8	3.9	(26.9)
Derivatives not designated as hedging instruments [Member] | Interest rate derivatives [Member] | Location - Interest expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Derivative		0	0	0	(0.1)
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Location - Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Derivative		0	0.8	3.9	(26.8)
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Location - Operating costs and expenses [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Derivative		$ (0.3)	$ 0	$ 0	$ 0
[1]	The fair value of these derivative instruments will be reclassified to their respective locations on the Unaudited Condensed Statement of Consolidated Operations upon settlement of the underlying derivative transactions, as appropriate.

Derivative Instruments, Hedgi51

Derivative Instruments, Hedging Activities and Fair Value Measurements, Recurring Fair Value Measurements (Details) - USD ($) $ in Millions		3 Months Ended						9 Months Ended
		Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Total gains (losses) included in:
Unrealized gain (loss) recognized as a component of net income related to financial assets and liabilities								$ 7.7	$ 3.8
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Reconciliation of changes in the fair value of Level 3 financial assets and liabilities [Roll Forward]
Financial asset (liability) balance, net, beginning of period		$ (232.8)	$ (221.6)	$ (219.3)	$ 2.6	$ 7.7	$ 3.2	(219.3)	3.2
Total gains (losses) included in:
Other comprehensive income		(15.5)	(1)	(1.5)	(2.5)	0	0
Settlements		0.3	0.2	(0.5)	0.1	(1.8)	(0.1)
Transfers out of Level 3		1.1	1.5	0.1	0	0	0
Financial asset (liability) balance, net, end of period		(251.5)	(232.8)	(221.6)	(0.7)	2.6	7.7	(251.5)	(0.7)
Unrealized gain (loss) recognized as a component of net income related to financial assets and liabilities		0			0.8			(1.1)	$ 1.3
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Location - Revenue [Member]
Total gains (losses) included in:
Net income	[1]	(0.3)	(0.4)	$ (0.4)	(0.9)	(3.3)	$ 4.6
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Location - Other Expense [Member]
Total gains (losses) included in:
Net income		(4.3)	$ (11.5)		$ 0	$ 0
Fair Value, Measurements, Recurring [Member] | Fair Value [Member]
Financial assets [Abstract]
Interest rate derivatives		7.6						7.6
Commodity derivatives		242.8						242.8		$ 226.6
Total		250.4						250.4
Financial liabilities [Abstract]
Liquidity Option Agreement		235.5						235.5		219.7
Commodity derivatives		197.1						197.1		147.4
Total		432.6						432.6		367.1
Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 1 [Member]
Financial assets [Abstract]
Interest rate derivatives		0						0
Commodity derivatives		84.1						84.1		37.8
Total		84.1						84.1
Financial liabilities [Abstract]
Liquidity Option Agreement		0						0		0
Commodity derivatives		37.4						37.4		13.8
Total		37.4						37.4		13.8
Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 2 [Member]
Financial assets [Abstract]
Interest rate derivatives		7.6						7.6
Commodity derivatives		157.7						157.7		187.8
Total		165.3						165.3
Financial liabilities [Abstract]
Liquidity Option Agreement		0						0		0
Commodity derivatives		142.7						142.7		133
Total		142.7						142.7		133
Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 3 [Member]
Financial assets [Abstract]
Interest rate derivatives		0						0
Commodity derivatives		1						1		1
Total		1						1
Financial liabilities [Abstract]
Liquidity Option Agreement		235.5						235.5		219.7
Commodity derivatives		17						17		0.6
Total		$ 252.5						$ 252.5		$ 220.3
[1]	There were $1.1 million of unrealized losses included in these amounts for the nine months ended September 30, 2015. There were unrealized gains of $0.8 million and $1.3 million included in these amounts for the three and nine months ended September 30, 2014, respectively.

Derivative Instruments, Hedgi52

Derivative Instruments, Hedging Activities and Fair Value Measurements, Level 3 Recurring Valuation Techniques (Details) - Fair Value [Member] $ in Millions	9 Months Ended
	Sep. 30, 2015USD ($)$ / gal$ / bbl	Dec. 31, 2014USD ($)
Asset commodity derivatives - Crude oil [Member] | Liability commodity derivatives - Crude oil [Member] | Level 3 [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair Value Measurements, Valuation Techniques	Discounted cash flow
Input description	Forward commodity prices
Asset commodity derivatives - Crude oil [Member] | Liability commodity derivatives - Crude oil [Member] | Level 3 [Member] | Minimum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, forward commodity price (in dollars per unit) | $ / bbl	44.47
Asset commodity derivatives - Crude oil [Member] | Liability commodity derivatives - Crude oil [Member] | Level 3 [Member] | Maximum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, forward commodity price (in dollars per unit) | $ / bbl	50.74
Asset commodity derivatives - Propane [Member] | Liability commodity derivatives - Propane [Member] | Level 3 [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair Value Measurements, Valuation Techniques	Discounted cash flow
Input description	Forward commodity prices
Asset commodity derivatives - Propane [Member] | Liability commodity derivatives - Propane [Member] | Level 3 [Member] | Maximum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, forward commodity price (in dollars per unit) | $ / gal	0.50
Asset commodity derivatives - Natural gasoline [Member] | Liability commodity derivatives - Natural gasoline [Member] | Level 3 [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair Value Measurements, Valuation Techniques	Discounted cash flow
Input description	Forward commodity prices
Asset commodity derivatives - Natural gasoline [Member] | Liability commodity derivatives - Natural gasoline [Member] | Level 3 [Member] | Minimum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, forward commodity price (in dollars per unit) | $ / gal	0.93
Asset commodity derivatives - Natural gasoline [Member] | Liability commodity derivatives - Natural gasoline [Member] | Level 3 [Member] | Maximum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, forward commodity price (in dollars per unit) | $ / gal	1
Fair Value, Measurements, Recurring [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Commodity asset derivatives	$ 242.8	$ 226.6
Commodity liability derivatives	197.1	147.4
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Commodity asset derivatives	1	1
Commodity liability derivatives	17	$ 0.6
Fair Value, Measurements, Recurring [Member] | Liability commodity derivatives - Crude oil [Member] | Level 3 [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Commodity liability derivatives	1.3
Fair Value, Measurements, Recurring [Member] | Liability commodity derivatives - Propane [Member] | Level 3 [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Commodity liability derivatives	0.1
Fair Value, Measurements, Recurring [Member] | Liability commodity derivatives - Natural gasoline [Member] | Level 3 [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Commodity liability derivatives	15.6
Fair Value, Measurements, Recurring [Member] | Asset commodity derivatives - Crude oil [Member] | Level 3 [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Commodity asset derivatives	0.7
Fair Value, Measurements, Recurring [Member] | Asset commodity derivatives - Propane [Member] | Level 3 [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Commodity asset derivatives	0
Fair Value, Measurements, Recurring [Member] | Asset commodity derivatives - Natural gasoline [Member] | Level 3 [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Commodity asset derivatives	$ 0.3

Derivative Instruments, Hedgi53

Derivative Instruments, Hedging Activities and Fair Value Measurements, Nonrecurring Fair Value Measurements (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Asset Impairment Charges [Abstract]
Non-cash asset impairment charges		$ 26.8	$ 5.7	$ 139.1	$ 18.2
Impairment of long-lived assets disposed of other than by sale				69.9	11.7
Impairment of long-lived assets held for sale				14.2	6.5
Impairment of long-lived assets disposed of by sale	[1]			55
Offshore Business [Member]
Asset Impairment Charges [Abstract]
Impairment of long-lived assets disposed of by sale				54.8
NGL Pipelines and Services [Member]
Asset Impairment Charges [Abstract]
Non-cash asset impairment charges		14.6	1.2	20.6	6.6
Crude Oil Pipelines & Services [Member]
Asset Impairment Charges [Abstract]
Non-cash asset impairment charges		0	0.4	25.9	2.2
Natural Gas Pipelines & Services [Member]
Asset Impairment Charges [Abstract]
Non-cash asset impairment charges		0	0.4	21.5	0.7
Petrochemical & Refined Products Services [Member]
Asset Impairment Charges [Abstract]
Non-cash asset impairment charges		12.2	3.7	12.6	8.7
Offshore Pipelines And Services [Member]
Asset Impairment Charges [Abstract]
Non-cash asset impairment charges		0	0	58.5	0
Fair Value, Measurements, Nonrecurring [Member] | Long-lived Assets Disposed of Other Than By Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value		0.4	0	0.4	0
Fair Value, Measurements, Nonrecurring [Member] | Long-lived Assets Held For Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value		34.2	1.1	34.2	1.1
Fair Value, Measurements, Nonrecurring [Member] | Long-lived Assets Disposed of By Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value		0		0
Fair Value, Measurements, Nonrecurring [Member] | Level 1 [Member] | Long-lived Assets Disposed of Other Than By Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value		0	0	0	0
Fair Value, Measurements, Nonrecurring [Member] | Level 1 [Member] | Long-lived Assets Held For Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value		0	0	0	0
Fair Value, Measurements, Nonrecurring [Member] | Level 1 [Member] | Long-lived Assets Disposed of By Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value		0		0
Fair Value, Measurements, Nonrecurring [Member] | Level 2 [Member] | Long-lived Assets Disposed of Other Than By Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value		0	0	0	0
Fair Value, Measurements, Nonrecurring [Member] | Level 2 [Member] | Long-lived Assets Held For Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value		0	0	0	0
Fair Value, Measurements, Nonrecurring [Member] | Level 2 [Member] | Long-lived Assets Disposed of By Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value		0		0
Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Long-lived Assets Disposed of Other Than By Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value		0.4	0	0.4	0
Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Long-lived Assets Held For Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value		34.2	$ 1.1	34.2	$ 1.1
Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Long-lived Assets Disposed of By Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value		$ 0		$ 0
[1]	Primarily represents the impairment charge recorded in second quarter of 2015 upon reclassification of our Offshore Business to held for sale status.

Derivative Instruments, Hedgi54

Derivative Instruments, Hedging Activities and Fair Value Measurements, Other Fair Value Measurements (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Carrying Value [Member]
Financial Liabilities: [Abstract]
Fixed Rate Debt Principal Amount Fair Value Disclosure	$ 20,880	$ 20,480
Level 2 [Member] | Fair Value [Member]
Financial Liabilities: [Abstract]
Fixed Rate Debt Principal Amount Fair Value Disclosure	$ 20,770	$ 22,160

Inventories (Details)

Inventories (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Available-for-Sale Inventory by Product Type [Abstract]
NGLs		$ 740.5		$ 740.5		$ 579.1
Petrochemicals and refined products		158		158		295.6
Crude oil		152.2		152.2		97.8
Natural gas		34.7		34.7		41.7
Total		1,085.4		1,085.4		$ 1,014.2
Summary of cost of sales and lower of cost or market adjustments [Abstract]
Cost of sales	[1]	4,419.9	$ 10,455.1	15,355.9	$ 32,213.1
Lower of cost or market adjustments		$ 2.1	$ 6.7	$ 6.1	$ 14.6
[1]	Cost of sales is a component of "Operating costs and expenses" as presented on our Unaudited Condensed Statements of Consolidated Operations. Fluctuations in these amounts are primarily due to changes in energy commodity prices and sales volumes associated with our marketing activities.

Property, Plant and Equipment56

Property, Plant and Equipment (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Property, plant and equipment and accumulated depreciation [Abstract]
Total historical cost of property, plant and equipment		$ 39,524.8		$ 39,524.8		$ 38,046.7
Less accumulated depreciation		8,310.7		8,310.7		8,165.1
Property, plant and equipment, net		31,214.1		31,214.1		29,881.6
Summary of depreciation expense and capitalized interest [Abstract]
Depreciation expense	[1]	286.2	$ 283.2	870.1	$ 822.1
Capitalized interest	[2]	40.3	$ 17.2	105.6	$ 53.4
Asset Retirement Obligations [Roll Forward]
Balance at beginning of period				98.3
Liabilities incurred				2.7
Liabilities settled				(5.9)
Revisions in estimated cash flows				49
Accretion expense				4.2
AROs related to Offshore Business sold in July 2015				(91.1)
Balance at end of period		57.2		57.2
Capitalized costs, asset retirement costs		17.8		17.8		31.3
Matagorda Gathering System [Member]
Asset Retirement Obligations [Roll Forward]
Revisions in estimated cash flows				39.5
Plants, pipelines and facilities [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Total historical cost of property, plant and equipment	[3]	31,686.3		$ 31,686.3		30,834.9
Plants, pipelines and facilities [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life	[3],[4]			3 years
Plants, pipelines and facilities [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life	[3],[4]			45 years
Underground and other storage facilities [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Total historical cost of property, plant and equipment	[5]	2,847.7		$ 2,847.7		2,584.2
Underground and other storage facilities [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life	[5],[6]			5 years
Underground and other storage facilities [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life	[5],[6]			40 years
Platforms and facilities [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Total historical cost of property, plant and equipment	[7]	0		$ 0		659.7
Platforms and facilities [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life	[7]			20 years
Platforms and facilities [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life	[7]			31 years
Transportation equipment [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Total historical cost of property, plant and equipment	[8]	164.8		$ 164.8		154.2
Transportation equipment [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life	[8]			3 years
Transportation equipment [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life	[8]			10 years
Marine vessels [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Total historical cost of property, plant and equipment	[9]	787.5		$ 787.5		796.4
Marine vessels [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life	[9]			15 years
Marine vessels [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life	[9]			30 years
Land [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Total historical cost of property, plant and equipment		261.3		$ 261.3		262.6
Construction in progress [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Total historical cost of property, plant and equipment		$ 3,777.2		$ 3,777.2		$ 2,754.7
Processing plants [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life				20 years
Processing plants [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life				35 years
Pipelines and related equipment [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life				5 years
Pipelines and related equipment [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life				45 years
Terminal facilities [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life				10 years
Terminal facilities [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life				35 years
Office furniture and equipment [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life				3 years
Office furniture and equipment [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life				20 years
Buildings [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life				20 years
Buildings [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life				40 years
Laboratory and shop equipment [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life				5 years
Laboratory and shop equipment [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life				35 years
Underground storage facilities [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life				5 years
Underground storage facilities [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life				35 years
Storage tanks [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life				10 years
Storage tanks [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life				40 years
Water wells [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life				5 years
Water wells [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life				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 costs incurred on funds used to construct property, plant and equipment while the asset is in its construction phase. 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. When capitalized interest is recorded, it reduces interest expense from what it would be otherwise.
[3]	Plants, pipelines and facilities 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 included offshore platforms and related facilities and other associated assets located in the Gulf of Mexico prior to the sale of our Offshore Business (see below).
[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.

Property, Plant and Equipment,

Property, Plant and Equipment, Sale of Offshore Business (Details) $ in Millions		3 Months Ended		6 Months Ended	9 Months Ended		12 Months Ended
		Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)	Jun. 30, 2015USD ($)	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)	Dec. 31, 2014	Jul. 24, 2015USD ($)
Sale of Offshore Business [Abstract]
Non-cash asset impairment charge	[1]				$ 55
Summary of depreciation expense and capitalized interest [Abstract]
Depreciation expense	[2]	$ 286.2	$ 283.2		$ 870.1	$ 822.1
Offshore Pipelines And Services [Member]
Sale of Offshore Business [Abstract]
Percentage of segment assets (in hundredths)				0.041			0.043
Percentage of gross operating margin (in hundredths)				0.034			0.031
Offshore Business [Member]
Sale of Offshore Business [Abstract]
Description of assets sold					As of December 31, 2014, our Offshore Business included approximately 2,350 miles of offshore natural gas and crude oil pipelines and six offshore hub platforms.
Cash consideration received								$ 1,530
Non-cash asset impairment charge					$ 54.8
Loss on sale					12.6
Sale of Offshore Business:
Net assets of Offshore Business before impairment charge				$ 1,590
Current assets				26.9
Property, plant and equipment, net				1,140
Investments in unconsolidated affiliates				482.4
Intangible assets, net				37.1
Goodwill				82
Total liabilities				116.4
Noncontrolling interests in assets held for sale (See Note 6)				62.2
Fair value of Offshore Business based on estimated transaction price				$ 1,530
Offshore Business [Member] | Offshore Business [Member]
Summary of depreciation expense and capitalized interest [Abstract]
Depreciation expense			$ 21.5		$ 40.1	$ 62.3
[1]	Primarily represents the impairment charge recorded in second quarter of 2015 upon reclassification of our Offshore Business to held for sale status.
[2]	Depreciation expense is a component of "Costs and expenses" as presented on our Unaudited Condensed Statements of Consolidated Operations.

Investments in Unconsolidated58

Investments in Unconsolidated Affiliates (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Jun. 30, 2015	Dec. 31, 2014
Schedule of Equity Method Investments [Line Items]
Total investments in unconsolidated affiliates		$ 2,625.3		$ 2,625.3			$ 3,042
Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]
Equity in income of unconsolidated affiliates		103.1	$ 72.3	302.5	$ 179.1
Unamortized excess cost amounts by business segment [Abstract]
Unamortized excess cost amounts		48.9		48.9			59.6
Equity method investment amortization of excess cost		0.6	0.7	4.5	2.3
NGL Pipelines & Services [Member]
Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]
Equity in income of unconsolidated affiliates		18.9	11.7	43	19.2
Unamortized excess cost amounts by business segment [Abstract]
Unamortized excess cost amounts		25.6		25.6			26.5
Equity method investment amortization of excess cost		$ 0.3	0.2	$ 0.9	0.9
NGL Pipelines & Services [Member] | Venice Energy Service Company, L.L.C. [Member]
Schedule of Equity Method Investments [Line Items]
Ownership Interest (in hundredths)		13.10%		13.10%
Total investments in unconsolidated affiliates		$ 26.4		$ 26.4			27.7
NGL Pipelines & Services [Member] | K/D/S Promix, L.L.C. [Member]
Schedule of Equity Method Investments [Line Items]
Ownership Interest (in hundredths)		50.00%		50.00%
Total investments in unconsolidated affiliates		$ 42.8		$ 42.8			38.5
NGL Pipelines & Services [Member] | Baton Rouge Fractionators LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership Interest (in hundredths)		32.20%		32.20%
Total investments in unconsolidated affiliates		$ 18.4		$ 18.4			18.8
NGL Pipelines & Services [Member] | Skelly-Belvieu Pipeline Company, L.L.C. [Member]
Schedule of Equity Method Investments [Line Items]
Ownership Interest (in hundredths)		50.00%		50.00%
Total investments in unconsolidated affiliates		$ 40.3		$ 40.3			40.1
NGL Pipelines & Services [Member] | Texas Express Pipeline LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership Interest (in hundredths)		35.00%		35.00%
Total investments in unconsolidated affiliates		$ 343.4		$ 343.4			349.3
NGL Pipelines & Services [Member] | Texas Express Gathering LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership Interest (in hundredths)		45.00%		45.00%
Total investments in unconsolidated affiliates		$ 37.2		$ 37.2			37.9
NGL Pipelines & Services [Member] | Front Range Pipeline LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership Interest (in hundredths)		33.30%		33.30%
Total investments in unconsolidated affiliates		$ 171.7		$ 171.7			170
NGL Pipelines & Services [Member] | Delaware Basin Gas Processing LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership Interest (in hundredths)		50.00%		50.00%
Total investments in unconsolidated affiliates	[1]	$ 28.7		$ 28.7			0
Crude Oil Pipelines & Services [Member]
Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]
Equity in income of unconsolidated affiliates		81.2	46.8	220.5	131.7
Unamortized excess cost amounts by business segment [Abstract]
Unamortized excess cost amounts		20.9		20.9			21.7
Equity method investment amortization of excess cost		$ 0.3	0.2	$ 0.8	0.5
Crude Oil Pipelines & Services [Member] | Seaway Crude Pipeline Company LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership Interest (in hundredths)		50.00%		50.00%
Total investments in unconsolidated affiliates		$ 1,403.1		$ 1,403.1			1,431.2
Crude Oil Pipelines & Services [Member] | Eagle Ford Pipeline LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership Interest (in hundredths)		50.00%		50.00%
Total investments in unconsolidated affiliates		$ 391.4		$ 391.4			336.5
Crude Oil Pipelines & Services [Member] | Eagle Ford Terminals Corpus Christi LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership Interest (in hundredths)		50.00%		50.00%
Total investments in unconsolidated affiliates	[2]	$ 23.4		$ 23.4			0
Natural Gas Pipelines & Services [Member]
Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]
Equity in income of unconsolidated affiliates		$ 0.9	0.9	$ 2.8	2.7
Natural Gas Pipelines & Services [Member] | White River Hub, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership Interest (in hundredths)		50.00%		50.00%
Total investments in unconsolidated affiliates		$ 23.1		$ 23.1			23.2
Petrochemical & Refined Products Services [Member]
Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]
Equity in income of unconsolidated affiliates		(3.3)	(4.2)	(10.4)	(10.3)
Unamortized excess cost amounts by business segment [Abstract]
Unamortized excess cost amounts		2.4		2.4			2.4
Equity method investment amortization of excess cost		$ 0	0	$ 0	0.1
Petrochemical & Refined Products Services [Member] | Baton Rouge Propylene Concentrator, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership Interest (in hundredths)		30.00%		30.00%
Total investments in unconsolidated affiliates		$ 5.8		$ 5.8			6.5
Petrochemical & Refined Products Services [Member] | Centennial Pipeline LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership Interest (in hundredths)		50.00%		50.00%
Total investments in unconsolidated affiliates		$ 67.2		$ 67.2			66.1
Petrochemical & Refined Products Services [Member] | Other Unconsolidated Affiliates [Member]
Schedule of Equity Method Investments [Line Items]
Total investments in unconsolidated affiliates		2.4		2.4			2.5
Offshore Pipelines & Services [Member]
Schedule of Equity Method Investments [Line Items]
Total investments in unconsolidated affiliates						$ 482.4
Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]
Equity in income of unconsolidated affiliates		5.4	17.1	46.6	35.8
Unamortized excess cost amounts by business segment [Abstract]
Unamortized excess cost amounts	[3]	0		0			9
Equity method investment amortization of excess cost		0	$ 0.3	2.8	$ 0.8
Offshore Pipelines & Services [Member] | Poseidon Oil Pipeline Company, L.L.C. [Member]
Schedule of Equity Method Investments [Line Items]
Total investments in unconsolidated affiliates	[4]	0		0			31.8
Offshore Pipelines & Services [Member] | Cameron Highway Oil Pipeline Company [Member]
Schedule of Equity Method Investments [Line Items]
Total investments in unconsolidated affiliates	[4]	0		0			201.3
Offshore Pipelines & Services [Member] | Deepwater Gateway, L.L.C. [Member]
Schedule of Equity Method Investments [Line Items]
Total investments in unconsolidated affiliates	[4]	0		0			79.6
Offshore Pipelines & Services [Member] | Neptune Pipeline Company, L.L.C. [Member]
Schedule of Equity Method Investments [Line Items]
Total investments in unconsolidated affiliates	[4]	0		0			34.9
Offshore Pipelines & Services [Member] | Southeast Keathley Canyon Pipeline Company L.L.C. [Member]
Schedule of Equity Method Investments [Line Items]
Total investments in unconsolidated affiliates	[4]	$ 0		$ 0			$ 146.1
[1]	New joint venture formed with Oxy Delaware Basin Plant, LLC, a subsidiary of Occidental Petroleum Corporation, in April 2015 that will plan, design and construct a new cryogenic natural gas processing plant to accommodate the growing production of NGL-rich natural gas in the Delaware Basin.
[2]	New joint venture formed with Plains Marketing, L.P., a subsidiary of Plains All American Pipeline, L.P., in March 2015 to construct and operate a marine terminal that will handle crude oil delivered by Eagle Ford Pipeline LLC.
[3]	Our investments in unconsolidated affiliates classified within the Offshore Pipelines & Services segment were sold to Genesis in July 2015.
[4]	Our investments in unconsolidated affiliates classified within the Offshore Pipelines & Services segment were sold to Genesis on July 24, 2015 (see Note 6). At June 30, 2015, the carrying value of these investments was $482.4 million.

Business Acquisitions (Details)

Business Acquisitions (Details) - Eagle Ford Midstream Assets [Member] - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2015
Business Acquisition
Description of acquisition		The EFS Midstream system includes approximately 460 miles of natural gas and condensate gathering pipelines, ten central gathering plants, 780 MMcf/d of natural gas treating capacity and 119 MBPD of condensate stabilization capacity.
Revenues from acquired assets	$ 56.7
Net income from acquired assets	$ 23.8

Business Acquisitions, Purchase

Business Acquisitions, Purchase Price Allocation (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015	Jul. 02, 2015	Dec. 31, 2014
Liabilities assumed in business combination:
Goodwill	$ 5,749.2		$ 4,300.2
EFS Midstream Contract with Producers [Member]
Description of Business Combination:
Contractual obligation	$ 270
Contract term (in years)	10 years
Eagle Ford Midstream Assets [Member]
Consideration:
Cash	$ 1,058.5
Accrued liability related to EFS Midstream acquisition	997.7
Total consideration	2,056.2
Indentifiable assets acquired in business combination:
Current assets, including cash of $13.4 million		$ 64
Property, plant, and equipment		636
Customer relationship intangible assets		1,409.8
Total assets acquired		2,109.8
Liabilities assumed in business combination:
Current liabilities		(9.6)
Long-term debt		(125)
Other long-term liabilities		(1.3)
Total liabilities assumed		(135.9)
Total assets acquired less liabilities assumed		1,973.9
Total consideration given for ownership interests in EFS Midstream	$ 2,056.2
Goodwill		82.3
Description of Business Combination:
Cash acquired		13.4
Eagle Ford Midstream Assets [Member] | Pipelines and related equipment [Member]
Indentifiable assets acquired in business combination:
Property, plant, and equipment		366
Eagle Ford Midstream Assets [Member] | Processing equipment [Member]
Indentifiable assets acquired in business combination:
Property, plant, and equipment		112
Eagle Ford Midstream Assets [Member] | Electrical and metering equipment [Member]
Indentifiable assets acquired in business combination:
Property, plant, and equipment		84
Eagle Ford Midstream Assets [Member] | Pumps and compressors [Member]
Indentifiable assets acquired in business combination:
Property, plant, and equipment		42
Eagle Ford Midstream Assets [Member] | Other property, plant and equipment [Member]
Indentifiable assets acquired in business combination:
Property, plant, and equipment		$ 32
Eagle Ford Midstream Assets [Member] | Customer relationship intangibles [Member]
Description of Business Combination:
Intangible assets as a percent of total assets acquired (in hundredths)		67.00%
Cash flow projections discount rate (in hundredths)	15.00%

Business Acquisitions, Pro Form

Business Acquisitions, Pro Forma Financial Information (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Basic earnings per unit [Abstract]
As reported basic earnings per unit (in dollars per unit)	$ 0.33	$ 0.38	$ 0.94	$ 1.16
Diluted earnings per unit [Abstract]
As reported diluted earnings per unit (in dollars per unit)	$ 0.32	$ 0.37	$ 0.92	$ 1.13
Eagle Ford Midstream Assets [Member]
Pro forma earnings data [Abstract]
Revenues		$ 12,388.7	$ 20,993.5	$ 37,927.5
Costs and expenses		11,502.6	18,645.5	35,195.2
Operating income		958.4	2,650.5	2,911.4
Net income		715.3	1,900.9	2,195.5
Net income attributable to noncontrolling interests		8.1	28.5	24.8
Net income attributable to limited partners		$ 707.2	$ 1,872.4	$ 2,170.7
Basic earnings per unit [Abstract]
As reported basic earnings per unit (in dollars per unit)		$ 0.38	$ 0.94	$ 1.16
Pro forma basic earnings per unit (in dollars per unit)		0.38	0.96	1.18
Diluted earnings per unit [Abstract]
As reported diluted earnings per unit (in dollars per unit)		0.37	0.92	1.13
Pro forma diluted earnings per unit (in dollars per unit)		$ 0.38	$ 0.94	$ 1.15

Intangible Assets and Goodwill,

Intangible Assets and Goodwill, Intangible Assets (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Identifiable intangible assets [Abstract]
Gross Value		$ 5,274.3		$ 5,274.3		$ 5,548.4
Accumulated Amortization		(1,192.2)		(1,192.2)		(1,246.3)
Carrying Value		4,082.1		4,082.1		4,302.1
Amortization Expense		51.7	$ 23.5	129.2	$ 72.7
Forecasted amortization expense [Abstract]
Remainder of 2015		50.3		50.3
2,016		218.8		218.8
2,017		223.5		223.5
2,018		220.4		220.4
2,019		208.6		208.6
Oiltanking Partners L.P. - Step 1 [Member] | Incentive distribution rights [Member]
Identifiable intangible assets [Abstract]
Gross Value						1,460
Carrying Value						1,460
Eagle Ford Midstream Assets [Member] | Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value		1,410		$ 1,410
Eagle Ford Midstream Assets [Member] | Customer relationship intangibles [Member] | Minimum [Member]
Identifiable intangible assets [Abstract]
Finite-Lived Intangible Asset, Useful Life				26 years
Eagle Ford Midstream Assets [Member] | Customer relationship intangibles [Member] | Maximum [Member]
Identifiable intangible assets [Abstract]
Finite-Lived Intangible Asset, Useful Life				29 years
NGL Pipelines & Services [Member]
Identifiable intangible assets [Abstract]
Gross Value		833.8		$ 833.8		1,051.1
Accumulated Amortization		(373.4)		(373.4)		(361.9)
Carrying Value		460.4		460.4		689.2
Amortization Expense		9.7	8.1	24.9	25.4
NGL Pipelines & Services [Member] | Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value		550.8		550.8		340.8
Accumulated Amortization		(183.8)		(183.8)		(183.2)
Carrying Value		367		367		157.6
NGL Pipelines & Services [Member] | Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value		283		283		277.7
Accumulated Amortization		(189.6)		(189.6)		(178.7)
Carrying Value		93.4		93.4		99
NGL Pipelines & Services [Member] | Incentive distribution rights [Member]
Identifiable intangible assets [Abstract]
Gross Value	[1]	0		0		432.6
Accumulated Amortization	[1]	0		0		0
Carrying Value	[1]	0		0		432.6
NGL Pipelines & Services [Member] | Eagle Ford Midstream Assets [Member] | Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value		230.1		230.1
Crude Oil Pipelines & Services [Member]
Identifiable intangible assets [Abstract]
Gross Value		2,485.8		2,485.8		2,244.8
Accumulated Amortization		(83.5)		(83.5)		(21.2)
Carrying Value		2,402.3		2,402.3		2,223.6
Amortization Expense		29	0.3	62.3	0.9
Crude Oil Pipelines & Services [Member] | Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value		2,204.4		2,204.4		1,108
Accumulated Amortization		(28.1)		(28.1)		(7.7)
Carrying Value		2,176.3		2,176.3		1,100.3
Crude Oil Pipelines & Services [Member] | Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value		281.4		281.4		281.4
Accumulated Amortization		(55.4)		(55.4)		(13.5)
Carrying Value		226		226		267.9
Crude Oil Pipelines & Services [Member] | Incentive distribution rights [Member]
Identifiable intangible assets [Abstract]
Gross Value	[1]	0		0		855.4
Accumulated Amortization	[1]	0		0		0
Carrying Value	[1]	0		0		855.4
Crude Oil Pipelines & Services [Member] | Eagle Ford Midstream Assets [Member] | Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value		1,100		1,100
Natural Gas Pipelines & Services [Member]
Identifiable intangible assets [Abstract]
Gross Value		1,712.9		1,712.9		1,629.6
Accumulated Amortization		(687.2)		(687.2)		(656.7)
Carrying Value		1,025.7		1,025.7		972.9
Amortization Expense		10.7	11.1	30.5	34.2
Natural Gas Pipelines & Services [Member] | Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value		1,246.9		1,246.9		1,163.6
Accumulated Amortization		(327.8)		(327.8)		(308.9)
Carrying Value		919.1		919.1		854.7
Natural Gas Pipelines & Services [Member] | Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value		466		466		466
Accumulated Amortization		(359.4)		(359.4)		(347.8)
Carrying Value		106.6		106.6		118.2
Natural Gas Pipelines & Services [Member] | Eagle Ford Midstream Assets [Member] | Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value		83.3		83.3
Petrochemical & Refined Products Services [Member]
Identifiable intangible assets [Abstract]
Gross Value		241.8		241.8		425.9
Accumulated Amortization		(48.1)		(48.1)		(51.1)
Carrying Value		193.7		193.7		374.8
Amortization Expense		2.3	1.5	7	4.6
Petrochemical & Refined Products Services [Member] | Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value		185.5		185.5		198.4
Accumulated Amortization		(37.3)		(37.3)		(43.3)
Carrying Value		148.2		148.2		155.1
Petrochemical & Refined Products Services [Member] | Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value		56.3		56.3		56.3
Accumulated Amortization		(10.8)		(10.8)		(7.8)
Carrying Value		45.5		45.5		48.5
Petrochemical & Refined Products Services [Member] | Incentive distribution rights [Member]
Identifiable intangible assets [Abstract]
Gross Value	[1]	0		0		171.2
Accumulated Amortization	[1]	0		0		0
Carrying Value	[1]	0		0		171.2
Offshore Pipelines & Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	[2]	0		0		197
Accumulated Amortization	[2]	0		0		(155.4)
Carrying Value	[2]	0		0		41.6
Amortization Expense		0	$ 2.5	4.5	$ 7.6
Offshore Pipelines & Services [Member] | Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	[2]	0		0		195.8
Accumulated Amortization	[2]	0		0		(154.9)
Carrying Value	[2]	0		0		40.9
Offshore Pipelines & Services [Member] | Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	[2]	0		0		1.2
Accumulated Amortization	[2]	0		0		(0.5)
Carrying Value	[2]	$ 0		$ 0		$ 0.7
[1]	At December 31, 2014, we had indefinite-lived intangible assets outstanding with a carrying value of $1.46 billion recorded in connection with our acquisition of the Oiltanking IDRs in October 2014. The IDRs represented contractual rights to future cash incentive distributions to be paid by Oiltanking. In February 2015 (following completion of Step 2 of the Oiltanking acquisition), the Oiltanking IDRs were cancelled and the carrying value of the IDRs were reclassified to goodwill.
[2]	Our intangible assets classified within the Offshore Pipelines & Services segment were sold to Genesis in July 2015 (see Note 6).

Intangible Assets and Goodwil63

Intangible Assets and Goodwill, Goodwill (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Changes in carrying amount of goodwill [Roll Forward]
Balance at beginning of period	$ 4,300.2
Purchase price and other adjustments	1,454.1
Reduction in goodwill related to the sale of assets	(82)
Addition to goodwill related to the acquisition of EFS Midstream	82.3
Goodwill reclassified to assets held-for-sale	(5.4)
Balance at end of period	5,749.2	$ 4,300.2
Oiltanking Partners L.P. - Step 1 [Member]
Changes in carrying amount of goodwill [Roll Forward]
Purchase price and other adjustments		100.3
NGL Pipelines & Services [Member]
Changes in carrying amount of goodwill [Roll Forward]
Balance at beginning of period	2,210.2
Purchase price and other adjustments	432.6
Reduction in goodwill related to the sale of assets	0
Addition to goodwill related to the acquisition of EFS Midstream	8.9
Goodwill reclassified to assets held-for-sale	0
Balance at end of period	2,651.7	2,210.2
NGL Pipelines & Services [Member] | Oiltanking Partners L.P. - Step 1 [Member]
Changes in carrying amount of goodwill [Roll Forward]
Purchase price and other adjustments		29.8
Crude Oil Pipelines & Services [Member]
Changes in carrying amount of goodwill [Roll Forward]
Balance at beginning of period	918.7
Purchase price and other adjustments	850.7
Reduction in goodwill related to the sale of assets	0
Addition to goodwill related to the acquisition of EFS Midstream	73.4
Goodwill reclassified to assets held-for-sale	0
Balance at end of period	1,842.8	918.7
Crude Oil Pipelines & Services [Member] | Oiltanking Partners L.P. - Step 1 [Member]
Changes in carrying amount of goodwill [Roll Forward]
Purchase price and other adjustments		58.8
Natural Gas Pipelines & Services [Member]
Changes in carrying amount of goodwill [Roll Forward]
Balance at beginning of period	296.3
Purchase price and other adjustments	0
Reduction in goodwill related to the sale of assets	0
Addition to goodwill related to the acquisition of EFS Midstream	0
Goodwill reclassified to assets held-for-sale	0
Balance at end of period	296.3	296.3
Petrochemical & Refined Products Services [Member]
Changes in carrying amount of goodwill [Roll Forward]
Balance at beginning of period	793
Purchase price and other adjustments	170.8
Reduction in goodwill related to the sale of assets	0
Addition to goodwill related to the acquisition of EFS Midstream	0
Goodwill reclassified to assets held-for-sale	(5.4)
Balance at end of period	958.4	793
Petrochemical & Refined Products Services [Member] | Oiltanking Partners L.P. - Step 1 [Member]
Changes in carrying amount of goodwill [Roll Forward]
Purchase price and other adjustments		11.7
Offshore Pipelines & Services [Member]
Changes in carrying amount of goodwill [Roll Forward]
Balance at beginning of period	82
Purchase price and other adjustments	0
Reduction in goodwill related to the sale of assets	(82)
Addition to goodwill related to the acquisition of EFS Midstream	0
Goodwill reclassified to assets held-for-sale	0
Balance at end of period	$ 0	$ 82

Debt Obligations (Details)

Debt Obligations (Details) - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Debt Instrument [Line Items]
Principal Outstanding		$ 22,497.8		$ 21,389.2
Other, non-principal amounts		(37.7)		(25.4)
Less current maturities of debt	[1]	(1,619.4)		(2,206.4)
Total long-term debt		20,840.7		19,157.4
Debt Obligations Terms [Abstract]
Gains on early extinguishment of debt		1.4	$ 0
Letters of credit outstanding for facilities and motor fuel tax obligations		2.5
Senior Debt Obligations [Member]
Debt Instrument [Line Items]
Principal Outstanding		21,019.5		19,856.5
Debt Obligations Terms [Abstract]
Aggregate debt principal issued		2,500
Senior Debt Obligations [Member] | Commercial Paper Notes [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 869.5		906.5
Debt Obligations Terms [Abstract]
Interest Rate Terms		variable
Information regarding variable interest rates paid [Abstract]
Variable Interest Rates Paid, Minimum (in hundredths)		0.35%
Variable Interest Rates Paid, Maximum (in hundredths)		0.78%
Weighted-Average Interest Rate Paid (in hundredths)		0.59%
Senior Debt Obligations [Member] | EPO Senior Notes I [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 0		250
Debt Obligations Terms [Abstract]
Interest Rate Terms		fixed
Interest Rate, stated percentage (in hundredths)		5.00%
Maturity Date		Mar. 1, 2015
Repayment of debt obligations		$ 250
Senior Debt Obligations [Member] | EPO Senior Notes X [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 0		400
Debt Obligations Terms [Abstract]
Interest Rate Terms		fixed
Interest Rate, stated percentage (in hundredths)		3.70%
Maturity Date		Jun. 1, 2015
Repayment of debt obligations		$ 400
Senior Debt Obligations [Member] | EPO Senior Notes FF [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 0		650
Debt Obligations Terms [Abstract]
Interest Rate Terms		fixed
Interest Rate, stated percentage (in hundredths)		1.25%
Maturity Date		Aug. 13, 2015
Senior Debt Obligations [Member] | EPO Senior Notes AA [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 750		750
Debt Obligations Terms [Abstract]
Interest Rate Terms		fixed
Interest Rate, stated percentage (in hundredths)		3.20%
Maturity Date		Feb. 1, 2016
Senior Debt Obligations [Member] | EPO 364-Day Credit Agreement [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 0		0
Debt Obligations Terms [Abstract]
Interest Rate Terms		variable
Maturity Date		Sep. 14, 2016
Maximum borrowing capacity		$ 1,500
Maximum bank commitments increase		200
Senior Debt Obligations [Member] | EPO Senior Notes L [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 800		800
Debt Obligations Terms [Abstract]
Interest Rate Terms		fixed
Interest Rate, stated percentage (in hundredths)		6.30%
Maturity Date		Sep. 1, 2017
Senior Debt Obligations [Member] | EPO Senior Notes V [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 349.7		349.7
Debt Obligations Terms [Abstract]
Interest Rate Terms		fixed
Interest Rate, stated percentage (in hundredths)		6.65%
Maturity Date		Apr. 15, 2018
Senior Debt Obligations [Member] | EPO Senior Notes OO [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 750		0
Debt Obligations Terms [Abstract]
Interest Rate Terms		fixed
Interest Rate, stated percentage (in hundredths)		1.65%
Maturity Date		May 7, 2018
Aggregate debt principal issued		$ 750
Debt issued as percent of principal amount (in hundredths)		99.881%
Senior Debt Obligations [Member] | EPO Senior Notes N [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 700		700
Debt Obligations Terms [Abstract]
Interest Rate Terms		fixed
Interest Rate, stated percentage (in hundredths)		6.50%
Maturity Date		Jan. 31, 2019
Senior Debt Obligations [Member] | EPO Senior Notes LL [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 800		800
Debt Obligations Terms [Abstract]
Interest Rate Terms		fixed
Interest Rate, stated percentage (in hundredths)		2.55%
Maturity Date		Oct. 15, 2019
Senior Debt Obligations [Member] | EPO Senior Notes Q [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 500		500
Debt Obligations Terms [Abstract]
Interest Rate Terms		fixed
Interest Rate, stated percentage (in hundredths)		5.25%
Maturity Date		Jan. 31, 2020
Senior Debt Obligations [Member] | EPO Senior Notes Y [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 1,000		1,000
Debt Obligations Terms [Abstract]
Interest Rate Terms		fixed
Interest Rate, stated percentage (in hundredths)		5.20%
Maturity Date		Sep. 1, 2020
Senior Debt Obligations [Member] | EPO Multi-Year Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 0		0
Debt Obligations Terms [Abstract]
Interest Rate Terms		variable
Maturity Date		Sep. 15, 2020
Maximum borrowing capacity		$ 4,000		3,500
Maximum bank commitments increase		$ 500
Information regarding variable interest rates paid [Abstract]
Variable Interest Rates Paid, Minimum (in hundredths)		1.15%
Variable Interest Rates Paid, Maximum (in hundredths)		3.25%
Weighted-Average Interest Rate Paid (in hundredths)		1.30%
Senior Debt Obligations [Member] | EPO Senior Notes CC [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 650		650
Debt Obligations Terms [Abstract]
Interest Rate Terms		fixed
Interest Rate, stated percentage (in hundredths)		4.05%
Maturity Date		Feb. 15, 2022
Senior Debt Obligations [Member] | EPO Senior Notes HH [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 1,250		1,250
Debt Obligations Terms [Abstract]
Interest Rate Terms		fixed
Interest Rate, stated percentage (in hundredths)		3.35%
Maturity Date		Mar. 15, 2023
Senior Debt Obligations [Member] | EPO Senior Notes JJ [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 850		850
Debt Obligations Terms [Abstract]
Interest Rate Terms		fixed
Interest Rate, stated percentage (in hundredths)		3.90%
Maturity Date		Feb. 15, 2024
Senior Debt Obligations [Member] | EPO Senior Notes MM [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 1,150		1,150
Debt Obligations Terms [Abstract]
Interest Rate Terms		fixed
Interest Rate, stated percentage (in hundredths)		3.75%
Maturity Date		Feb. 15, 2025
Senior Debt Obligations [Member] | EPO Senior Notes PP [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 875		0
Debt Obligations Terms [Abstract]
Interest Rate Terms		fixed
Interest Rate, stated percentage (in hundredths)		3.70%
Maturity Date		Feb. 15, 2026
Aggregate debt principal issued		$ 875
Debt issued as percent of principal amount (in hundredths)		99.635%
Senior Debt Obligations [Member] | EPO Senior Notes D [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 500		500
Debt Obligations Terms [Abstract]
Interest Rate Terms		fixed
Interest Rate, stated percentage (in hundredths)		6.875%
Maturity Date		Mar. 1, 2033
Senior Debt Obligations [Member] | EPO Senior Notes H [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 350		350
Debt Obligations Terms [Abstract]
Interest Rate Terms		fixed
Interest Rate, stated percentage (in hundredths)		6.65%
Maturity Date		Oct. 15, 2034
Senior Debt Obligations [Member] | EPO Senior Notes J [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 250		250
Debt Obligations Terms [Abstract]
Interest Rate Terms		fixed
Interest Rate, stated percentage (in hundredths)		5.75%
Maturity Date		Mar. 1, 2035
Senior Debt Obligations [Member] | EPO Senior Notes W [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 399.6		399.6
Debt Obligations Terms [Abstract]
Interest Rate Terms		fixed
Interest Rate, stated percentage (in hundredths)		7.55%
Maturity Date		Apr. 15, 2038
Senior Debt Obligations [Member] | EPO Senior Notes R [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 600		600
Debt Obligations Terms [Abstract]
Interest Rate Terms		fixed
Interest Rate, stated percentage (in hundredths)		6.125%
Maturity Date		Oct. 15, 2039
Senior Debt Obligations [Member] | EPO Senior Notes Z [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 600		600
Debt Obligations Terms [Abstract]
Interest Rate Terms		fixed
Interest Rate, stated percentage (in hundredths)		6.45%
Maturity Date		Sep. 1, 2040
Senior Debt Obligations [Member] | EPO Senior Notes BB [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 750		750
Debt Obligations Terms [Abstract]
Interest Rate Terms		fixed
Interest Rate, stated percentage (in hundredths)		5.95%
Maturity Date		Feb. 1, 2041
Senior Debt Obligations [Member] | EPO Senior Notes DD [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 600		600
Debt Obligations Terms [Abstract]
Interest Rate Terms		fixed
Interest Rate, stated percentage (in hundredths)		5.70%
Maturity Date		Feb. 15, 2042
Senior Debt Obligations [Member] | EPO Senior Notes EE [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 750		750
Debt Obligations Terms [Abstract]
Interest Rate Terms		fixed
Interest Rate, stated percentage (in hundredths)		4.85%
Maturity Date		Aug. 15, 2042
Senior Debt Obligations [Member] | EPO Senior Notes GG [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 1,100		1,100
Debt Obligations Terms [Abstract]
Interest Rate Terms		fixed
Interest Rate, stated percentage (in hundredths)		4.45%
Maturity Date		Feb. 15, 2043
Senior Debt Obligations [Member] | EPO Senior Notes II [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 1,400		1,400
Debt Obligations Terms [Abstract]
Interest Rate Terms		fixed
Interest Rate, stated percentage (in hundredths)		4.85%
Maturity Date		Mar. 15, 2044
Senior Debt Obligations [Member] | EPO Senior Notes KK [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 1,150		1,150
Debt Obligations Terms [Abstract]
Interest Rate Terms		fixed
Interest Rate, stated percentage (in hundredths)		5.10%
Maturity Date		Feb. 15, 2045
Senior Debt Obligations [Member] | EPO Senior Notes QQ [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 875		0
Debt Obligations Terms [Abstract]
Interest Rate Terms		fixed
Interest Rate, stated percentage (in hundredths)		4.90%
Maturity Date		May 15, 2046
Aggregate debt principal issued		$ 875
Debt issued as percent of principal amount (in hundredths)		99.635%
Senior Debt Obligations [Member] | EPO Senior Notes NN [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 400		400
Debt Obligations Terms [Abstract]
Interest Rate Terms		fixed
Interest Rate, stated percentage (in hundredths)		4.95%
Maturity Date		Oct. 15, 2054
Senior Debt Obligations [Member] | TEPPCO Senior Notes 4 [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 0.3		0.3
Debt Obligations Terms [Abstract]
Interest Rate Terms		fixed
Interest Rate, stated percentage (in hundredths)		6.65%
Maturity Date		Apr. 15, 2018
Senior Debt Obligations [Member] | TEPPCO Senior Notes 5 [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 0.4		0.4
Debt Obligations Terms [Abstract]
Interest Rate Terms		fixed
Interest Rate, stated percentage (in hundredths)		7.55%
Maturity Date		Apr. 15, 2038
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes A [Member]
Debt Instrument [Line Items]
Principal Outstanding	[2]	$ 521.9		550
Debt Obligations Terms [Abstract]
Interest Rate Terms	[2]	fixed/variable
Interest Rate, stated percentage (in hundredths)	[2]	8.375%
Maturity Date	[2]	Aug. 31, 2066
Repayment of debt obligations		$ 28.1
Date through which interest rate is fixed		8/1/2016
Variable annual interest rate thereafter, variable rate basis		3-month LIBOR
Variable interest rate (in hundredths)		3.7075%
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes C [Member]
Debt Instrument [Line Items]
Principal Outstanding	[3]	$ 259.5		285.8
Debt Obligations Terms [Abstract]
Interest Rate Terms	[3]	fixed/variable
Interest Rate, stated percentage (in hundredths)	[3]	7.00%
Maturity Date	[3]	Jun. 1, 2067
Repayment of debt obligations		$ 26.3
Date through which interest rate is fixed		9/1/2017
Variable annual interest rate thereafter, variable rate basis		3-month LIBOR
Variable interest rate (in hundredths)		2.7775%
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes B [Member]
Debt Instrument [Line Items]
Principal Outstanding	[4]	$ 682.7		682.7
Debt Obligations Terms [Abstract]
Interest Rate Terms	[4]	fixed/variable
Interest Rate, stated percentage (in hundredths)	[4]	7.034%
Maturity Date	[4]	Jan. 15, 2068
Date through which interest rate is fixed		1/15/2018
Variable annual interest rate thereafter, variable rate basis		3-month LIBOR
Variable interest rate (in hundredths)		2.68%
Minimum variable annual interest rate (in hundredths)		7.034%
Junior Debt Obligations [Member] | TEPPCO Junior Subordinated Notes [Member]
Debt Instrument [Line Items]
Principal Outstanding		$ 14.2		$ 14.2
Debt Obligations Terms [Abstract]
Interest Rate Terms		fixed/variable
Maturity Date		Jun. 1, 2067
[1]	We expect to refinance the current maturities of our debt obligations at or prior to their maturity.
[2]	Fixed rate of 8.375% through August 1, 2016 (i.e., first call date without a make-whole redemption premium); thereafter, variable rate based on 3-month LIBOR plus 3.7075%. During the third quarter of 2015, EPO retired $28.1 million of these junior notes.
[3]	Fixed rate of 7.0% through September 1, 2017 (i.e., first call date without a make-whole redemption premium); thereafter, variable rate based on 3-month LIBOR plus 2.7775%. During the third quarter of 2015, EPO retired $26.3 million of these junior notes.
[4]	Fixed rate of 7.034% through January 15, 2018 (i.e., first call date without a make-whole redemption premium); thereafter, the rate will be the greater of 7.034% or a variable rate based on 3-month LIBOR plus 2.68%.

Debt Obligations, Debt Maturiti

Debt Obligations, Debt Maturities (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Scheduled Maturities of Debt [Abstract]
Remainder of 2015	$ 869.5
2,016	750
2,017	800
2,018	1,100
2,019	1,500
After 2,019	17,478.3
Total	22,497.8	$ 21,389.2
Commercial Paper Notes [Member]
Scheduled Maturities of Debt [Abstract]
Remainder of 2015	869.5
2,016	0
2,017	0
2,018	0
2,019	0
After 2,019	0
Total	869.5
Senior Notes [Member]
Scheduled Maturities of Debt [Abstract]
Remainder of 2015	0
2,016	750
2,017	800
2,018	1,100
2,019	1,500
After 2,019	16,000
Total	20,150
Junior Subordinated Notes [Member]
Scheduled Maturities of Debt [Abstract]
Remainder of 2015	0
2,016	0
2,017	0
2,018	0
2,019	0
After 2,019	1,478.3
Total	$ 1,478.3

Equity and Distributions, Summa

Equity and Distributions, Summary of Changes in Outstanding Units (Details)	9 Months Ended
	Sep. 30, 2015shares
Common Units (Unrestricted) [Member]
Summary of changes in outstanding units [Roll Forward]
Beginning Balance (in units)	1,933,095,027
Common units issued in connection with at-the-market program (in units)	23,258,453
Common units issued in connection with DRIP and EUPP (in units)	8,251,315
Common units issued in connection with Step 2 of Oiltanking acquisition (in units)	36,827,517
Common units issued in connection with the vesting and exercise of unit options (in units)	333,002
Common units issued in connection with the vesting of phantom unit awards (in units)	613,689
Common units issued in connection with the vesting of restricted common unit awards (in units)	1,997,194
Forfeiture of restricted common unit awards (in units)	0
Acquisition and cancellation of treasury units in connection with the vesting of equity-based awards (in units)	(680,496)
Other (in units)	15,054
Ending Balance (in units)	2,003,710,755
Restricted Common Units [Member]
Summary of changes in outstanding units [Roll Forward]
Beginning Balance (in units)	4,229,790
Common units issued in connection with at-the-market program (in units)	0
Common units issued in connection with DRIP and EUPP (in units)	0
Common units issued in connection with Step 2 of Oiltanking acquisition (in units)	0
Common units issued in connection with the vesting and exercise of unit options (in units)	0
Common units issued in connection with the vesting of phantom unit awards (in units)	0
Common units issued in connection with the vesting of restricted common unit awards (in units)	(1,997,194)
Forfeiture of restricted common unit awards (in units)	(157,750)
Acquisition and cancellation of treasury units in connection with the vesting of equity-based awards (in units)	0
Other (in units)	0
Ending Balance (in units)	2,074,846
Common units [Member]
Summary of changes in outstanding units [Roll Forward]
Beginning Balance (in units)	1,937,324,817
Common units issued in connection with at-the-market program (in units)	23,258,453
Common units issued in connection with DRIP and EUPP (in units)	8,251,315
Common units issued in connection with Step 2 of Oiltanking acquisition (in units)	36,827,517
Common units issued in connection with the vesting and exercise of unit options (in units)	333,002
Common units issued in connection with the vesting of phantom unit awards (in units)	613,689
Common units issued in connection with the vesting of restricted common unit awards (in units)	0
Forfeiture of restricted common unit awards (in units)	(157,750)
Acquisition and cancellation of treasury units in connection with the vesting of equity-based awards (in units)	(680,496)
Other (in units)	15,054
Ending Balance (in units)	2,005,785,601

Equity and Distributions, Issua

Equity and Distributions, Issuances of Equity (Details) - USD ($) $ in Millions	Nov. 06, 2015	Mar. 31, 2015	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014	Jun. 30, 2015
Net Cash Proceeds from Sale of Common Units [Abstract]
Net cash proceeds from the issuance of common units			$ 1,011.4	$ 304.9
Oiltanking Partners L.P. [Member]
Description of Business Combination:
Limited partner interests acquired (in hundredths)					65.90%
Oiltanking Acquisition [Member]
Description of Business Combination:
Total consideration for acquisition			$ 5,900
Oiltanking Partners L.P. - Step 1 [Member]
Description of Business Combination:
Total consideration for acquisition					$ 4,410
Oiltanking Partners L.P. - Step 2 [Member]
Description of Business Combination:
Common units exchanged for each Oiltanking unit (in units)			1.3
Common units issued in connection with acquisition of Oiltanking (in units)			36,827,517
Distribution Reinvestment Plan [Member]
Registration Statements and Equity Offerings [Line Items]
Maximum common units authorized for issuance (in units)			140,000,000
Remaining units available for issuance (in units)			19,516,031
Net Cash Proceeds from Sale of Common Units [Abstract]
Number of common units issued (in units)			7,965,318	7,148,778
Net cash proceeds from the issuance of common units			$ 242.8	$ 239.8
Distribution Reinvestment Plan [Member] | EPCO and its privately held affiliates [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Net cash proceeds from the issuance of common units	$ 50		$ 50	$ 75
Employee Unit Purchase Plan [Member]
Registration Statements and Equity Offerings [Line Items]
Maximum common units authorized for issuance (in units)			8,000,000
Remaining units available for issuance (in units)			6,867,071
Net Cash Proceeds from Sale of Common Units [Abstract]
Number of common units issued (in units)			285,997	207,126
Net cash proceeds from the issuance of common units			$ 8.9	$ 7.4
2015 At-the-Market Registration [Member]
Registration Statements and Equity Offerings [Line Items]
Maximum common units authorized for issuance			1,920
Remaining units available for issuance			$ 1,920
2013 At-the-Market Registration [Member]
Registration Statements and Equity Offerings [Line Items]
Maximum common units authorized for issuance						$ 1,250
Remaining units available for issuance						$ 424.6
Net Cash Proceeds from Sale of Common Units [Abstract]
Number of common units issued (in units)			23,258,453	1,590,334
Gross proceeds from the sale of common units			$ 767.1	$ 58.3
Net cash proceeds from the issuance of common units			$ 759.7	$ 57.7
2013 At-the-Market Registration [Member] | EPCO and its privately held affiliates [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Number of common units issued (in units)		3,225,057	3,225,057
Net cash proceeds from the issuance of common units			$ 100

Equity and Distributions, Nonco

Equity and Distributions, Noncontrolling Interests (Details) $ in Billions	9 Months Ended
	Sep. 30, 2015USD ($)
Noncontrolling Interest
Noncontrolling interests acquired	$ 1.4
Panola Pipeline Company, LLC [Member]
Noncontrolling Interest
Noncontrolling Interest, Ownership Percentage by Parent (in hundredths)	55.00%
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners (in hundredths)	45.00%
Anadarko Petroleum Corporation [Member] | Panola Pipeline Company, LLC [Member]
Noncontrolling Interest
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners (in hundredths)	15.00%
DCP Midstream Partners, LP [Member] | Panola Pipeline Company, LLC [Member]
Noncontrolling Interest
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners (in hundredths)	15.00%
MarkWest Energy Partners, L.P. [Member] | Panola Pipeline Company, LLC [Member]
Noncontrolling Interest
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners (in hundredths)	15.00%

Equity and Distributions, Accum

Equity and Distributions, Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Accumulated Other Comprehensive Income (Loss) [Abstract]
Beginning Balance			$ (241.6)	$ (359)
Other comprehensive income before reclassifications			112.7	16.1
Amounts reclassified from accumulated other comprehensive loss (income)			(101.8)	36.8
Total other comprehensive income (loss)	$ 47.9	$ 48.1	10.9	52.9
Ending Balance	(230.7)	(306.1)	(230.7)	(306.1)
Interest expense	243.7	229.8	723.2	679.6
Revenue	(6,307.9)	(12,330.2)	(20,872.9)	(37,760.9)
Operating costs and expenses	5,452.6	11,414.8	18,426.5	34,934.4
Total	(657.7)	(699.2)	(1,864.9)	(2,152.4)
Gains and Losses on Cash Flow Hedges [Member] | Interest rate derivatives [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Beginning Balance			(314.8)	(347.2)
Other comprehensive income before reclassifications			0	0
Amounts reclassified from accumulated other comprehensive loss (income)			26.3	23.9
Total other comprehensive income (loss)			26.3	23.9
Ending Balance	(288.5)	(323.3)	(288.5)	(323.3)
Gains and Losses on Cash Flow Hedges [Member] | Commodity derivatives [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Beginning Balance			69.9	(14.7)
Other comprehensive income before reclassifications			112.3	16.1
Amounts reclassified from accumulated other comprehensive loss (income)			(128.1)	12.9
Total other comprehensive income (loss)			(15.8)	29
Ending Balance	54.1	14.3	54.1	14.3
Other [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Beginning Balance			3.3	2.9
Other comprehensive income before reclassifications			0.4	0
Amounts reclassified from accumulated other comprehensive loss (income)			0	0
Total other comprehensive income (loss)			0.4	0
Ending Balance	3.7	2.9	3.7	2.9
Reclassification out of Accumulated Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Total	(37.9)	(10)	(101.8)	36.8
Reclassification out of Accumulated Other Comprehensive Income [Member] | Gains and Losses on Cash Flow Hedges [Member] | Interest rate derivatives [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Interest expense	8.9	8	26.3	23.9
Reclassification out of Accumulated Other Comprehensive Income [Member] | Gains and Losses on Cash Flow Hedges [Member] | Commodity derivatives [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Revenue	(46.8)	(17.8)	(128.6)	14.5
Operating costs and expenses	$ 0	$ (0.2)	$ 0.5	$ (1.6)

Equity and Distributions, Distr

Equity and Distributions, Distributions (Details) - $ / shares	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Distributions to Partners [Abstract]
Number of Designated Units to be excluded from distributions during 2015 (in units)	35,380,000
Cash Distribution [Member] | First Quarter 2014 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)		$ 0.3550
Record Date		Apr. 30, 2014
Payment Date		May 7, 2014
Cash Distribution [Member] | Second Quarter 2014 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)		$ 0.3600
Record Date		Jul. 31, 2014
Payment Date		Aug. 7, 2014
Cash Distribution [Member] | Third Quarter 2014 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)		$ 0.3650
Record Date		Oct. 31, 2014
Payment Date		Nov. 7, 2014
Cash Distribution [Member] | First Quarter 2015 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)	$ 0.3750
Record Date	Apr. 30, 2015
Payment Date	May 7, 2015
Cash Distribution [Member] | Second Quarter 2015 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)	$ 0.3800
Record Date	Jul. 31, 2015
Payment Date	Aug. 7, 2015
Cash Distribution [Member] | Third Quarter 2015 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)	$ 0.3850
Record Date	Oct. 30, 2015
Payment Date	Nov. 6, 2015

Business Segments (Details)

Business Segments (Details) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)	Sep. 30, 2015USD ($)Segment	Sep. 30, 2014USD ($)
Business Segments [Abstract]
Number of reportable segments | Segment			5
Segment Gross Operating Margin [Abstract]
Revenues	$ 6,307.9	$ 12,330.2	$ 20,872.9	$ 37,760.9
Subtract operating costs and expenses	(5,452.6)	(11,414.8)	(18,426.5)	(34,934.4)
Add equity in income of unconsolidated affiliates	103.1	72.3	302.5	179.1
Add depreciation, amortization and accretion expense amounts not reflected in gross operating margin	351.1	322.7	1,082	936.5
Add impairment charges not reflected in gross operating margin	26.8	5.7	139.1	18.2
Add net losses or subtract net gains attributable to asset sales and insurance recoveries not reflected in gross operating margin (see Note 16)	12.3	(2.6)	14.7	(99)
Add non-refundable deferred revenues attributable to shipper make-up rights on new pipeline projects reflected in gross operating margin	3.4	21.6	39.3	66.8
Subtract subsequent recognition of deferred revenues attributable to make-up rights not reflected in gross operating margin	(10.9)	0	(45.3)	0
Total segment gross operating margin	1,341.1	1,335.1	3,978.7	3,928.1
Reconciliation of total Segment Gross Operating Margin [Abstract]
Total segment gross operating margin	1,341.1	1,335.1	3,978.7	3,928.1
Adjustments to reconcile total segment gross operating margin to operating income:
Subtract depreciation, amortization and accretion expense amounts not reflected in gross operating margin	(351.1)	(322.7)	(1,082)	(936.5)
Subtract impairment charges not reflected in gross operating margin	(26.8)	(5.7)	(139.1)	(18.2)
Add net gains or subtract net losses attributable to asset sales and insurance recoveries not reflected in gross operating margin	(12.3)	2.6	(14.7)	99
Subtract non-refundable deferred revenues attributable to shipper make-up rights on new pipeline projects reflected in gross operating margin	(3.4)	(21.6)	(39.3)	(66.8)
Add subsequent recognition of deferred revenues attributable to make-up rights not reflected in gross operating margin	10.9	0	45.3	0
Subtract general and administrative costs not reflected in gross operating margin	(49)	(50)	(143.2)	(150.9)
Operating income	909.4	937.7	2,605.7	2,854.7
Other expense, net	(246.2)	(230.8)	(736.4)	(679.8)
Income before income taxes	$ 663.2	$ 706.9	$ 1,869.3	$ 2,174.9

Business Segments, Segment Repo

Business Segments, Segment Reporting Information (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Information by business segment [Abstract]
Revenues from third parties		$ 6,294	$ 12,319.2	$ 20,845.6	$ 37,697.1
Revenues from related parties		13.9	11	27.3	63.8
Intersegment and intrasegment revenues		0	0	0	0
Total revenues		6,307.9	12,330.2	20,872.9	37,760.9
Equity in income (loss) of unconsolidated affiliates		103.1	72.3	302.5	179.1
Gross operating margin		1,341.1	1,335.1	3,978.7	3,928.1
Property, plant and equipment, net (see Note 6)		31,214.1		31,214.1		$ 29,881.6
Investments in unconsolidated affiliates (see Note 7)		2,625.3		2,625.3		3,042
Intangible assets, net (see Note 9)		4,082.1		4,082.1		4,302.1
Goodwill (see Note 9)		5,749.2		5,749.2		4,300.2
Segment assets		43,670.7		43,670.7		41,525.9
NGL Pipelines and Services [Member]
Information by business segment [Abstract]
Equity in income (loss) of unconsolidated affiliates		18.9	11.7	43	19.2
Intangible assets, net (see Note 9)		460.4		460.4		689.2
Goodwill (see Note 9)		2,651.7		2,651.7		2,210.2
Crude Oil Pipelines & Services [Member]
Information by business segment [Abstract]
Equity in income (loss) of unconsolidated affiliates		81.2	46.8	220.5	131.7
Intangible assets, net (see Note 9)		2,402.3		2,402.3		2,223.6
Goodwill (see Note 9)		1,842.8		1,842.8		918.7
Natural Gas Pipelines & Services [Member]
Information by business segment [Abstract]
Equity in income (loss) of unconsolidated affiliates		0.9	0.9	2.8	2.7
Intangible assets, net (see Note 9)		1,025.7		1,025.7		972.9
Goodwill (see Note 9)		296.3		296.3		296.3
Petrochemical and Refined Products Services [Member]
Information by business segment [Abstract]
Equity in income (loss) of unconsolidated affiliates		(3.3)	(4.2)	(10.4)	(10.3)
Intangible assets, net (see Note 9)		193.7		193.7		374.8
Goodwill (see Note 9)		958.4		958.4		793
Offshore Pipelines And Services [Member]
Information by business segment [Abstract]
Equity in income (loss) of unconsolidated affiliates		5.4	17.1	46.6	35.8
Intangible assets, net (see Note 9)	[1]	0		0		41.6
Goodwill (see Note 9)		0		0		82
Reportable Business Segments [Member] | NGL Pipelines and Services [Member]
Information by business segment [Abstract]
Revenues from third parties		2,284.6	4,024	7,223.2	13,217.2
Revenues from related parties		2.2	2.7	6	10.2
Intersegment and intrasegment revenues		2,461	3,603.8	7,685.1	10,789.7
Total revenues		4,747.8	7,630.5	14,914.3	24,017.1
Equity in income (loss) of unconsolidated affiliates		18.9	11.7	43	19.2
Gross operating margin		695.5	711.5	2,041.3	2,172.4
Property, plant and equipment, net (see Note 6)		12,192.8		12,192.8		11,766.9
Investments in unconsolidated affiliates (see Note 7)		708.9		708.9		682.3
Intangible assets, net (see Note 9)		460.4		460.4		689.2
Goodwill (see Note 9)		2,651.7		2,651.7		2,210.2
Segment assets		16,013.8		16,013.8		15,348.6
Reportable Business Segments [Member] | Crude Oil Pipelines & Services [Member]
Information by business segment [Abstract]
Revenues from third parties		2,316.4	5,435.6	8,080.4	16,236.6
Revenues from related parties		6.2	1.5	8.6	31.1
Intersegment and intrasegment revenues		1,142.1	2,529.5	3,958.9	10,714.5
Total revenues		3,464.7	7,966.6	12,047.9	26,982.2
Equity in income (loss) of unconsolidated affiliates		81.2	46.8	220.5	131.7
Gross operating margin		254.6	190.8	704.2	534.5
Property, plant and equipment, net (see Note 6)		3,550		3,550		2,332.2
Investments in unconsolidated affiliates (see Note 7)		1,817.9		1,817.9		1,767.7
Intangible assets, net (see Note 9)		2,402.3		2,402.3		2,223.6
Goodwill (see Note 9)		1,842.8		1,842.8		918.7
Segment assets		9,613		9,613		7,242.2
Reportable Business Segments [Member] | Natural Gas Pipelines & Services [Member]
Information by business segment [Abstract]
Revenues from third parties		705.2	1,026.5	2,117.5	3,261
Revenues from related parties		4.5	5.4	10.8	16.5
Intersegment and intrasegment revenues		180.2	231	519.7	835.8
Total revenues		889.9	1,262.9	2,648	4,113.3
Equity in income (loss) of unconsolidated affiliates		0.9	0.9	2.8	2.7
Gross operating margin		192.4	195.4	588.3	618.8
Property, plant and equipment, net (see Note 6)		8,680.6		8,680.6		8,835.5
Investments in unconsolidated affiliates (see Note 7)		23.1		23.1		23.2
Intangible assets, net (see Note 9)		1,025.7		1,025.7		972.9
Goodwill (see Note 9)		296.3		296.3		296.3
Segment assets		10,025.7		10,025.7		10,127.9
Reportable Business Segments [Member] | Petrochemical and Refined Products Services [Member]
Information by business segment [Abstract]
Revenues from third parties		980	1,792	3,347.6	4,869.9
Revenues from related parties		0	0	0	0
Intersegment and intrasegment revenues		267.3	452.2	875.8	1,317.6
Total revenues		1,247.3	2,244.2	4,223.4	6,187.5
Equity in income (loss) of unconsolidated affiliates		(3.3)	(4.2)	(10.4)	(10.3)
Gross operating margin		191.5	190.3	547.4	482.4
Property, plant and equipment, net (see Note 6)		3,013.5		3,013.5		3,047.2
Investments in unconsolidated affiliates (see Note 7)		75.4		75.4		75.1
Intangible assets, net (see Note 9)		193.7		193.7		374.8
Goodwill (see Note 9)		958.4		958.4		793
Segment assets		4,241		4,241		4,290.1
Reportable Business Segments [Member] | Offshore Pipelines And Services [Member]
Information by business segment [Abstract]
Revenues from third parties		7.8	41.1	76.9	112.4
Revenues from related parties		1	1.4	1.9	6
Intersegment and intrasegment revenues		0.1	1.2	0.6	4.8
Total revenues		8.9	43.7	79.4	123.2
Equity in income (loss) of unconsolidated affiliates		5.4	17.1	46.6	35.8
Gross operating margin		7.1	47.1	97.5	120
Property, plant and equipment, net (see Note 6)		0		0		1,145.1
Investments in unconsolidated affiliates (see Note 7)		0		0		493.7
Intangible assets, net (see Note 9)		0		0		41.6
Goodwill (see Note 9)		0		0		82
Segment assets		0		0		1,762.4
Eliminations [Member]
Information by business segment [Abstract]
Revenues from third parties		0	0	0	0
Revenues from related parties		0	0	0	0
Intersegment and intrasegment revenues		(4,050.7)	(6,817.7)	(13,040.1)	(23,662.4)
Total revenues		(4,050.7)	(6,817.7)	(13,040.1)	(23,662.4)
Equity in income (loss) of unconsolidated affiliates		0	0	0	0
Gross operating margin		0	$ 0	0	$ 0
Adjustments [Member]
Information by business segment [Abstract]
Property, plant and equipment, net (see Note 6)		3,777.2		3,777.2		2,754.7
Investments in unconsolidated affiliates (see Note 7)		0		0		0
Intangible assets, net (see Note 9)		0		0		0
Goodwill (see Note 9)		0		0		0
Segment assets		$ 3,777.2		$ 3,777.2		$ 2,754.7
[1]	Our intangible assets classified within the Offshore Pipelines & Services segment were sold to Genesis in July 2015 (see Note 6).

Business Segments, Consolidated

Business Segments, Consolidated Revenues and Expenses (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Consolidated Revenues [Abstract]
Total consolidated revenues		$ 6,307.9	$ 12,330.2	$ 20,872.9	$ 37,760.9
Operating costs and expenses:
Cost of sales	[1]	4,419.9	10,455.1	15,355.9	32,213.1
Other operating costs and expenses	[2]	642.5	633.9	1,834.8	1,865.6
Depreciation, amortization and accretion		351.1	322.7	1,082	936.5
Net losses (gains) attributable to asset sales and insurance recoveries		12.3	(2.6)	14.7	(99)
Non-cash asset impairment charges		26.8	5.7	139.1	18.2
General and administrative costs		49	50	143.2	150.9
Total consolidated costs and expenses		5,501.6	11,464.8	18,569.7	35,085.3
NGL Pipelines and Services [Member]
Consolidated Revenues [Abstract]
Sales of NGLs and related products		1,844.9	3,603.4	5,936.2	12,029.8
Midstream services		441.9	423.3	1,293	1,197.6
Total consolidated revenues		2,286.8	4,026.7	7,229.2	13,227.4
Crude Oil Pipelines & Services [Member]
Consolidated Revenues [Abstract]
Sales of crude oil		2,147.3	5,348.2	7,689.3	16,003.5
Midstream services		175.3	88.9	399.7	264.2
Total consolidated revenues		2,322.6	5,437.1	8,089	16,267.7
Natural Gas Pipelines & Services [Member]
Consolidated Revenues [Abstract]
Sales of natural gas		455	775.5	1,361.2	2,515.7
Midstream services		254.7	256.4	767.1	761.8
Total consolidated revenues		709.7	1,031.9	2,128.3	3,277.5
Petrochemical and Refined Products Services [Member]
Consolidated Revenues [Abstract]
Sales of petrochemicals and refined products		780.5	1,605.4	2,764.2	4,338.2
Midstream services		199.5	186.6	583.4	531.7
Total consolidated revenues		980	1,792	3,347.6	4,869.9
Offshore Pipelines And Services [Member]
Consolidated Revenues [Abstract]
Sales of natural gas		0	0	0	0.2
Sales of crude oil		0.4	2.5	3.2	7.5
Midstream services		8.4	40	75.6	110.7
Total consolidated revenues		$ 8.8	$ 42.5	$ 78.8	$ 118.4
[1]	Cost of sales is a component of "Operating costs and expenses" as presented on our Unaudited Condensed Statements of Consolidated Operations. Fluctuations in these amounts are primarily due to changes in energy commodity prices and sales volumes associated with our marketing activities.
[2]	Represents cost of operating our plants, pipelines and other fixed assets, excluding depreciation, amortization and accretion charges.

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ / shares in Units, $ in Millions	Nov. 06, 2015	Sep. 30, 2015	Mar. 31, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Revenues - related parties:
Total revenue - related parties		$ 13.9		$ 11	$ 27.3	$ 63.8
Costs and expenses - related parties:
Total costs and expenses - related parties		312.9		248.6	869.2	826.4
Accounts receivable - related parties:
Total accounts receivable - related parties		1.7			1.7		$ 2.8
Accounts payable - related parties:
Total accounts payable - related parties		80.3			80.3		118.9
Related Party Transactions [Abstract]
Operating costs and expenses		284.7		216.7	783.9	735.5
General and administrative expenses		28.2		31.9	85.3	90.9
Relationship with Affiliates [Abstract]
Net cash proceeds from the issuance of common units					$ 1,011.4	$ 304.9
2013 At-the-Market Registration [Member]
Relationship with Affiliates [Abstract]
Number of common units issued (in units)					23,258,453	1,590,334
Net cash proceeds from the issuance of common units					$ 759.7	$ 57.7
Distribution Reinvestment Plan [Member]
Relationship with Affiliates [Abstract]
Number of common units issued (in units)					7,965,318	7,148,778
Net cash proceeds from the issuance of common units					$ 242.8	$ 239.8
EPCO and its privately held affiliates [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties		246		212.8	703.9	688
Accounts payable - related parties:
Total accounts payable - related parties		$ 64.6			64.6		98.1
Distributions:
Total cash distributions					$ 705.9	$ 652.8
Relationship with Affiliates [Abstract]
Total Number of Units (in units)		675,259,617			675,259,617
Percentage of Total Units Outstanding (in hundredths)		33.70%			33.70%
Number of Designated Units excluded from distributions (in units)					35,380,000	45,120,000
Enterprise common units pledged as security (in units)		118,000,000			118,000,000
EPCO and its privately held affiliates [Member] | 2013 At-the-Market Registration [Member]
Relationship with Affiliates [Abstract]
Number of common units issued (in units)			3,225,057		3,225,057
Offering price of common unit (in dollars per unit)			$ 31.01
Net cash proceeds from the issuance of common units					$ 100
EPCO and its privately held affiliates [Member] | Distribution Reinvestment Plan [Member]
Relationship with Affiliates [Abstract]
Net cash proceeds from the issuance of common units	$ 50				50	$ 75
EPCO and its privately held affiliates [Member] | Administrative Services Agreement [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties		$ 241.7		208.6	691	676.1
Related Party Transactions [Abstract]
Operating costs and expenses		215.3		179	612.2	591.6
General and administrative expenses		26.4		29.6	78.8	84.5
Unconsolidated affiliates [Member]
Revenues - related parties:
Total revenue - related parties		13.9		11	27.3	63.8
Costs and expenses - related parties:
Total costs and expenses - related parties		66.9		$ 35.8	165.3	$ 138.4
Accounts receivable - related parties:
Total accounts receivable - related parties		1.7			1.7		2.8
Accounts payable - related parties:
Total accounts payable - related parties		$ 15.7			$ 15.7		$ 20.8

Earnings Per Unit (Details)

Earnings Per Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
BASIC EARNINGS PER UNIT
Net income attributable to limited partners		$ 649.3	$ 691.1	$ 1,836.4	$ 2,127.6
Undistributed earnings allocated and cash payments on phantom unit awards	[1]	(2.2)	(1.3)	(6.6)	(4)
Net income available to common unitholders		$ 647.1	$ 689.8	$ 1,829.8	$ 2,123.6
Basic weighted-average number of common units outstanding (in units)		1,969.3	1,834.2	1,952.3	1,831.1
Basic earnings per unit (in dollars per unit)		$ 0.33	$ 0.38	$ 0.94	$ 1.16
DILUTED EARNINGS PER UNIT
Net income attributable to limited partners		$ 649.3	$ 691.1	$ 1,836.4	$ 2,127.6
Diluted weighted-average number of units outstanding:
Distribution-bearing common units (in units)		1,969.3	1,834.2	1,952.3	1,831.1
Designated Units (in units)		35.4	45.1	35.4	45.1
Phantom units (in units)	[1]	5.7	3.4	5.4	2.8
Incremental option units (in units)		0.1	0.7	0.2	1
Total (in units)		2,010.5	1,883.4	1,993.3	1,880
Diluted earnings per unit (in dollars per unit)		$ 0.32	$ 0.37	$ 0.92	$ 1.13
[1]	Each phantom unit award includes a DER, which entitles the recipient to receive cash payments equal to the product of the number of phantom unit awards and the cash distribution per unit paid to our common unitholders. Cash payments made in connection with DERs are nonforfeitable. As a result, the phantom units are considered participating securities for purposes of computing basic earnings per unit. Phantom unit awards were first issued in February 2014.

Commitments and Contingencies (

Commitments and Contingencies (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Operating lease obligations [Abstract]
Lease and rental expense included in costs and expenses	$ 28.8	$ 23.5	$ 76.4	$ 69.2
Litigation matters [Member]
Loss Contingencies [Line Items]
Litigation accruals on an undiscounted basis	4.6		4.6		$ 2.4
Litigation matters [Member] | ETP Lawsuit [Member]
Loss Contingencies [Line Items]
Loss contingency, damages awarded			319.4
Loss contingency, total damages sought			535.8
Loss contingency, disgorgement damages sought			150
Prejudgment interest			$ 66.4
Post-judgment interest rate (in hundredths)			5.00%
EFS Midstream Contract with Producers [Member]
Contractual obligation [Line Items]
Contractual obligation	$ 270		$ 270
Contract term (in years)			10 years

Commitments and Contingencies,

Commitments and Contingencies, Liquidity Option Agreement (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014	Oct. 02, 2014
Liquidity Option Agreement [Abstract]
Liquidity Option Agreement	$ 235.5		$ 235.5		$ 219.7	$ 119.4
Business Acquisition [Line Items]
Purchase price adjustment to goodwill			1,454.1
Change in fair value of Liquidity Option Agreement (see Note 15)	$ 4.3	$ 0	$ 15.8	$ 0
Liquidity Option Agreement [Member] | Maximum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, Expected life of OTA following option exercise (in years)			30 years
Liquidity Option Agreement [Member] | Minimum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, Expected life of OTA following option exercise (in years)			1 year
Oiltanking Partners L.P. - Step 1 [Member]
Business Acquisition [Line Items]
Liquidity Option Agreement valuation adjustment					100.3
Purchase price adjustment to goodwill					$ 100.3

Supplemental Cash Flow Inform78

Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	9 Months Ended		12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Decrease (increase) in:
Accounts receivable - trade	$ 1,042.5	$ 153.6
Accounts receivable - related parties	1.2	4
Inventories	(143.2)	(536.9)
Prepaid and other current assets	(32.7)	(44.5)
Other assets	2.1	20
Increase (decrease) in:
Accounts payable - trade	(72.7)	(14.2)
Accounts payable - related parties	(38.6)	(27.7)
Accrued product payables	(1,248.4)	(13.1)
Accrued interest	(136.7)	(131.7)
Other current liabilities	(13.8)	143.5
Other liabilities	12.4	11.2
Net effect of changes in operating accounts	(627.9)	(435.8)
Liability for construction in progress expenditures	495.1		$ 372.8
Accrued liability related to EFS Midstream acquisition (see Note 8)	997.7		$ 0
Significant Disposals [Line Items]
Proceeds from asset sales and insurance recoveries	1,537.3	121.5
Net gains (losses) attributable to asset sales and insurance recoveries	(14.7)	99
West Storage Facilities [Member]
Significant Disposals [Line Items]
Proceeds from asset sales and insurance recoveries	0	95
Net gains (losses) attributable to asset sales and insurance recoveries	0	95
Offshore Business [Member]
Significant Disposals [Line Items]
Proceeds from asset sales and insurance recoveries	1,528.6	0
Net gains (losses) attributable to asset sales and insurance recoveries	(12.6)	0
Other Disposal of Assets [Member]
Significant Disposals [Line Items]
Proceeds from asset sales and insurance recoveries	8.7	26.5
Net gains (losses) attributable to asset sales and insurance recoveries	$ (2.1)	$ 4

Condensed Consolidating Finan79

Condensed Consolidating Financial Information, Balance Sheet (Details) - USD ($) $ in Millions		Sep. 30, 2015	Dec. 31, 2014	Sep. 30, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents and restricted cash		$ 126.7	$ 74.4
Accounts receivable - trade, net		2,802	3,823
Accounts receivable - related parties		1.7	2.8
Inventories		1,085.4	1,014.2
Derivative assets		241.8	226
Prepaid and other current assets		402.4	350.3
Total current assets		4,660	5,490.7
Property, plant and equipment, net		31,214.1	29,881.6
Investments in unconsolidated affiliates		2,625.3	3,042
Intangible assets, net		4,082.1	4,302.1
Goodwill		5,749.2	4,300.2
Other assets		197.1	184.4
Total assets		48,527.8	47,201
Current liabilities:
Current maturities of debt	[1]	1,619.4	2,206.4
Accounts payable - trade		844.9	773.8
Accounts payable - related parties		80.3	118.9
Accrued product payables		2,547.9	3,853.3
Accrued liability related to EFS Midstream acquisition		997.7	0
Accrued interest		198.9	335.5
Other current liabilities		589.8	585.8
Total current liabilities		6,878.9	7,873.7
Long-term debt		20,840.7	19,157.4
Deferred tax liabilities		53.4	66.6
Other long-term liabilities		$ 401.9	$ 411.1
Commitments and contingencies
Equity:
Partners' and other owners' equity		$ 20,162.1	$ 18,063.2
Noncontrolling interests		190.8	1,629
Total equity		20,352.9	19,692.2	$ 15,981.9	$ 15,440.4
Total liabilities and equity		48,527.8	47,201
Eliminations and Adjustments [Member]
Current assets:
Cash and cash equivalents and restricted cash		0	0
Accounts receivable - trade, net		0	0
Accounts receivable - related parties		(0.7)	(4)
Inventories		0	0
Derivative assets		0	0
Prepaid and other current assets		0	0.8
Total current assets		(0.7)	(3.2)
Property, plant and equipment, net		0	0
Investments in unconsolidated affiliates		(20,397.5)	(18,287.5)
Intangible assets, net		0	0
Goodwill		0	0
Other assets		0	0
Total assets		(20,398.2)	(18,290.7)
Current liabilities:
Current maturities of debt		0	0
Accounts payable - trade		0	0
Accounts payable - related parties		(0.7)	(4)
Accrued product payables		0	0
Accrued liability related to EFS Midstream acquisition		0
Accrued interest		0	0
Other current liabilities		0.5	0
Total current liabilities		(0.2)	(4)
Long-term debt		0	0
Deferred tax liabilities		3.8	4.1
Other long-term liabilities		$ 0	$ 0
Commitments and contingencies
Equity:
Partners' and other owners' equity		$ (20,373.1)	$ (18,263.7)
Noncontrolling interests		(28.7)	(27.1)
Total equity		(20,401.8)	(18,290.8)
Total liabilities and equity		(20,398.2)	(18,290.7)
Subsidiary Issuer (EPO) [Member]
Current assets:
Cash and cash equivalents and restricted cash		46.9	18.7
Accounts receivable - trade, net		791	1,128.5
Accounts receivable - related parties		123.1	158.8
Inventories		889.1	831.8
Derivative assets		139.1	102
Prepaid and other current assets		164.7	435.7
Total current assets		2,153.9	2,675.5
Property, plant and equipment, net		3,432.3	2,871.7
Investments in unconsolidated affiliates		38,310	36,937.5
Intangible assets, net		726.8	2,527.3
Goodwill		459.1	1,956.1
Other assets		226.4	139.3
Total assets		45,308.5	47,107.4
Current liabilities:
Current maturities of debt		1,619.3	2,206.4
Accounts payable - trade		331.4	216.6
Accounts payable - related parties		866.7	1,226.5
Accrued product payables		938	1,570
Accrued liability related to EFS Midstream acquisition		0
Accrued interest		198.6	335.4
Other current liabilities		174.3	130.8
Total current liabilities		4,128.3	5,685.7
Long-term debt		20,825.4	19,142.5
Deferred tax liabilities		3.2	4.9
Other long-term liabilities		$ 10.6	$ 10.9
Commitments and contingencies
Equity:
Partners' and other owners' equity		$ 20,341	$ 22,263.4
Noncontrolling interests		0	0
Total equity		20,341	22,263.4
Total liabilities and equity		45,308.5	47,107.4
Other Subsidiaries (Non-guarantor) [Member]
Current assets:
Cash and cash equivalents and restricted cash		85.3	70.4
Accounts receivable - trade, net		2,011.3	2,698.2
Accounts receivable - related parties		780.8	1,114.6
Inventories		196.6	182.8
Derivative assets		102.7	124
Prepaid and other current assets		247.7	222.3
Total current assets		3,424.4	4,412.3
Property, plant and equipment, net		27,780.4	26,912
Investments in unconsolidated affiliates		4,094.7	3,556.4
Intangible assets, net		3,370.1	1,292.4
Goodwill		5,290.1	1,721.4
Other assets		49	45.8
Total assets		44,008.7	37,940.3
Current liabilities:
Current maturities of debt		0.1	0
Accounts payable - trade		519	571.4
Accounts payable - related parties		130.1	173.3
Accrued product payables		1,611.2	2,287.9
Accrued liability related to EFS Midstream acquisition		997.7
Accrued interest		0.3	0.7
Other current liabilities		425.1	763.7
Total current liabilities		3,683.5	3,797
Long-term debt		15.3	14.9
Deferred tax liabilities		47.4	58.5
Other long-term liabilities		$ 234.3	$ 180.8
Commitments and contingencies
Equity:
Partners' and other owners' equity		$ 39,986.1	$ 33,820.9
Noncontrolling interests		42.1	68.2
Total equity		40,028.2	33,889.1
Total liabilities and equity		44,008.7	37,940.3
Consolidated EPO and Subsidiaries [Member]
Current assets:
Cash and cash equivalents and restricted cash		126.7	74.4
Accounts receivable - trade, net		2,802	3,823
Accounts receivable - related parties		2.4	6.8
Inventories		1,085.4	1,014.2
Derivative assets		241.8	226
Prepaid and other current assets		402.2	349.5
Total current assets		4,660.5	5,493.9
Property, plant and equipment, net		31,214.1	29,881.6
Investments in unconsolidated affiliates		2,625.3	3,042
Intangible assets, net		4,082.1	4,302.1
Goodwill		5,749.2	4,300.2
Other assets		196.6	184.4
Total assets		48,527.8	47,204.2
Current liabilities:
Current maturities of debt		1,619.4	2,206.4
Accounts payable - trade		844.9	773.2
Accounts payable - related parties		80.3	118.9
Accrued product payables		2,547.9	3,853.3
Accrued liability related to EFS Midstream acquisition		997.7
Accrued interest		198.9	335.5
Other current liabilities		589.4	585.8
Total current liabilities		6,878.5	7,873.1
Long-term debt		20,840.7	19,157.4
Deferred tax liabilities		49.6	62.5
Other long-term liabilities		$ 166.4	$ 191.4
Commitments and contingencies
Equity:
Partners' and other owners' equity		$ 20,373.1	$ 18,263.7
Noncontrolling interests		219.5	1,656.1
Total equity		20,592.6	19,919.8
Total liabilities and equity		48,527.8	47,204.2
Consolidated EPO and Subsidiaries [Member] | Eliminations and Adjustments [Member]
Current assets:
Cash and cash equivalents and restricted cash		(5.5)	(14.7)
Accounts receivable - trade, net		(0.3)	(3.7)
Accounts receivable - related parties		(901.5)	(1,266.6)
Inventories		(0.3)	(0.4)
Derivative assets		0	0
Prepaid and other current assets		(10.2)	(308.5)
Total current assets		(917.8)	(1,593.9)
Property, plant and equipment, net		1.4	97.9
Investments in unconsolidated affiliates		(39,779.4)	(37,451.9)
Intangible assets, net		(14.8)	482.4
Goodwill		0	622.7
Other assets		(78.8)	(0.7)
Total assets		(40,789.4)	(37,843.5)
Current liabilities:
Current maturities of debt		0	0
Accounts payable - trade		(5.5)	(14.8)
Accounts payable - related parties		(916.5)	(1,280.9)
Accrued product payables		(1.3)	(4.6)
Accrued liability related to EFS Midstream acquisition		0
Accrued interest		0	(0.6)
Other current liabilities		(10)	(308.7)
Total current liabilities		(933.3)	(1,609.6)
Long-term debt		0	0
Deferred tax liabilities		(1)	(0.9)
Other long-term liabilities		$ (78.5)	$ (0.3)
Commitments and contingencies
Equity:
Partners' and other owners' equity		$ (39,954)	$ (37,820.6)
Noncontrolling interests		177.4	1,587.9
Total equity		(39,776.6)	(36,232.7)
Total liabilities and equity		(40,789.4)	(37,843.5)
Enterprise Products Partners L.P. (Guarantor) [Member]
Current assets:
Cash and cash equivalents and restricted cash		0	0
Accounts receivable - trade, net		0	0
Accounts receivable - related parties		0	0
Inventories		0	0
Derivative assets		0	0
Prepaid and other current assets		0.2	0
Total current assets		0.2	0
Property, plant and equipment, net		0	0
Investments in unconsolidated affiliates		20,397.5	18,287.5
Intangible assets, net		0	0
Goodwill		0	0
Other assets		0.5	0
Total assets		20,398.2	18,287.5
Current liabilities:
Current maturities of debt		0	0
Accounts payable - trade		0	0.6
Accounts payable - related parties		0.7	4
Accrued product payables		0	0
Accrued liability related to EFS Midstream acquisition		0
Accrued interest		0	0
Other current liabilities		(0.1)	0
Total current liabilities		0.6	4.6
Long-term debt		0	0
Deferred tax liabilities		0	0
Other long-term liabilities		$ 235.5	$ 219.7
Commitments and contingencies
Equity:
Partners' and other owners' equity		$ 20,162.1	$ 18,063.2
Noncontrolling interests		0	0
Total equity		20,162.1	18,063.2
Total liabilities and equity		$ 20,398.2	$ 18,287.5
[1]	We expect to refinance the current maturities of our debt obligations at or prior to their maturity.

Condensed Consolidating Finan80

Condensed Consolidating Financial Information, Statement of Operations (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Condensed Consolidating Statement of Operations
Revenues	$ 6,307.9	$ 12,330.2	$ 20,872.9	$ 37,760.9
Costs and expenses:
Operating costs and expenses	5,452.6	11,414.8	18,426.5	34,934.4
General and administrative costs	49	50	143.2	150.9
Total costs and expenses	5,501.6	11,464.8	18,569.7	35,085.3
Equity in income of unconsolidated affiliates	103.1	72.3	302.5	179.1
Operating income	909.4	937.7	2,605.7	2,854.7
Other income (expense):
Interest expense	(243.7)	(229.8)	(723.2)	(679.6)
Other, net	(2.5)	(1)	(13.2)	(0.2)
Total other expense, net	(246.2)	(230.8)	(736.4)	(679.8)
Income before income taxes	663.2	706.9	1,869.3	2,174.9
Provision for income taxes	(5.5)	(7.7)	(4.4)	(22.5)
Net income	657.7	699.2	1,864.9	2,152.4
Net loss (income) attributable to noncontrolling interests	(8.4)	(8.1)	(28.5)	(24.8)
Net income attributable to entity	649.3	691.1	1,836.4	2,127.6
Eliminations and Adjustments [Member]
Condensed Consolidating Statement of Operations
Revenues	0	0	0	0
Costs and expenses:
Operating costs and expenses	0	0	0	0
General and administrative costs	0	0	0	0
Total costs and expenses	0	0	0	0
Equity in income of unconsolidated affiliates	(653.2)	(692.5)	(1,852.6)	(2,129.4)
Operating income	(653.2)	(692.5)	(1,852.6)	(2,129.4)
Other income (expense):
Interest expense	0	0	0	0
Other, net	0	0	0	0
Total other expense, net	0	0	0	0
Income before income taxes	(653.2)	(692.5)	(1,852.6)	(2,129.4)
Provision for income taxes	0	(0.9)	(0.9)	(1.4)
Net income	(653.2)	(693.4)	(1,853.5)	(2,130.8)
Net loss (income) attributable to noncontrolling interests	1.3	1.3	3.6	3.8
Net income attributable to entity	(651.9)	(692.1)	(1,849.9)	(2,127)
Subsidiary Issuer (EPO) [Member]
Condensed Consolidating Statement of Operations
Revenues	4,685.2	8,121.5	15,301	25,190.1
Costs and expenses:
Operating costs and expenses	4,506.7	7,950.9	14,696.2	24,516.6
General and administrative costs	11.1	8.2	28.9	23.1
Total costs and expenses	4,517.8	7,959.1	14,725.1	24,539.7
Equity in income of unconsolidated affiliates	725.5	762.5	1,996.4	2,169.5
Operating income	892.9	924.9	2,572.3	2,819.9
Other income (expense):
Interest expense	(239.5)	(229.2)	(717.9)	(678.6)
Other, net	1.7	0.2	4	0.7
Total other expense, net	(237.8)	(229)	(713.9)	(677.9)
Income before income taxes	655.1	695.9	1,858.4	2,142
Provision for income taxes	(3.3)	(4)	(8.9)	(15.5)
Net income	651.8	691.9	1,849.5	2,126.5
Net loss (income) attributable to noncontrolling interests	0	0	0	0
Net income attributable to entity	651.8	691.9	1,849.5	2,126.5
Other Subsidiaries (Non-guarantor) [Member]
Condensed Consolidating Statement of Operations
Revenues	4,531.1	8,598.2	14,751	25,859.9
Costs and expenses:
Operating costs and expenses	3,854.5	7,853.5	12,909.8	23,707.6
General and administrative costs	38.3	40.4	113.9	126
Total costs and expenses	3,892.8	7,893.9	13,023.7	23,833.6
Equity in income of unconsolidated affiliates	116.5	94.4	314.5	256.1
Operating income	754.8	798.7	2,041.8	2,282.4
Other income (expense):
Interest expense	(4.2)	(0.6)	(7.3)	(1)
Other, net	0.1	(1.2)	0.6	(0.9)
Total other expense, net	(4.1)	(1.8)	(6.7)	(1.9)
Income before income taxes	750.7	796.9	2,035.1	2,280.5
Provision for income taxes	(2.2)	(2.8)	5.4	(5.8)
Net income	748.5	794.1	2,040.5	2,274.7
Net loss (income) attributable to noncontrolling interests	0	0.1	0.8	0.2
Net income attributable to entity	748.5	794.2	2,041.3	2,274.9
Consolidated EPO and Subsidiaries [Member]
Condensed Consolidating Statement of Operations
Revenues	6,307.9	12,330.2	20,872.9	37,760.9
Costs and expenses:
Operating costs and expenses	5,452.6	11,414.8	18,426.5	34,934.4
General and administrative costs	49.4	48.6	142.8	149.1
Total costs and expenses	5,502	11,463.4	18,569.3	35,083.5
Equity in income of unconsolidated affiliates	103.1	72.3	302.5	179.1
Operating income	909	939.1	2,606.1	2,856.5
Other income (expense):
Interest expense	(243.7)	(229.8)	(723.2)	(679.6)
Other, net	1.8	(1)	2.6	(0.2)
Total other expense, net	(241.9)	(230.8)	(720.6)	(679.8)
Income before income taxes	667.1	708.3	1,885.5	2,176.7
Provision for income taxes	(5.5)	(6.8)	(3.5)	(21.1)
Net income	661.6	701.5	1,882	2,155.6
Net loss (income) attributable to noncontrolling interests	(9.7)	(9.4)	(32.1)	(28.6)
Net income attributable to entity	651.9	692.1	1,849.9	2,127
Consolidated EPO and Subsidiaries [Member] | Eliminations and Adjustments [Member]
Condensed Consolidating Statement of Operations
Revenues	(2,908.4)	(4,389.5)	(9,179.1)	(13,289.1)
Costs and expenses:
Operating costs and expenses	(2,908.6)	(4,389.6)	(9,179.5)	(13,289.8)
General and administrative costs	0	0	0	0
Total costs and expenses	(2,908.6)	(4,389.6)	(9,179.5)	(13,289.8)
Equity in income of unconsolidated affiliates	(738.9)	(784.6)	(2,008.4)	(2,246.5)
Operating income	(738.7)	(784.5)	(2,008)	(2,245.8)
Other income (expense):
Interest expense	0	0	2	0
Other, net	0	0	(2)	0
Total other expense, net	0	0	0	0
Income before income taxes	(738.7)	(784.5)	(2,008)	(2,245.8)
Provision for income taxes	0	0	0	0.2
Net income	(738.7)	(784.5)	(2,008)	(2,245.6)
Net loss (income) attributable to noncontrolling interests	(9.7)	(9.5)	(32.9)	(28.8)
Net income attributable to entity	(748.4)	(794)	(2,040.9)	(2,274.4)
Enterprise Products Partners L.P. (Guarantor) [Member]
Condensed Consolidating Statement of Operations
Revenues	0	0	0	0
Costs and expenses:
Operating costs and expenses	0	0	0	0
General and administrative costs	(0.4)	1.4	0.4	1.8
Total costs and expenses	(0.4)	1.4	0.4	1.8
Equity in income of unconsolidated affiliates	653.2	692.5	1,852.6	2,129.4
Operating income	653.6	691.1	1,852.2	2,127.6
Other income (expense):
Interest expense	0	0	0	0
Other, net	(4.3)	0	(15.8)	0
Total other expense, net	(4.3)	0	(15.8)	0
Income before income taxes	649.3	691.1	1,836.4	2,127.6
Provision for income taxes	0	0	0	0
Net income	649.3	691.1	1,836.4	2,127.6
Net loss (income) attributable to noncontrolling interests	0	0	0	0
Net income attributable to entity	$ 649.3	$ 691.1	$ 1,836.4	$ 2,127.6

Condensed Consolidating Finan81

Condensed Consolidating Financial Information, Statement of Comprehensive Income (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Condensed Consolidating Statement of Comprehensive Income
Comprehensive income	$ 705.6	$ 747.3	$ 1,875.8	$ 2,205.3
Comprehensive loss (income) attributable to noncontrolling interests	(8.4)	(8.1)	(28.5)	(24.8)
Comprehensive income attributable to entity	697.2	739.2	1,847.3	2,180.5
Eliminations and Adjustments [Member]
Condensed Consolidating Statement of Comprehensive Income
Comprehensive income	(701)	(741.5)	(1,864.3)	(2,183.7)
Comprehensive loss (income) attributable to noncontrolling interests	1.3	1.3	3.6	3.8
Comprehensive income attributable to entity	(699.7)	(740.2)	(1,860.7)	(2,179.9)
Subsidiary Issuer (EPO) [Member]
Condensed Consolidating Statement of Comprehensive Income
Comprehensive income	676	708.9	1,869.9	2,161.8
Comprehensive loss (income) attributable to noncontrolling interests	0	0	0	0
Comprehensive income attributable to entity	676	708.9	1,869.9	2,161.8
Other Subsidiaries (Non-guarantor) [Member]
Condensed Consolidating Statement of Comprehensive Income
Comprehensive income	797.3	825.2	2,056.1	2,292.2
Comprehensive loss (income) attributable to noncontrolling interests	0	0.1	0.8	0.2
Comprehensive income attributable to entity	797.3	825.3	2,056.9	2,292.4
Consolidated EPO and Subsidiaries [Member]
Condensed Consolidating Statement of Comprehensive Income
Comprehensive income	709.4	749.6	1,892.8	2,208.5
Comprehensive loss (income) attributable to noncontrolling interests	(9.7)	(9.4)	(32.1)	(28.6)
Comprehensive income attributable to entity	699.7	740.2	1,860.7	2,179.9
Consolidated EPO and Subsidiaries [Member] | Eliminations and Adjustments [Member]
Condensed Consolidating Statement of Comprehensive Income
Comprehensive income	(763.9)	(784.5)	(2,033.2)	(2,245.5)
Comprehensive loss (income) attributable to noncontrolling interests	(9.7)	(9.5)	(32.9)	(28.8)
Comprehensive income attributable to entity	(773.6)	(794)	(2,066.1)	(2,274.3)
Enterprise Products Partners L.P. (Guarantor) [Member]
Condensed Consolidating Statement of Comprehensive Income
Comprehensive income	697.2	739.2	1,847.3	2,180.5
Comprehensive loss (income) attributable to noncontrolling interests	0	0	0	0
Comprehensive income attributable to entity	$ 697.2	$ 739.2	$ 1,847.3	$ 2,180.5

Condensed Consolidating Finan82

Condensed Consolidating Financial Information, Statement of Cash Flows (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Operating activities:
Net income	$ 657.7	$ 699.2	$ 1,864.9	$ 2,152.4
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion			1,147.7	992.4
Equity in income of unconsolidated affiliates	(103.1)	(72.3)	(302.5)	(179.1)
Distributions received from unconsolidated affiliates			362.4	260.7
Net effect of changes in operating accounts and other operating activities			(481.3)	(522)
Net cash flows provided by operating activities			2,591.2	2,704.4
Investing activities:
Capital expenditures, net of contributions in aid of construction costs			(2,619.1)	(1,859.5)
Cash used for business combinations, net of cash received			(1,045.1)	0
Proceeds from asset sales and insurance recoveries			1,537.3	121.5
Other investing activities			(181.3)	(530.1)
Cash used in investing activities			(2,308.2)	(2,268.1)
Financing activities:
Borrowings under debt agreements			17,113.7	7,167.5
Repayments of debt			(16,139.2)	(4,856.3)
Cash distributions paid to partners			(2,185.1)	(1,948.2)
Cash payments made in connection with DERs			(5.6)	(2.4)
Cash distributions paid to noncontrolling interests			(33.2)	(29.4)
Cash contributions from noncontrolling interests			37.4	4
Net cash proceeds from issuance of common units			1,011.4	304.9
Cash contributions from owners			0	0
Other financing activities			(76.3)	(71.7)
Cash provided by (used in) financing activities			(276.9)	568.4
Net change in cash and cash equivalents			6.1	1,004.7
Cash and cash equivalents, beginning balance			74.4	56.9
Cash and cash equivalents, ending balance	80.5	1,061.6	80.5	1,061.6
Eliminations and Adjustments [Member]
Operating activities:
Net income	(653.2)	(693.4)	(1,853.5)	(2,130.8)
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion			0	0
Equity in income of unconsolidated affiliates	653.2	692.5	1,852.6	2,129.4
Distributions received from unconsolidated affiliates			(2,241.1)	(2,007.4)
Net effect of changes in operating accounts and other operating activities			0.9	1.4
Net cash flows provided by operating activities			(2,241.1)	(2,007.4)
Investing activities:
Capital expenditures, net of contributions in aid of construction costs			0	0
Cash used for business combinations, net of cash received			0
Proceeds from asset sales and insurance recoveries			0	0
Other investing activities			1,005.2	300.7
Cash used in investing activities			1,005.2	300.7
Financing activities:
Borrowings under debt agreements			0	0
Repayments of debt			0	0
Cash distributions paid to partners			2,241.1	2,007.4
Cash payments made in connection with DERs			0	0
Cash distributions paid to noncontrolling interests			0	0
Cash contributions from noncontrolling interests			0	0
Net cash proceeds from issuance of common units			0	0
Cash contributions from owners			(1,005.2)	(300.7)
Other financing activities			0	0
Cash provided by (used in) financing activities			1,235.9	1,706.7
Net change in cash and cash equivalents			0	0
Cash and cash equivalents, beginning balance			0	0
Cash and cash equivalents, ending balance	0	0	0	0
Subsidiary Issuer (EPO) [Member]
Operating activities:
Net income	651.8	691.9	1,849.5	2,126.5
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion			106	114.3
Equity in income of unconsolidated affiliates	(725.5)	(762.5)	(1,996.4)	(2,169.5)
Distributions received from unconsolidated affiliates			1,705.4	3,475.8
Net effect of changes in operating accounts and other operating activities			(52.9)	(764.6)
Net cash flows provided by operating activities			1,611.6	2,782.5
Investing activities:
Capital expenditures, net of contributions in aid of construction costs			(725.5)	(329.1)
Cash used for business combinations, net of cash received			(1,058.4)
Proceeds from asset sales and insurance recoveries			1,532.1	4.2
Other investing activities			(1,091.2)	(2,059.3)
Cash used in investing activities			(1,343)	(2,384.2)
Financing activities:
Borrowings under debt agreements			17,113.7	7,167.5
Repayments of debt			(16,139.2)	(4,856.3)
Cash distributions paid to partners			(2,241.1)	(2,007.4)
Cash payments made in connection with DERs			0	0
Cash distributions paid to noncontrolling interests			0	0
Cash contributions from noncontrolling interests			0	0
Net cash proceeds from issuance of common units			0	0
Cash contributions from owners			1,005.2	300.7
Other financing activities			(23.9)	(18.1)
Cash provided by (used in) financing activities			(285.3)	586.4
Net change in cash and cash equivalents			(16.7)	984.7
Cash and cash equivalents, beginning balance			18.7	28.4
Cash and cash equivalents, ending balance	2	1,013.1	2	1,013.1
Other Subsidiaries (Non-guarantor) [Member]
Operating activities:
Net income	748.5	794.1	2,040.5	2,274.7
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion			1,042.1	878.5
Equity in income of unconsolidated affiliates	(116.5)	(94.4)	(314.5)	(256.1)
Distributions received from unconsolidated affiliates			227.1	229
Net effect of changes in operating accounts and other operating activities			(450.6)	230.1
Net cash flows provided by operating activities			2,544.6	3,356.2
Investing activities:
Capital expenditures, net of contributions in aid of construction costs			(1,893.6)	(1,530.4)
Cash used for business combinations, net of cash received			13.3
Proceeds from asset sales and insurance recoveries			5.2	117.3
Other investing activities			(43.5)	(526.9)
Cash used in investing activities			(1,918.6)	(1,940)
Financing activities:
Borrowings under debt agreements			77.9	0
Repayments of debt			0	0
Cash distributions paid to partners			(1,602.4)	(3,473.6)
Cash payments made in connection with DERs			0	0
Cash distributions paid to noncontrolling interests			(0.8)	0
Cash contributions from noncontrolling interests			37.8	0
Net cash proceeds from issuance of common units			0	0
Cash contributions from owners			875.1	2,060
Other financing activities			0	0
Cash provided by (used in) financing activities			(612.4)	(1,413.6)
Net change in cash and cash equivalents			13.6	2.6
Cash and cash equivalents, beginning balance			70.4	49.5
Cash and cash equivalents, ending balance	84	52.1	84	52.1
Consolidated EPO and Subsidiaries [Member]
Operating activities:
Net income	661.6	701.5	1,882	2,155.6
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion			1,147.7	992.4
Equity in income of unconsolidated affiliates	(103.1)	(72.3)	(302.5)	(179.1)
Distributions received from unconsolidated affiliates			362.4	260.7
Net effect of changes in operating accounts and other operating activities			(494.2)	(517.8)
Net cash flows provided by operating activities			2,595.4	2,711.8
Investing activities:
Capital expenditures, net of contributions in aid of construction costs			(2,619.1)	(1,859.5)
Cash used for business combinations, net of cash received			(1,045.1)
Proceeds from asset sales and insurance recoveries			1,537.3	121.5
Other investing activities			(181.3)	(530.1)
Cash used in investing activities			(2,308.2)	(2,268.1)
Financing activities:
Borrowings under debt agreements			17,113.7	7,167.5
Repayments of debt			(16,139.2)	(4,856.3)
Cash distributions paid to partners			(2,241.1)	(2,007.4)
Cash payments made in connection with DERs			0	0
Cash distributions paid to noncontrolling interests			(33.2)	(29.4)
Cash contributions from noncontrolling interests			37.4	4
Net cash proceeds from issuance of common units			0	0
Cash contributions from owners			1,005.2	300.7
Other financing activities			(23.9)	(18.1)
Cash provided by (used in) financing activities			(281.1)	561
Net change in cash and cash equivalents			6.1	1,004.7
Cash and cash equivalents, beginning balance			74.4	56.9
Cash and cash equivalents, ending balance	80.5	1,061.6	80.5	1,061.6
Consolidated EPO and Subsidiaries [Member] | Eliminations and Adjustments [Member]
Operating activities:
Net income	(738.7)	(784.5)	(2,008)	(2,245.6)
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion			(0.4)	(0.4)
Equity in income of unconsolidated affiliates	738.9	784.6	2,008.4	2,246.5
Distributions received from unconsolidated affiliates			(1,570.1)	(3,444.1)
Net effect of changes in operating accounts and other operating activities			9.3	16.7
Net cash flows provided by operating activities			(1,560.8)	(3,426.9)
Investing activities:
Capital expenditures, net of contributions in aid of construction costs			0	0
Cash used for business combinations, net of cash received			0
Proceeds from asset sales and insurance recoveries			0	0
Other investing activities			953.4	2,056.1
Cash used in investing activities			953.4	2,056.1
Financing activities:
Borrowings under debt agreements			(77.9)	0
Repayments of debt			0	0
Cash distributions paid to partners			1,602.4	3,473.6
Cash payments made in connection with DERs			0	0
Cash distributions paid to noncontrolling interests			(32.4)	(29.4)
Cash contributions from noncontrolling interests			(0.4)	4
Net cash proceeds from issuance of common units			0	0
Cash contributions from owners			(875.1)	(2,060)
Other financing activities			0	0
Cash provided by (used in) financing activities			616.6	1,388.2
Net change in cash and cash equivalents			9.2	17.4
Cash and cash equivalents, beginning balance			(14.7)	(21)
Cash and cash equivalents, ending balance	(5.5)	(3.6)	(5.5)	(3.6)
Enterprise Products Partners L.P. (Guarantor) [Member]
Operating activities:
Net income	649.3	691.1	1,836.4	2,127.6
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion			0	0
Equity in income of unconsolidated affiliates	(653.2)	(692.5)	(1,852.6)	(2,129.4)
Distributions received from unconsolidated affiliates			2,241.1	2,007.4
Net effect of changes in operating accounts and other operating activities			12	(5.6)
Net cash flows provided by operating activities			2,236.9	2,000
Investing activities:
Capital expenditures, net of contributions in aid of construction costs			0	0
Cash used for business combinations, net of cash received			0
Proceeds from asset sales and insurance recoveries			0	0
Other investing activities			(1,005.2)	(300.7)
Cash used in investing activities			(1,005.2)	(300.7)
Financing activities:
Borrowings under debt agreements			0	0
Repayments of debt			0	0
Cash distributions paid to partners			(2,185.1)	(1,948.2)
Cash payments made in connection with DERs			(5.6)	(2.4)
Cash distributions paid to noncontrolling interests			0	0
Cash contributions from noncontrolling interests			0	0
Net cash proceeds from issuance of common units			1,011.4	304.9
Cash contributions from owners			0	0
Other financing activities			(52.4)	(53.6)
Cash provided by (used in) financing activities			(1,231.7)	(1,699.3)
Net change in cash and cash equivalents			0	0
Cash and cash equivalents, beginning balance			0	0
Cash and cash equivalents, ending balance	$ 0	$ 0	$ 0	$ 0