Enterprise Products Partners (EPD) 10-K 26 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Jan. 31, 2016	Jun. 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 Public Float			$ 39,270
Entity Common Stock, Shares Outstanding		2,021,263,324
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 19	$ 74.4
Restricted cash	15.9	0
Accounts receivable - trade, net of allowance for doubtful accounts of $12.1 at December 31, 2015 and $13.9 at December 31, 2014	2,569.9	3,823
Accounts receivable - related parties	1.2	2.8
Inventories	1,038.1	1,014.2
Derivative assets	258.6	226
Prepaid and other current assets	410.3	350.3
Total current assets	4,313	5,490.7
Property, plant and equipment, net	32,034.7	29,881.6
Investments in unconsolidated affiliates	2,628.5	3,042
Intangible assets, net of accumulated amortization of $1,235.8 at December 31, 2015 and $1,246.3 at December 31, 2014	4,037.2	4,302.1
Goodwill	5,745.2	4,300.2
Other assets	193.4	184.4
Total assets	48,952	47,201
Current liabilities:
Current maturities of debt	1,863.9	2,206.4
Accounts payable - trade	860.1	773.8
Accounts payable - related parties	84.1	118.9
Accrued product payables	2,484.4	3,853.3
Accrued liability related to EFS Midstream acquisition	993.2	0
Accrued interest	352.1	335.5
Other current liabilities	528.8	585.8
Total current liabilities	7,166.6	7,873.7
Long-term debt	20,826.7	19,157.4
Deferred tax liabilities	46.1	66.6
Other long-term liabilities	$ 411.5	$ 411.1
Commitments and contingencies
Limited partners:
Common units (2,012,553,024 units outstanding at December 31, 2015 and 1,937,324,817 units outstanding at December 31, 2014)	$ 20,514.3	$ 18,304.8
Accumulated other comprehensive loss	(219.2)	(241.6)
Total partners' equity	20,295.1	18,063.2
Noncontrolling interests	206	1,629
Total equity	20,501.1	19,692.2
Total liabilities and equity	$ 48,952	$ 47,201

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Allowance for doubtful accounts	$ 12.1	$ 13.9
Accumulated amortization	$ 1,235.8	$ 1,246.3
Limited partners:
Capital account, units outstanding (in units)	2,012,553,024	1,937,324,817

STATEMENTS OF CONSOLIDATED OPER

STATEMENTS OF CONSOLIDATED OPERATIONS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues:
Third parties	$ 26,955.6	$ 47,879.7	$ 47,661.1
Related parties	72.3	71.5	65.9
Total revenues	27,027.9	47,951.2	47,727
Operating costs and expenses:
Third parties	22,588.2	43,228.4	43,300.8
Related parties	1,080.5	992.1	937.9
Total operating costs and expenses	23,668.7	44,220.5	44,238.7
General and administrative costs:
Third parties	78.5	83.7	74
Related parties	114.1	130.8	114.3
Total general and administrative costs	192.6	214.5	188.3
Total costs and expenses	23,861.3	44,435	44,427
Equity in income of unconsolidated affiliates	373.6	259.5	167.3
Operating income	3,540.2	3,775.7	3,467.3
Other income (expense):
Interest expense	(961.8)	(921)	(802.5)
Change in fair value of Liquidity Option Agreement	(25.4)	0	0
Other, net	2.9	1.9	(0.2)
Total other expense, net	(984.3)	(919.1)	(802.7)
Income before income taxes	2,555.9	2,856.6	2,664.6
Benefit from (provision for) income taxes	2.5	(23.1)	(57.5)
Net income	2,558.4	2,833.5	2,607.1
Net income attributable to noncontrolling interests	(37.2)	(46.1)	(10.2)
Net income attributable to limited partners	$ 2,521.2	$ 2,787.4	$ 2,596.9
Earnings per unit:
Basic earnings per unit (in dollars per unit)	$ 1.28	$ 1.51	$ 1.45
Diluted earnings per unit (in dollars per unit)	$ 1.26	$ 1.47	$ 1.41

STATEMENTS OF CONSOLIDATED COMP

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
Net income	$ 2,558.4	$ 2,833.5	$ 2,607.1
Commodity derivative instruments:
Changes in fair value of cash flow hedges	214.9	161.3	(46.9)
Reclassification of losses (gains) to net income	(228.2)	(76.7)	22.1
Interest rate derivative instruments:
Changes in fair value of cash flow hedges	0	0	6.6
Reclassification of losses to net income	35.3	32.4	29.2
Total cash flow hedges	22	117	11
Other	0.4	0.4	0.4
Total other comprehensive income	22.4	117.4	11.4
Comprehensive income	2,580.8	2,950.9	2,618.5
Comprehensive income attributable to noncontrolling interests	(37.2)	(46.1)	(10.2)
Comprehensive income attributable to limited partners	$ 2,543.6	$ 2,904.8	$ 2,608.3

STATEMENTS OF CONSOLIDATED CASH

STATEMENTS OF CONSOLIDATED CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating activities:
Net income	$ 2,558.4	$ 2,833.5	$ 2,607.1
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion	1,516	1,360.5	1,217.6
Non-cash asset impairment charges	162.6	34	92.6
Equity in income of unconsolidated affiliates	(373.6)	(259.5)	(167.3)
Distributions received from unconsolidated affiliates	462.1	375.1	251.6
Net losses (gains) attributable to asset sales and insurance recoveries	15.6	(102.1)	(83.3)
Gains on early extinguishment of debt	(1.6)	0	0
Deferred income tax expense (benefit)	(20.6)	6.1	37.9
Changes in fair value of Liquidity Option Agreement	25.4	0	0
Changes in fair market value of derivative instruments	(18.4)	30.6	1.4
Net effect of changes in operating accounts	(323.3)	(108.2)	(97.6)
Other operating activities	(0.2)	(7.8)	5.5
Net cash flows provided by operating activities	4,002.4	4,162.2	3,865.5
Investing activities:
Capital expenditures	(3,830.7)	(2,892.9)	(3,408.2)
Contributions in aid of construction costs	19.1	28.9	26
Decrease (increase) in restricted cash	(15.9)	65.6	(61.3)
Cash used for business combinations, net of cash received	(1,056.5)	(2,416.8)	0
Investments in unconsolidated affiliates	(162.6)	(722.4)	(1,094.1)
Proceeds from asset sales and insurance recoveries	1,608.6	145.3	280.6
Other investing activities	(3.8)	(5.6)	(0.5)
Cash used in investing activities	(3,441.8)	(5,797.9)	(4,257.5)
Financing activities:
Borrowings under debt agreements	21,081.1	18,361.1	13,852.8
Repayments of debt	(19,867.2)	(14,341.1)	(12,680.6)
Debt issuance costs	(24)	(41.2)	(23.7)
Monetization of interest rate derivative instruments	0	27.6	(168.8)
Cash distributions paid to limited partners	(2,943.7)	(2,638.1)	(2,400.3)
Cash payments made in connection with distribution equivalent rights	(7.7)	(3.7)	0
Cash distributions paid to noncontrolling interests	(48)	(48.6)	(8.9)
Cash contributions from noncontrolling interests	54	4	115.4
Net cash proceeds from the issuance of common units	1,188.6	388.8	1,792
Other financing activities	(49.1)	(55.6)	(45.1)
Cash provided by (used in) financing activities	(616)	1,653.2	432.8
Net change in cash and cash equivalents	(55.4)	17.5	40.8
Cash and cash equivalents, January 1	74.4	56.9	16.1
Cash and cash equivalents, December 31	$ 19	$ 74.4	$ 56.9

STATEMENTS OF CONSOLIDATED EQUI

STATEMENTS OF CONSOLIDATED EQUITY - USD ($) $ in Millions	Total	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interests [Member]	Limited Partners [Member]
Balance at Dec. 31, 2012	$ 13,296	$ (370.4)	$ 108.3	$ 13,558.1
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	2,607.1	0	10.2	2,596.9
Cash distributions paid to limited partners	(2,400.3)	0	0	(2,400.3)
Cash distributions paid to noncontrolling interests	(8.9)	0	(8.9)	0
Cash contributions from noncontrolling interests	115.4	0	115.4	0
Net cash proceeds from the issuance of common units	1,792	0	0	1,792
Amortization of fair value of equity-based awards	72.4	0	0	72.4
Cash flow hedges	11	11	0	0
Other	(44.3)	0.4	0.6	(45.3)
Balance at Dec. 31, 2013	15,440.4	(359)	225.6	15,573.8
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	2,833.5	0	46.1	2,787.4
Cash distributions paid to limited partners	(2,638.1)	0	0	(2,638.1)
Cash payments made in connection with distribution equivalent rights	(3.7)	0	0	(3.7)
Cash distributions paid to noncontrolling interests	(48.6)	0	(48.6)	0
Cash contributions from noncontrolling interests	4	0	4	0
Common units issued and noncontrolling interests acquired in connection with Step 1 of Oiltanking acquisition	3,568.7	0	1,397.2	2,171.5
Net cash proceeds from the issuance of common units	388.8	0	0	388.8
Amortization of fair value of equity-based awards	87	0	5.2	81.8
Cash flow hedges	117	117	0	0
Other	(56.8)	0.4	(0.5)	(56.7)
Balance at Dec. 31, 2014	19,692.2	(241.6)	1,629	18,304.8
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	2,558.4	0	37.2	2,521.2
Cash distributions paid to limited partners	(2,943.7)	0	0	(2,943.7)
Cash payments made in connection with distribution equivalent rights	(7.7)	0	0	(7.7)
Cash distributions paid to noncontrolling interests	(48)	0	(48)	0
Cash contributions from noncontrolling interests	54	0	54	0
Common units issued in connection with Step 2 of Oiltanking acquisition	0	0	(1,408.7)	1,408.7
Removal 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	1,188.6	0	0	1,188.6
Amortization of fair value of equity-based awards	92.4	0	0	92.4
Cash flow hedges	22	22	0	0
Other	(45)	0.4	4.6	(50)
Balance at Dec. 31, 2015	$ 20,501.1	$ (219.2)	$ 206	$ 20,514.3

Partnership Operations, Organiz

Partnership Operations, Organization and Basis of Presentation	12 Months Ended
	Dec. 31, 2015
Partnership Operations, Organization and Basis of Presentation [Abstract]
Partnership Operations, Organization and Basis of Presentation	With the exception of per unit amounts, or as noted within the context of each disclosure, the dollar amounts presented in the tabular data within these disclosures are stated in millions of dollars. KEY REFERENCES USED IN THESE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 Directors (the "Board") of Enterprise GP; (ii) Richard H. Bachmann, who is also a director and Vice Chairman of the Board of Enterprise GP; and (iii) Dr. Ralph S. Cunningham. Ms. Duncan Williams and Mr. Bachmann also currently serve as managers of Dan Duncan LLC along with W. Randall Fowler, who is also a director and President of Enterprise GP. 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. Duncan Williams, who serves as Chairman of EPCO; (ii) Dr. Cunningham, who serves as Vice Chairman of EPCO; and (iii) Mr. Bachmann, who serves as the President and Chief Executive Officer of EPCO. Ms. Duncan Williams and Mr. Bachmann also currently serve as directors of EPCO along with Mr. Fowler, who is also the Executive Vice President and Chief Administrative Officer of EPCO. EPCO, together with its privately held affiliates, owned approximately 33.6% of our limited partner interests at December 31, 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"), a U.S. corporation, as the first step of a two-step acquisition of Oiltanking. In February 2015, we completed the second step of this acquisition. See Note 12 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 5 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 12 for additional information regarding this acquisition. 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 liquid ("NGL") related businesses of EPCO and are 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; 250 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. All statistical data (e.g., pipeline mileage, processing capacity and similar operating metrics) in these notes to consolidated financial statements are unaudited. 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, which primarily consisted of our Offshore Pipelines & Services segment. Our consolidated financial statements reflect ownership of the Offshore Business through July 24, 2015. See Note 10 for additional information regarding our business segments. 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 15 for information regarding the ASA and other related party matters.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
Summary of Significant Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Allowance for Doubtful Accounts Our allowance for doubtful accounts is determined based on specific identification and estimates of future uncollectible accounts, including those related to natural gas imbalances. Our procedure for estimating the allowance for doubtful accounts is based on: (i) historical experience with customers, (ii) the perceived financial stability of customers based on our research and (iii) the levels of credit we grant to customers. In addition, we may increase the allowance for doubtful accounts in response to the specific identification of customers involved in bankruptcy proceedings and similar financial difficulties. On a routine basis, we review estimates associated with the allowance for doubtful accounts to ensure that we have recorded sufficient reserves to cover potential losses. The following table presents our allowance for doubtful accounts activity for the periods indicated: For the Year Ended December 31, 2015 2014 2013 Balance at beginning of period $ 13.9 $ 7.5 $ 13.2 Charged to costs and expenses 0.8 8.4 2.1 Deductions (2.6 ) (2.0 ) (7.8 ) Balance at end of period $ 12.1 $ 13.9 $ 7.5 See "Credit Risk" in Note 18 for additional information. Cash and Cash Equivalents Cash and cash equivalents represent unrestricted cash on hand and highly liquid investments with original maturities of less than three months from the date of purchase. Consolidation Policy Our consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest, after the elimination of all intercompany accounts and transactions. We also consolidate other entities and ventures in which we possess a controlling financial interest as well as partnership interests where we are the sole general partner of the partnership. We evaluate our financial interests in business enterprises to determine if they represent variable interest entities where we are the primary beneficiary. If such criteria are met, we consolidate the financial statements of such businesses with those of our own. Third party or affiliate ownership interests in our controlled subsidiaries are presented as noncontrolling interests. See Note 9 for information regarding noncontrolling interests. If the entity is organized as a limited partnership or limited liability company and maintains separate ownership accounts, we account for our investment using the equity method if our ownership interest is between 3% and 50%, unless our interest is so minor that we have virtually no influence over the investee's operating and financial policies. For all other types of investments, we apply the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the investee's operating and financial policies. In consolidation, we eliminate our proportionate share of profits and losses from transactions with equity method unconsolidated affiliates to the extent such amounts remain on our Consolidated Balance Sheets (or those of our equity method investments) in inventory or similar accounts. 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 17 for additional information regarding our contingencies. Current Assets and Current Liabilities We present, as individual captions in our Consolidated Balance Sheets, all components of current assets and current liabilities that exceed 5% of total current assets and current liabilities, respectively. 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. We are required to recognize derivative instruments at fair value as either assets or liabilities on our Consolidated Balance Sheets unless such instruments meet certain normal purchase/normal sale criteria. While all derivatives are required to be reported at fair value on the balance sheet, changes in fair value of derivative instruments are reported in different ways, depending on the nature and effectiveness of the hedging activities to which they relate. After meeting specified conditions, a qualified derivative may be designated as a total or partial hedge of:  Changes in the fair value of a recognized asset or liability, or an unrecognized firm commitment – In a fair value hedge, gains and losses for both the derivative instrument and the hedged item are recognized in income during the period of change.  Variable cash flows of a forecasted transaction – In a cash flow hedge, the effective portion of the hedge is reported in other comprehensive income (loss) and is reclassified into earnings when the forecasted transaction affects earnings. An effective hedge relationship is one in which the change in fair value of a derivative instrument can be expected to offset 80% to 125% of the changes in fair value of a hedged item at inception and throughout the life of the hedging relationship. The effective portion of a hedge relationship is the amount by which the derivative instrument exactly offsets the change in fair value of the hedged item during the reporting period. Conversely, ineffectiveness represents the change in the fair value of the derivative instrument that does not exactly offset the change in the fair value of the hedged item. Any ineffectiveness associated with a hedge relationship is recognized in earnings immediately. Ineffectiveness can be caused by, among other things, changes in the timing of forecasted transactions or a mismatch of terms between the derivative instrument and the hedged item. A contract designated as a cash flow hedge of an anticipated transaction that is not probable of occurring is immediately recognized in earnings. Certain of our derivative instruments do not qualify for hedge accounting treatment; therefore, these instruments are accounted for using mark-to-market accounting. 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 14 for additional information regarding our derivative instruments. Environmental Costs Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management's best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals. Expenditures to mitigate or prevent future environmental contamination are capitalized. Ongoing environmental compliance costs are charged to expense as incurred. In accruing for environmental remediation liabilities, costs of future expenditures for environmental remediation are not discounted to their present value, unless the amount and timing of the expenditures are fixed or reliably determinable. At December 31, 2015, none of our estimated environmental remediation liabilities were discounted to present value since the ultimate amount and timing of cash payments for such liabilities were not readily determinable. The following table presents the activity of our environmental reserves for the periods indicated: For the Year Ended December 31, 2015 2014 2013 Balance at beginning of period $ 15.6 $ 9.9 $ 13.7 Charged to costs and expenses 6.4 11.9 3.9 Acquisition-related additions and other 1.1 2.5 0.7 Deductions (10.1 ) (8.7 ) (8.4 ) Balance at end of period $ 13.0 $ 15.6 $ 9.9 At December 31, 2015 and 2014, $5.8 million and $8.1 million, respectively, of our environmental reserves were classified as current liabilities. Estimates Preparing our consolidated financial statements in conformity with U.S. generally accepted accounting principles ("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. 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. The characteristics of fair value amounts classified within each level of the hierarchy are described as follows:  Level 1 fair values are based on quoted prices, which are available in active markets for identical assets or liabilities as of the measurement date. Active markets are defined as those in which transactions for identical assets or liabilities occur with sufficient frequency so as to provide pricing information on an ongoing basis (e.g., the New York Mercantile Exchange ("NYMEX")). Our Level 1 fair values consist of financial assets and liabilities such as exchange-traded commodity derivative instruments.  Level 2 fair values are based on pricing inputs other than quoted prices in active markets (as reflected in Level 1 fair values) and are either directly or indirectly observable as of the measurement date. Level 2 fair values include instruments that are valued using financial models or other appropriate valuation methodologies. Such financial models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, the time value of money, volatility factors, current market and contractual prices for the underlying instruments and other relevant economic measures. Substantially all of these assumptions (i) are observable in the marketplace throughout the full term of the instrument; (ii) can be derived from observable data; or (iii) are validated by inputs other than quoted prices (e.g., interest rate and yield curves at commonly quoted intervals). Our Level 2 fair values primarily consist of commodity derivative instruments such as forwards, swaps and other instruments transacted on an exchange or over-the-counter and interest rate derivative instruments. The fair values of these derivative instruments are based on observable price quotes for similar products and locations. The fair value of our interest rate derivatives are determined using financial models that incorporate the implied forward LIBOR yield curve for the same period as the future interest rate swap settlements.  Level 3 fair values are based on unobservable inputs. Unobservable inputs are used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. Unobservable inputs reflect management's ideas about the assumptions that market participants would use in pricing an asset or liability (including assumptions about risk). Unobservable inputs are based on the best information available to us in the circumstances, which might include our internally developed data. Level 3 inputs are typically used in connection with internally developed valuation methodologies where we make our best estimate of an instrument's fair value. With regards to commodity derivatives, our Level 3 fair values primarily consist of ethane, propane, normal butane and natural gasoline-based contracts with terms greater than one year and certain options used to hedge natural gas storage inventory and transportation capacities. In addition, we often rely on price quotes from reputable brokers who publish price quotes on certain products and compare these prices to other reputable brokers for the same products in the same markets whenever possible. These prices, when combined with data from our commodity derivative instruments, are used in our models to determine the fair value of such instruments. Transfers within the fair value hierarchy routinely occur for certain term contracts as prices and other inputs used for the valuation of future delivery periods become more observable with the passage of time. Other transfers are made periodically in response to changing market conditions that affect liquidity, price observability and other inputs used in determining valuations. We deem any such transfers to have occurred at the end of the quarter in which they transpired. There were no transfers between Level 1 and 2 during the years ended December 31, 2015 and 2014. We have a risk management policy that covers our Level 3 commodity derivatives. Governance and oversight of risk management activities for these commodities are provided by our Chief Executive Officer with guidance and support from a risk management committee ("RMC") that meets quarterly (or on a more frequent basis, if needed). Members of executive management attend the RMC meetings, which are chaired by the head of our commodities risk control group. This group is responsible for preparing and distributing daily reports and risk analysis to members of the RMC and other appropriate members of management. These reports include mark-to-market valuations with the one-day and month-to-date changes in fair values. This group also develops and validates the forward commodity price curves used to estimate the fair values of our Level 3 commodity derivatives. These forward curves incorporate published indexes, market quotes and other observable inputs to the extent available. Impairment Testing for Goodwill Our goodwill amounts are assessed for impairment on a routine annual basis or when impairment indicators are present. If such indicators occur (e.g., the loss of a significant customer or technological obsolescence of assets), the estimated fair value of the reporting unit to which the goodwill is assigned is determined and compared to its carrying value. If the fair value of the reporting unit is less than its carrying value including associated goodwill amounts, a charge to earnings is recorded to reduce the carrying value of the goodwill to its implied fair value. Our reporting unit estimated fair values are based on assumptions regarding the future economic prospects of the businesses that comprise each reporting unit. Such assumptions include: (i) discrete financial forecasts for the assets classified within the reporting unit, which, in turn, rely on management's estimates of operating margins, throughput volumes and similar factors; (ii) long-term growth rates for cash flows beyond the discrete forecast period; and (iii) appropriate discount rates. We believe the assumptions we use in estimating reporting unit fair values are consistent with those that would be employed by market participants is their fair value estimation process. Based on our most recent goodwill impairment test at December 31, 2015, each reporting unit's fair value was substantially in excess of its carrying value (i.e., by at least 10%). See Note 7 for additional information regarding goodwill. Impairment Testing for Long-Lived Assets Long-lived assets (including intangible assets with finite useful lives and property, plant and equipment) are reviewed for impairment 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 carrying value of a long-lived asset is deemed not recoverable if it exceeds the sum of undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the asset's carrying value exceeds the sum of its undiscounted cash flows, a non-cash asset impairment charge equal to the excess of the asset's carrying value over its estimated fair value is recorded. Fair value is defined as the price that would be received to sell an asset or be paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. We measure fair value using market price indicators or, in the absence of such data, appropriate valuation techniques. See Note 14 for information regarding impairment charges related to long-lived assets. Impairment Testing for Unconsolidated Affiliates We evaluate our equity method investments for impairment when events or changes in circumstances indicate that there is a loss in value of the investment attributable to an other than temporary decline. Examples of such events or changes in circumstances include continuing operating losses of the entity and/or long-term negative changes in the entity's industry. In the event we determine that the loss in value of an investment is an other than temporary decline, we record a charge to equity earnings to adjust the carrying value of the investment to its estimated fair value. There were no impairment charges in 2015 and 2014 related to our equity method investments. See Note 6 for information regarding our equity method investments, and Note 14 for information for the related impairment charge recorded during 2013. Inventories Inventories primarily consist of NGLs, petrochemicals, refined products, crude oil and natural gas volumes that are valued at the lower of average cost or market. We capitalize, as a cost of inventory, shipping and handling charges (e.g., pipeline transportation and storage fees) and other related costs associated with purchased volumes. As volumes are sold and delivered out of inventory, the cost of these volumes (including freight-in charges that have been capitalized as part of inventory cost) are charged to operating costs and expenses. Shipping and handling fees associated with products we sell and deliver to customers are charged to operating costs and expenses as incurred. See Note 4 for additional information regarding our inventories. Property, Plant and Equipment Property, plant and equipment is recorded at cost. Expenditures for additions, improvements and other enhancements to property, plant and equipment are capitalized, and minor replacements, maintenance, and repairs that do not extend asset life or add value are charged to expense as incurred. When property, plant and equipment assets are retired or otherwise disposed of, the related cost and accumulated depreciation is removed from the accounts and any resulting gain or loss is included in results of operations for the respective period. 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. In general, depreciation is the systematic and rational allocation of an asset's cost, less its residual value (if any), to the periods it benefits. The majority of our property, plant and equipment is depreciated using the straight-line method, which results in depreciation expense being incurred evenly over the life of an asset. Our estimate of depreciation expense incorporates management assumptions regarding the useful economic lives and residual values of our assets. With respect to midstream energy assets such as natural gas gathering systems that are reliant upon a specific natural resource basin for throughput volumes, the anticipated useful economic life of such assets may be limited by the estimated life of the associated natural resource basin from which the assets derive benefit. Our forecast of the remaining life for the applicable resource basins is based on several factors, including information published by the U.S. Energy Information Administration. Where appropriate, we use other depreciation methods (generally accelerated) for tax purposes. Leasehold improvements are recorded as a component of property, plant and equipment. The cost of leasehold improvements is charged to earnings using the straight-line method over the shorter of (i) the remaining lease term or (ii) the estimated useful lives of the improvements. We consider renewal terms that are deemed reasonably assured when estimating remaining lease terms. Our assumptions regarding the useful economic lives and residual values of our assets may change in response to new facts and circumstances, which would prospectively impact our depreciation expense amounts. Examples of such circumstances include, but are not limited to: (i) changes in laws and regulations that limit the estimated economic life of an asset; (ii) changes in technology that render an asset obsolete; (iii) changes in expected salvage values or (iv) significant changes in the forecast life of the applicable resource basins, if any. Certain of our plant operations entail periodic planned outages for major maintenance activities. These planned shutdowns typically result in significant expenditures, which are principally comprised of amounts paid to third parties for materials, contract services and related items. We use the expense-as-incurred method for our planned major maintenance activities for plant operations; however, the cost of annual planned major maintenance projects for such plants are deferred and recognized ratably until the next planned annual outage. With regard to the planned major maintenance activities on our marine transportation assets and underground storage caverns, we use the deferral method to account for such costs. Under this method, major maintenance costs are capitalized and amortized over the period until the next major overhaul or cavern integrity project. Asset retirement obligations ("AROs") are legal obligations associated with the retirement of tangible long-lived assets that result from their acquisition, construction, development and/or normal operation. When an ARO is incurred, we record a liability for the ARO and capitalize an equal amount as an increase in the carrying value of the related long-lived asset. ARO amounts are measured at their estimated fair value using expected present value techniques. Over time, the ARO liability is accreted to its present value (through accretion expense) and the capitalized amount is depreciated over the remaining useful life of the related long-lived asset. We will incur a gain or loss to the extent that our ARO liabilities are not settled at their recorded amounts. See Note 5 for additional information regarding our property, plant and equipment and AROs. Recent Accounting Developments Revenue Recognition In May 2014, the Financial Accounting Standards Board ("FASB") and the International Accounting Standards Board finished their joint project in the area of revenue recognition. The resulting accounting standards update eliminates the specific transaction and industry revenue recognition guidance under current U.S. GAAP and replaces it with a principles based approach for determining revenue recognition. The core principle in the new guidance is that a company should recognize revenue in a manner that fairly depicts the transfer of goods or services to customers in amounts that reflect the consideration the company expects to receive for those goods or services. In order to apply this core principle, companies will apply the following five steps in determining the amount of revenues to recognize: (i) identify the contract; (ii) identify the performance obligations in the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and (v) recognize revenue when (or as) the performance obligation is satisfied. Each of these steps involves management's judgment and an analysis of the contract's material terms and conditions. In light of this recently issued accounting guidance, we started the process of reviewing our revenue contracts in 2015; however, due to the early stage of this process, we are currently not in a position to estimate the impact the new guidance will have on our consolidated financial statements. We expect to adopt the new standard on January 1, 2018 using the modified retrospective approach. This approach allows us to apply the new standard to (i) all new contracts entered into after January 1, 2018 and (ii) all existing contracts as of January 1, 2018 through a cumulative adjustment to equity. Consolidated revenues for periods prior to January 1, 2018 would not be revised. Leases A new lease accounting model is being introduced by the FASB. Under the new guidance, substantially all leases (with the exception of leases with a term of 12 months or less) will be recorded on the balance sheet and be classified as either "finance" or "operating" leases on the basis of whether the lessee effectively obtains control of the underlying asset during lease term. A lease would be classified as a finance lease if a lessee meets one of five classification criteria that are generally consistent with current lease accounting guidance. Alternatively, a lease would be classified as an operating lease if it does not meet this criteria. Regardless of classification, the initial measurement of both finance leases and operating leases will result in the balance sheet recognition of a "right-of-use asset" and a corresponding lease liability, which will be recognized at the present value of the lease payments. The subsequent measurement of each type of lease varies. Leases classified as a finance lease are accounted for using the effective interest method. Under this approach, a lessee would separately amortize the right of use asset (in a manner similar to depreciation) and the discount on the lease liability (as a component of interest expense). Interest expense is separately recorded since a finance lease is viewed as the purchasing and financing of a leased asset. On the cash flow statement, amortization associated with this type of lease would be presented as an adjustment to net income within operating activities and payments on the principal portion of the lease liability would be classified as a financing activity cash outflow. Leases classified as an operating lease would recognize a single lease expense amount that is recorded on a straight-line basis (or another systematic basis if more appropriate), which combines the unwinding of the discount on the lease liability with the amortization of the right of use asset. For purposes of cash flow statement presentation, operating lease payments would be a component of operating activities. Due to the recent nature of this guidance, we are currently not in a position to estimate its future impact on our consolidated financial statements. Based on the parameters outlined by the FASB, we expect to adopt the new lease accounting model in 2019. 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 December 31, 2015, our restricted cash amount was $15.9 million. We did not have any restricted cash as of December 31, 2014. See Note 14 for information regarding our derivative instruments and hedging activities.

Revenue Recognition

Revenue Recognition	12 Months Ended
	Dec. 31, 2015
Revenue Recognition [Abstract]
Revenue Recognition	In general, we recognize revenue from our customers when all of the following criteria are met: (i) persuasive evidence of an exchange arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the buyer's price is fixed or determinable and (iv) collectibility is reasonably assured. Amounts billed in advance of the period in which the service is rendered or product delivered are recorded as deferred revenue. The following information summarizes our revenue recognition policies by business segment. See Note 10 for general information regarding our business segments. NGL Pipelines & Services In our natural gas processing business, we utilize contracts that are either fee-based, commodity-based or a combination of the two. When a cash fee for natural gas processing services is stipulated by a contract, we record revenue when a producer's natural gas has been processed and redelivered. Our commodity-based contracts include keepwhole and margin-band contracts, percent-of-liquids contracts, percent-of-proceeds contracts and contracts featuring a combination of commodity and fee-based terms. Under keepwhole and margin-band contracts, we take ownership of mixed NGLs extracted from the producer's natural gas stream while replacing the equivalent quantity of energy on a natural gas basis to producers. We recognize revenue when the extracted NGLs are delivered and sold to customers under NGL marketing sales contracts. Under percent-of-liquids contracts, we take ownership of a portion of the mixed NGLs extracted from the producer's natural gas stream (in lieu of a cash processing fee) and recognize revenue when the extracted NGLs are delivered and sold to customers under NGL marketing sales contracts. Under percent-of-proceeds contracts, we share in the proceeds generated from the sale of mixed NGLs we extract on the producer's behalf (in lieu of a cash processing fee). In certain cases, we also utilize contracts that include a combination of commodity-based terms (such as those described above) and fee-based terms. Our NGL marketing activities generate revenues from merchant activities such as term and spot sales of NGLs, which we take title to through our natural gas processing activities (i.e., our equity NGL production) and open market and contract purchases. Revenue from these sales contracts is recognized when the NGLs are delivered to customers. In general, sales prices referenced in the underlying contracts are market-based and may include pricing differentials for factors such as location, timing or NGL product quality. NGL sales contracts associated with our export facilities may also include take-or-pay provisions. Revenues from NGL pipeline transportation contracts and tariffs are generally based upon a fixed fee per gallon (subject to escalation, if applicable) of liquids transported multiplied by the volume delivered. Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies, including the Federal Energy Regulatory Commission ("FERC"), or contractual arrangements. Typically, pipeline transportation revenue is recognized when volumes are transported and delivered. However, under certain NGL pipeline transportation agreements (e.g., those associated with committed shippers on our Texas Express Pipeline, Front Range Pipeline, ATEX and Aegis Ethane Pipeline) customers are required to ship a minimum volume over an agreed-upon period. These arrangements typically entail the shipper paying a transportation fee based on a minimum volume commitment, with a provision that allows the shipper to make-up any volume shortfalls over the agreed-upon period (referred to as shipper "make-up rights"). Revenue pursuant to such agreements, including that associated with make-up rights, is initially deferred and subsequently recognized at the earlier of when the deficiency volume is shipped, when the shipper's ability to meet the minimum volume commitment has expired (typically a one year contractual period), or when the pipeline is otherwise released from its transportation service performance obligation. We collect storage revenue under our NGL and related product storage contracts primarily from capacity reservation agreements, where we collect a fee for reserving storage capacity for customers in our underground storage wells. Customers pay reservation fees based on the level of storage capacity reserved rather than the actual volumes stored. Under these agreements, revenue is recognized ratably over the specified reservation period. When a customer exceeds its reserved capacity, we charge that customer excess storage fees, which are recognized in the period of occurrence. In addition, we generally charge customers throughput fees based on volumes delivered into and subsequently withdrawn from storage, which are recognized as the service is provided. We typically earn revenues from NGL fractionation under fee-based arrangements. These fees are contractually subject to adjustment for changes in certain fractionation expenses (e.g., natural gas fuel costs). Under fee-based arrangements, revenue is recognized in the period services are provided. At our Norco facility in Louisiana, we perform fractionation services for certain customers under percent-of-liquids contracts. Such contracts allow us to retain a contractually determined percentage of the customer's fractionated NGLs as payment for services rendered. Revenue is recognized from such arrangements when we sell and deliver the retained NGLs to customers. Revenue from NGL import and LPG export terminaling activities is recorded in the period services are provided. Customers are typically billed a fee per unit of volume loaded or unloaded. Crude Oil Pipelines & Services Revenues from crude oil transportation contracts and tariffs are generally based upon a fixed fee per barrel (subject to escalation, if applicable) transported multiplied by the volume delivered. Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies, including the FERC, or contractual arrangements. Typically, revenue associated with these arrangements is recognized when volumes are transported and delivered; however, under certain of our crude oil pipeline transportation agreements, customers are required to ship a minimum volume over an agreed-upon period, with make-up rights. Revenue pursuant to such agreements, including that associated with make-up rights, is initially deferred and subsequently recognized at the earlier of when the deficiency volume is shipped, when the shipper's ability to meet the minimum volume commitment has expired (typically a one year contractual period), or when the pipeline is otherwise released from its transportation service performance obligation. Revenue from our condensate gathering, processing and stabilization services as well as gathering, treating and compression services is recognized based upon the higher of actual volumes handled or minimum volume commitments. Fees charged for the underlying services are contractually fixed and, if applicable, subject to escalation. With respect to those agreements having minimum volume commitments, the producer pays a deficiency fee when its volumes do not meet contractually defined minimum volume thresholds (there are no make-up rights in connection with these agreements). Under certain of the contracts, if actual volumes handled during a period exceed the respective minimum volume commitment, the excess volume serves to reduce future minimum volume commitments (for periods up to two years in the future), thus reducing any potential deficiency fees that the producer may pay in the future. Under our crude oil terminaling agreements, we charge customers for crude oil storage based on storage capacity reservation agreements, where we collect a fee for reserving storage capacity for customers at our terminals. Under these agreements, revenue is recognized ratably over the specified reservation period. In addition, we charge our customers throughput (or pumpover) fees based on volumes withdrawn from our terminals. Revenue is also generated from fee-based trade documentation services and is recognized as services are completed. Our crude oil marketing activities generate revenues from the sale and delivery of crude oil purchased either directly from producers or from others on the open market. These sales contracts generally settle with the physical delivery of crude oil to customers. In general, the sales prices referenced in the underlying contracts are market-based and may include pricing differentials for factors such as delivery location, timing or crude oil quality. Natural Gas Pipelines & Services Our natural gas pipelines typically generate revenues from transportation agreements under which shippers are billed a fee per unit of volume transported multiplied by the volume gathered or delivered. Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies, including the FERC, or contractual arrangements. Certain of our natural gas pipelines offer firm capacity reservation services whereby the shipper pays a contractual fee based on the level of throughput capacity reserved (whether or not the shipper actually utilizes such capacity). Revenues are recognized when volumes have been delivered to customers or in the period we provide firm capacity reservation services. Under our natural gas storage revenue contracts, there are typically two components: (i) monthly demand payments, which are associated with a customer's storage capacity reservation and paid regardless of actual usage, and (ii) storage fees per unit of volume stored at our facilities. Revenue from demand payments is recognized during the period the customer reserves capacity. Revenue from storage fees is recognized in the period the services are provided. Our natural gas marketing activities generate revenue from the sale and delivery to local gas distribution companies and other customers of natural gas purchased from producers, regional natural gas processing plants and the open market. Revenue from these sales contracts is recognized when natural gas is delivered to customers. In general, sales prices referenced in the underlying contracts are market-based and may include pricing differentials for factors such as delivery location. Petrochemical & Refined Products Services Our propylene fractionation, butane isomerization and deisobutanizer facilities generate revenue through fee-based arrangements, which typically include a base-processing fee subject to adjustment for changes in power, fuel and labor costs, all of which are the primary costs of propylene fractionation and butane isomerization. Our butane isomerization and deisobutanizer operations also generate revenue from the sale and delivery of by-products. Revenue resulting from such agreements is recognized in the period the services are provided. Revenues from our petrochemical pipeline transportation contracts are primarily based upon a fixed fee per volume transported (typically measured in gallons or pounds and subject to escalation, if applicable) multiplied by the volume delivered. Our petrochemical marketing activities include the purchase and fractionation of refinery grade propylene obtained in the open market and generate revenues from the sale and delivery of products obtained through propylene fractionation. Revenue from these sales contracts is recognized when such products are delivered to customers. In general, we sell our petrochemical products at market-based prices, which may include pricing differentials for factors such as delivery location. Revenue from the production and sale of octane additives and high purity isobutylene is dependent on the sales price and volume of such commodities sold to customers. Revenue is recognized for sales transactions when the product is delivered. Pipelines transporting refined products generate revenues through contracts and tariffs as customers are billed a fixed fee per barrel (subject to escalation, if applicable) of liquids transported multiplied by the volume delivered. The fees charged under these arrangements are either contractual or regulated by governmental agencies, including the FERC. Revenue associated with these fee-based contracts and tariffs is recognized when volumes have been delivered. Revenue from our refined products storage facilities is based on capacity reservation agreements where we collect a fee for reserving a defined storage capacity for customers at our facilities. Under these contracts, revenue is recognized ratably over the length of the storage period. Revenue from product terminaling activities is recorded in the period such services are provided. Customers are typically billed a fee per unit of volume loaded. Revenue is also generated from the provision of inland and offshore marine transportation of refined products, crude oil, condensate, asphalt, heavy fuel oil, LPG and other petroleum products via tow boats and tank barges. Under our marine services transportation contracts, revenue is recognized over the transit time of individual tows as determined on an individual contract basis, which is generally less than ten days in duration. Revenue from these contracts is typically based on set day rates or a set fee per cargo movement. The costs of fuel, substantially all of which is a pass through expense, and other specified operational fees and costs are directly reimbursed by the customer under most of these contracts. Offshore Pipelines & Services In July 2015, we sold our Offshore Business to Genesis. See Note 5 for additional information related to the sale of our Offshore Business. Revenue from offshore pipelines was generally based upon a fixed fee per unit of volume gathered or transported multiplied by the volume delivered. Transportation fees were based either on contractual arrangements or tariffs regulated by the FERC. Revenue associated with these fee-based contracts and tariffs was recognized when volumes were delivered. Revenues from offshore platform services generally consisted of demand fees and commodity charges. Revenues from offshore platform services were recognized in the period the services were provided. Demand fees represented charges to customers served by offshore platforms regardless of the volume the customer actually delivered to the platform. Revenue from commodity charges was based on a fee per unit of volume delivered to the platform multiplied by the total volume of each product delivered. Contracts for platform services often included both demand fees and commodity charges, but demand fees generally expired after a contractually fixed period of time.

Inventories

Inventories	12 Months Ended
	Dec. 31, 2015
Inventories [Abstract]
Inventories	Our inventory amounts by product type were as follows at the dates indicated: December 31, 2015 2014 NGLs $ 639.9 $ 579.1 Petrochemicals and refined products 148.0 295.6 Crude oil 222.1 97.8 Natural gas 28.1 41.7 Total $ 1,038.1 $ 1,014.2 In those instances where we take ownership of inventory volumes through percent-of-liquids contracts and similar arrangements (as opposed to outright purchases from third parties for cash), these volumes are valued at market-based prices during the month in which they are acquired. The following table presents our total cost of sales amounts and lower of cost or market adjustments for the periods indicated: For the Year Ended December 31, 2015 2014 2013 Cost of sales (1) $ 19,612.9 $ 40,464.1 $ 40,770.2 Lower of cost or market adjustments within cost of sales 19.8 22.8 18.5 (1) Cost of sales is a component of "Operating costs and expenses," as presented on our 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. Due to fluctuating commodity prices, we recognize lower of cost or market adjustments when the carrying value of our available-for-sale inventories exceeds their net realizable value. These non-cash charges are a component of cost of sales in the period they are recognized. To the extent our commodity hedging strategies address inventory-related price risks and are successful, these inventory valuation adjustments are mitigated or offset. See Note 14 for a description of our commodity hedging activities.

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 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 December 31, in Years 2015 2014 Plants, pipelines and facilities (1) 3-45 (6) $ 32,525.0 $ 30,834.9 Underground and other storage facilities (2) 5-40 (7) 3,000.5 2,584.2 Platforms and facilities (3) 20-31 -- 659.7 Transportation equipment (4) 3-10 159.9 154.2 Marine vessels (5) 15-30 769.8 796.4 Land 262.7 262.6 Construction in progress 3,894.0 2,754.7 Total 40,611.9 38,046.7 Less accumulated depreciation 8,577.2 8,165.1 Property, plant and equipment, net $ 32,034.7 $ 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; buildings; office furniture and equipment; 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. (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; buildings, 20-40 years; office furniture and equipment, 3-20 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 carrying values of certain fixed asset categories increased primarily as a result of the acquisition of EFS Midstream in July 2015. See Note 12 for information regarding this acquisition. The following table summarizes our depreciation expense and capitalized interest amounts for the periods indicated: For the Year Ended December 31, 2015 2014 2013 Depreciation expense (1) $ 1,161.6 $ 1,114.1 $ 1,012.4 Capitalized interest (2) 149.1 77.9 133.0 (1) Depreciation expense is a component of "Costs and expenses" as presented on our Statements of Consolidated Operations. (2) Capitalized interest is a component of "Interest expense" as presented on our Statements of Consolidated Operations. Sale of Offshore Business In July 2015, we completed the sale of our Offshore Business, which primarily consisted of our Offshore Pipelines & Services business segment, to Genesis 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 Alabama, Louisiana, Mississippi and Texas and 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. At the time of sale, the carrying value of the net assets of the Offshore Business 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. In total, we recorded non-cash losses of $67.1 million for the Offshore Business during 2015, including a $54.8 million asset impairment charge during the second quarter of 2015 and a $12.3 million loss on the sale in July 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, segment assets for our Offshore Pipelines & Services segment represented 4.3% of consolidated total segment assets. Likewise, gross operating margin from this business segment represented only 3.1% of our consolidated total gross operating margin for the year ended December 31, 2014. 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 acquisition of EFS Midstream). Also, proceeds from the closing of this sale reduced our need to issue additional equity and debt to support our capital spending program. Asset Retirement Obligations We record 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 December 31, 2015 and 2014 includes $17.6 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 for the periods indicated: For the Year Ended December 31, 2015 2014 2013 ARO liability beginning balance $ 98.3 $ 90.2 $ 105.2 Liabilities incurred 2.7 0.1 1.7 Liabilities settled (6.3 ) (2.7 ) (14.2 ) Revisions in estimated cash flows 49.7 4.6 (8.6 ) Accretion expense 5.2 6.1 6.1 AROs related to Offshore Business sold in July 2015 (91.1 ) -- -- ARO liability ending balance $ 58.5 $ 98.3 $ 90.2 Revisions to estimated cash flows for the year ended December 31, 2015 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 Consolidated Balance Sheet upon the sale of the Offshore Business on July 24, 2015. The following table presents our forecast of accretion expense for the periods indicated: 2016 2017 2018 2019 2020 $ 3.7 $ 4.0 $ 4.3 $ 4.7 $ 5.0

Investments in Unconsolidated A

Investments in Unconsolidated Affiliates	12 Months Ended
	Dec. 31, 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 December 31, 2015 December 31, 2015 2014 NGL Pipelines & Services: Venice Energy Service Company, L.L.C. ("VESCO") 13.1% $ 25.9 $ 27.7 K/D/S Promix, L.L.C. ("Promix") 50% 38.3 38.5 Baton Rouge Fractionators LLC ("BRF") 32.2% 18.5 18.8 Skelly-Belvieu Pipeline Company, L.L.C. ("Skelly-Belvieu") 50% 39.8 40.1 Texas Express Pipeline LLC ("Texas Express") 35% 342.0 349.3 Texas Express Gathering LLC ("TEG") 45% 36.8 37.9 Front Range Pipeline LLC ("Front Range") 33.3% 171.2 170.0 Delaware Basin Gas Processing LLC ("Delaware Processing") 50% 46.2 -- Crude Oil Pipelines & Services: Seaway Crude Pipeline Company LLC ("Seaway") 50% 1,396.0 1,431.2 Eagle Ford Pipeline LLC ("Eagle Ford Crude Oil Pipeline") 50% 388.8 336.5 Eagle Ford Terminals Corpus Christi LLC ("Eagle Ford Corpus Christi") 50% 28.6 -- Natural Gas Pipelines & Services: White River Hub, LLC ("White River Hub") 50% 22.5 23.2 Petrochemical & Refined Products Services: Baton Rouge Propylene Concentrator, LLC ("BRPC") 30% 5.4 6.5 Centennial Pipeline LLC ("Centennial") 50% 65.6 66.1 Other Various 2.9 2.5 Offshore Pipelines & Services: Various, sold to Genesis in July 2015 (see Note 5) n/a -- 493.7 Total investments in unconsolidated affiliates $ 2,628.5 $ 3,042.0 NGL Pipelines & Services The principal business activity of each investee included in our NGL Pipelines & Services segment is described as follows:  VESCO owns a natural gas processing facility in south Louisiana and a related gathering system that gathers natural gas from certain offshore developments for delivery to its natural gas processing facility.  Promix owns an NGL fractionation facility and related storage caverns located in south Louisiana. The facility receives mixed NGLs via pipeline from natural gas processing plants located in southern Louisiana and along the Mississippi Gulf Coast. In addition, Promix owns an NGL gathering system that gathers mixed NGLs from processing plants in southern Louisiana for its fractionator.  BRF owns an NGL fractionation facility located in south Louisiana that receives mixed NGLs from natural gas processing plants located in Alabama, Mississippi and southern Louisiana.  Skelly-Belvieu owns a pipeline that transports mixed NGLs from Skellytown, Texas to Mont Belvieu, Texas. The Skelly-Belvieu Pipeline receives NGLs through a pipeline interconnect with our Mid-America Pipeline System in Skellytown.  Texas Express owns an NGL pipeline that extends from Skellytown to our NGL fractionation and storage complex in Mont Belvieu. This pipeline commenced operations in November 2013. Mixed NGLs from the Rocky Mountains, Permian Basin and Mid-Continent regions are delivered to the Texas Express Pipeline via an interconnect with our Mid-America Pipeline System near Skellytown. The pipeline also transports mixed NGLs from two gathering systems owned by TEG to Mont Belvieu. In addition, mixed NGLs from the Denver-Julesburg Basin in Colorado are transported to the Texas Express Pipeline using the Front Range Pipeline.  TEG owns two NGL gathering systems that deliver volumes to the Texas Express Pipeline. These gathering systems commenced operations in November 2013. The Elk City gathering system gathers mixed NGLs from natural gas processing plants in the Anadarko/Granite Wash production area located in the Texas Panhandle and western Oklahoma. The North Texas gathering system gathers mixed NGLs from natural gas processing plants in the Barnett Shale production area in North Texas. An affiliate of Enbridge Energy Partners, L.P. serves as operator of these two NGL gathering systems.  Front Range owns an NGL pipeline that transports mixed NGLs from natural gas processing plants located in the Denver-Julesburg Basin to an interconnect with our Texas Express Pipeline and Mid-America Pipeline System in Skellytown. The Front Range Pipeline commenced operations in February 2014.  Delaware Processing was Crude Oil Pipelines & Services The principal business activity of each investee included in our Crude Oil Pipelines & Services segment is described as follows:  Seaway owns a pipeline system that connects the Cushing, Oklahoma crude oil hub with markets in Southeast Texas. The Seaway Pipeline is comprised of the Longhaul System, the Freeport System and the Texas City System. The Cushing hub is a major industry trading hub and price settlement point for West Texas Intermediate on the NYMEX. The Longhaul System provides north-to-south transportation of crude oil from the Cushing hub to Seaway's Jones Creek terminal near Freeport, Texas and our terminal located near Katy, Texas. In July 2014 we completed a pipeline looping project involving our Longhaul System. This expansion project entailed the construction of an additional pipeline that transports crude oil southbound from the Cushing hub to Seaway's Jones Creek terminal. The Freeport System consists of a marine dock, three pipelines and other related facilities that transport crude oil to and from Freeport to the Jones Creek terminal. The Texas City System consists of a ship unloading dock, storage tanks, various pipelines and other related facilities that deliver crude oil from Texas City, Texas to Galena Park, Texas and other nearby locations. The Freeport System and Texas City System make only intrastate movements. Seaway also owns storage tanks at the Jones Creek terminal, which are connected to the Longhaul System, and storage tanks at our Enterprise Crude Houston ("ECHO") terminal.  Eagle Ford Crude Oil Pipeline owns a crude oil pipeline that transports crude oil and condensate for producers in South Texas that commenced operations in July 2013. The system consists of a crude oil and condensate pipeline system extending from Gardendale, Texas in LaSalle County to Three Rivers, Texas in Live Oak County and continuing on to Corpus Christi, Texas. The system also includes a pipeline segment extending from Three Rivers to an interconnect with our South Texas Crude Oil Pipeline System in Wilson County. This system includes a marine terminal facility in Corpus Christi and storage capacity across the system. Plains All American Pipeline, L.P., our joint venture partner in the pipeline, serves as operator of the system.  Eagle Ford Corpus Christi was 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 Crude Oil Pipeline. This terminal is expected to be completed in 2018. Natural Gas Pipelines & Services White River Hub owns a natural gas hub facility serving producers in the Piceance Basin of northwest Colorado. The facility enables producers to access six interstate natural gas pipelines. Petrochemical & Refined Products Services The principal business activity of each significant investee included in our Petrochemical & Refined Products Services segment is described as follows:  BRPC owns a propylene fractionation facility located in south Louisiana that fractionates refinery grade propylene into chemical grade propylene.  Centennial owns an interstate refined products pipeline that extends from an origination facility in Beaumont, Texas, to Bourbon, Illinois. Centennial also owns a refined products storage terminal located near Creal Springs, Illinois. Offshore Pipelines & Services Our investments in unconsolidated affiliates classified within the Offshore Pipelines & Services segment were sold to Genesis on July 24, 2015 (see Note 5). At June 30, 2015, the carrying value of these investments was $482.4 million. Equity Earnings The following table presents our equity in income (loss) of unconsolidated affiliates by business segment for the periods indicated: For the Year Ended December 31, 2015 2014 2013 NGL Pipelines & Services $ 57.5 $ 30.6 $ 15.7 Crude Oil Pipelines & Services 281.4 184.6 140.3 Natural Gas Pipelines & Services 3.8 3.6 3.8 Petrochemical & Refined Products Services (1) (15.7 ) (13.3 ) (22.3 ) Offshore Pipelines & Services 46.6 54.0 29.8 Total $ 373.6 $ 259.5 $ 167.3 (1) Losses are primarily attributable to our investment in Centennial. As a result of a trend in declining earnings, we estimated the fair value of this equity-method investment during each of the last three fiscal years. Our estimates, based on a combination of the market and income approaches, indicate that the fair value of this investment remains substantially in excess of its carrying value. Excess Cost On occasion, the price we pay to acquire an ownership interest in a company exceeds the underlying carrying value of the capital accounts we acquire. These excess cost amounts are attributable to the fair value of the underlying tangible assets of these entities exceeding their respective book carrying values at the time of our acquisition of ownership interests in these entities. We amortize such excess cost amounts as a reduction to equity earnings in a manner similar to depreciation. The following table presents our unamortized excess cost amounts by business segment at the dates indicated: December 31, 2015 2014 NGL Pipelines & Services $ 25.3 $ 26.5 Crude Oil Pipelines & Services 19.3 21.7 Petrochemical & Refined Products Services 2.3 2.4 Offshore Pipelines & Services (1) -- 9.0 Total $ 46.9 $ 59.6 (1) Our investments in unconsolidated affiliates classified within the Offshore Pipelines & Services segment were sold to Genesis in July 2015. In total, amortization of excess cost amounts were $4.9 million, $3.3 million and $3.3 million for the years ended December 31, 2015, 2014 and 2013, respectively. We forecast that our amortization of excess cost amount will approximate $2.2 million in each of the next five years. Summarized Combined Financial Information of Unconsolidated Affiliates Combined balance sheet information for the last two years and results of operations data for the last three years for our unconsolidated affiliates are summarized in the following table (all data presented on a 100% basis): December 31, 2015 2014 Balance Sheet Data: Current assets $ 204.5 $ 289.9 Property, plant and equipment, net 5,671.1 6,766.5 Other assets 58.9 60.4 Total assets $ 5,934.5 $ 7,116.8 Current liabilities $ 306.7 $ 305.9 Other liabilities 103.2 309.9 Combined equity 5,524.6 6,501.0 Total liabilities and combined equity $ 5,934.5 $ 7,116.8 For the Year Ended December 31, 2015 2014 2013 Income Statement Data: Revenues $ 1,426.6 $ 1,311.3 $ 947.4 Operating income 825.8 600.0 423.9 Net income 814.1 587.9 382.6

Intangible Assets and Goodwill

Intangible Assets and Goodwill	12 Months Ended
	Dec. 31, 2015
Intangible Assets and Goodwill [Abstract]
Intangible Assets and Goodwill	Identifiable Intangible Assets The following table summarizes our intangible assets by business segment at the dates indicated: December 31, 2015 December 31, 2014 Gross Value Accumulated Amortization Carrying Value Gross Value Accumulated Amortization Carrying Value NGL Pipelines & Services: Customer relationship intangibles $ 447.4 $ (156.9 ) $ 290.5 $ 340.8 $ (183.2 ) $ 157.6 Contract-based intangibles 283.0 (193.2 ) 89.8 277.7 (178.7 ) 99.0 IDRs (1) -- -- -- 432.6 -- 432.6 Segment total 730.4 (350.1 ) 380.3 1,051.1 (361.9 ) 689.2 Crude Oil Pipelines & Services: Customer relationship intangibles 2,204.4 (39.1 ) 2,165.3 1,108.0 (7.7 ) 1,100.3 Contract-based intangibles 281.4 (69.2 ) 212.2 281.4 (13.5 ) 267.9 IDRs (1) -- -- -- 855.4 -- 855.4 Segment total 2,485.8 (108.3 ) 2,377.5 2,244.8 (21.2 ) 2,223.6 Natural Gas Pipelines & Services: Customer relationship intangibles 1,350.3 (366.3 ) 984.0 1,163.6 (308.9 ) 854.7 Contract-based intangibles 464.7 (361.0 ) 103.7 466.0 (347.8 ) 118.2 Segment total 1,815.0 (727.3 ) 1,087.7 1,629.6 (656.7 ) 972.9 Petrochemical & Refined Products Services: Customer relationship intangibles 185.5 (38.3 ) 147.2 198.4 (43.3 ) 155.1 Contract-based intangibles 56.3 (11.8 ) 44.5 56.3 (7.8 ) 48.5 IDRs (1) -- -- -- 171.2 -- 171.2 Segment total 241.8 (50.1 ) 191.7 425.9 (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 $ 5,273.0 $ (1,235.8 ) 4,037.2 $ 5,548.4 $ (1,246.3 ) $ 4,302.1 (1) We recorded intangible assets having an aggregate carrying value of $1.46 billion in connection with our October 2014 acquisition of the IDRs of Oiltanking. The IDRs represented contractual rights to future cash incentive distributions to be paid by Oiltanking. These rights were granted to Oiltanking GP under the terms of Oiltanking's partnership agreement. Oiltanking GP could separate and sell the IDRs independent of its other residual general partner interest in Oiltanking. In February 2015 (following completion of Step 2 of the Oiltanking acquisition), the Oiltanking IDRs were cancelled and the carrying value of this intangible asset was reclassified to goodwill. (2) Our intangible assets classified within the Offshore Pipelines & Services segment were sold to Genesis in July 2015 (see Note 5). The following table presents the amortization expense of our intangible assets by business segment for the periods indicated: For the Year Ended December 31, 2015 2014 2013 NGL Pipelines & Services $ 33.6 $ 33.1 $ 36.4 Crude Oil Pipelines & Services 87.1 15.7 1.4 Natural Gas Pipelines & Services 40.0 45.0 50.1 Petrochemical & Refined Products Services 8.9 6.9 6.2 Offshore Pipelines & Services 4.5 9.9 11.5 Total $ 174.1 $ 110.6 $ 105.6 The following table presents our forecast of amortization expense associated with existing intangible assets for the years indicated: 2016 2017 2018 2019 2020 $ 181.6 $ 177.4 $ 171.6 $ 167.0 $ 166.3 In general, our intangible assets fall within two categories – customer relationship and contract-based intangible assets. The values assigned to such intangible assets are amortized to earnings using either (i) a straight-line approach or (ii) other methods that closely resemble the pattern in which the economic benefits are estimated to be consumed or otherwise used, as appropriate. Customer relationship intangible assets Customer relationship intangible assets represent the estimated economic value assigned to commercial relationships acquired in connection with business combinations. Our customer relationship intangible assets can be classified as either (i) basin-specific or (ii) general. In certain instances, the acquisition of these intangible assets represents obtaining access to customers in a defined resource basin analogous to having a franchise in a particular area. Efficient operation of the acquired assets (e.g., a natural gas gathering system) helps to support commercial relationships with existing producers and provides us with opportunities to establish new ones within our existing asset footprint. The duration of such customer relationships is limited by the estimated economic life of the associated resource basin. In other situations, the acquisition of a customer relationship intangible asset provides us with access to customers whose hydrocarbon volumes are not attributable to specific resource basins. As with basin-specific customer relationships, efficient operation of the associated assets (e.g., a marine terminal that handles volumes originating from multiple sources) helps to support commercial relationships with existing customers and provides us with opportunities to establish new ones. The duration of these general customer relationships is typically limited to the term of the underlying service contracts, including assumed renewals. Amortization expense attributable to customer relationships is recorded in a manner that closely resembles the pattern in which we expect to benefit from providing services to customers. At December 31, 2015, the carrying value of our portfolio of customer relationship intangible assets was $3.59 billion, the principal components of which are as follows: Weighted Average Remaining Amortization Period at December 31, 2015 December 31, 2015 Gross Value Accumulated Amortization Carrying Value Basin-specific customer relationships: EFS Midstream (1) 26.4 years $ 1,409.8 $ (26.2 ) $ 1,383.6 State Line and Fairplay (2) 31.2 years 895.0 (141.7 ) 753.3 San Juan Gathering (3) 23.8 years 331.3 (196.4 ) 134.9 Encinal (4) 11.0 years 132.9 (86.9 ) 46.0 General customer relationships: Oiltanking (5) 28.0 years 1,192.5 (11.5 ) 1,181.0 (1) We acquired these intangible assets in connection with our acquisition of EFS Midstream in July 2015 (see Note 12 for additional information). (2) These customer relationships are associated with our State Line and Fairplay Gathering Systems, which we acquired in 2010. The State Line system serves producers in the Haynesville and Bossier Shale supply basins and the Cotton Valley and Taylor Sand formations in Louisiana and eastern Texas. The Fairplay system serves producers in the Cotton Valley and Taylor Sand formations within Panola and Rusk counties in East Texas. (3) These customer relationships are associated with our San Juan Gathering System, which serves producers in the San Juan Basin of northern New Mexico and southern Colorado. We acquired this intangible asset in 2004. (4) These customer relationships are associated with our Encinal Gathering System, which serves producers in the Olmos and Wilcox formations in South Texas. We acquired this intangible asset in 2006. (5) We acquired these intangible assets in connection with our acquisition of Oiltanking in October 2014 (see Note 12 for additional information). EFS Midstream customer relationships We recorded $1.41 billion of customer relationships in connection with our acquisition of EFS Midstream in July 2015. The EFS Midstream System serves producers in the Eagle Ford Shale, providing condensate gathering and processing services as well as gathering, treating and compression services for associated natural gas. The estimated fair value of these customer relationship intangible assets was determined using an income approach, specifically a discounted cash flow analysis. The EFS Midstream customer relationships provide us with long-term access to the natural gas, NGL and condensate resources served by EFS Midstream. Infrastructure like 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 (e.g., Pioneer and Reliance) that establish a customer base. The level of expenditures involved in constructing these asset networks can create significant economic barriers to entry that effectively limit competition. 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, including long-range cash flow forecasts that extend for the estimated economic life of the hydrocarbon resource base served by the asset network, anticipated service contract renewals and resource base depletion rates. A discount rate of 15% was applied to the resulting cash flows. Oiltanking customer relationships We recorded $1.19 billion of customer relationships in connection with our acquisition of Oiltanking in October 2014. These intangible assets represent the estimated value of the expected patronage of Oiltanking's third party storage and terminal customers. We valued the customer relationships using an income approach, specifically a discounted cash flow analysis. Our analysis was based on forecasting revenue for the existing terminal customers, including assumed service contract renewals, and then adjusting for expected customer attrition rates. The operating cash flows were then reduced by contributory asset charges. The cash flow projections were based on forecasts used to price the Oiltanking acquisition. The discounted cash flow analysis used to estimate the fair value of the Oiltanking customer relationships relied on Level 3 fair value inputs, including long-range cash flow forecasts that extend for the estimated economic life of the terminal assets and anticipated service contract renewals. A discount rate of 6.5% was applied to the resulting cash flows. Contract-based intangible assets Contract-based intangible assets represent specific commercial rights we acquired in connection with business combinations or asset purchases. At December 31, 2015, the carrying value of our contract-based intangible assets was $450.2 million. Our most significant contract-based intangible assets are the Oiltanking customer contracts and the Jonah natural gas gathering agreements. Oiltanking customer contracts We recorded $297.4 million of contract-based intangible assets in connection with our acquisition of Oiltanking in October 2014. These intangible assets represent the estimated value of specific commercial rights we acquired in connection with third party customer storage and terminal contracts at the Houston and Beaumont terminals. We valued the contracts using an income approach. If a contract was in its renewal period and had not been cancelled, we assumed the contract was renewed on equivalent terms to the prior contract. We only valued those contracts that specified a minimum monthly fee, excluding contracts with a de minimis fee. At December 31, 2015, the carrying value of this group of intangible assets was $225.1 million and the weighted average remaining amortization period for the group was 5.2 years. Amortization expense attributable to these contracts is recorded using a straight-line approach over the terms of the underlying contracts. Jonah natural gas gathering agreements These intangible assets represent the value attributed to certain natural gas gathering contracts on the Jonah Gathering System. At December 31, 2015, the carrying value of this group of intangible assets was $ million and the weighted average remaining amortization period for the group was 26.0 years. Amortization expense attributable to these intangible assets is recorded using a units-of-production method based on gathering volumes. 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. Goodwill is not amortized; however, it is subject to annual impairment testing at the end of each fiscal year, and more frequently, if circumstances indicate it is probable that the fair value of goodwill is below its carrying amount. The following table presents changes in the carrying amount of goodwill during the periods indicated: NGL Pipelines & Services Crude Oil Pipelines & Services Natural Gas Pipelines & Services Petrochemical & Refined Products Services Offshore Pipelines & Services Consolidated Total Balance at December 31, 2012 $ 341.2 $ 311.2 $ 296.3 $ 1,056.0 $ 82.1 $ 2,086.8 Reduction in goodwill related to the sale of assets -- (6.1 ) -- (0.7 ) -- (6.8 ) Balance at December 31, 2013 341.2 305.1 296.3 1,055.3 82.1 2,080.0 Reclassification of goodwill between segments 520.0 -- -- (520.0 ) -- -- Reduction in goodwill related to the sale of assets -- -- -- -- (0.1 ) (0.1 ) Addition to goodwill related to the acquisition of Oiltanking 1,349.0 613.6 -- 257.7 -- 2,220.3 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 -- (2.1 ) -- -- (82.0 ) (84.1 ) Addition to goodwill related to the acquisition of EFS Midstream 8.9 73.7 -- -- -- 82.6 Goodwill reclassified to assets held-for-sale -- -- -- (7.6 ) -- (7.6 ) Balance at December 31, 2015 $ 2,651.7 $ 1,841.0 $ 296.3 $ 956.2 $ -- $ 5,745.2 We did not record any goodwill impairment charges in 2015, 2014 or 2013. Based on our most recent goodwill impairment test at December 31, 2015, each reporting unit's fair value was substantially in excess of its carrying value (i.e., by at least 10%). Upon completion of Step 1 of the Oiltanking acquisition in October 2014, we recorded $2.22 billion of goodwill. This amount includes retrospective adjustments to the fair value of the Liquidity Option Agreement made in 2015 (see Note 17). Upon completion of Step 2 of the Oiltanking acquisition in February 2015, the IDRs of Oiltanking were cancelled and the associated $1.45 billion carrying value of this identifiable intangible asset was reclassified to goodwill. In the aggregate, we recorded $3.67 billion of goodwill in connection with the Oiltanking acquisition. Factors contributing to the recognition of goodwill in the Oiltanking acquisition include (i) opportunities for new business and repurposing existing assets for "best use" in order to meet anticipated increased demand for export and logistical services related to North American crude oil, condensate and NGL production, (ii) securing ownership and control of assets that are essential to our other midstream assets and (iii) cost savings from integrating Oiltanking's operations into our midstream asset network. See Note 12 for additional information regarding the Oiltanking acquisition. In July 2015, we recorded $82.6 million of goodwill in connection with our acquisition of EFS Midstream (see Note 12). In general, we attribute this goodwill to our ability to leverage the acquired business with our existing midstream asset network to create future business opportunities. In July 2015, we removed $82.0 million of goodwill in connection with sale of the Offshore Business (see Note 5).

Debt Obligations

Debt Obligations	12 Months Ended
	Dec. 31, 2015
Debt Obligations [Abstract]
Debt Obligations	The following table presents our consolidated debt obligations (arranged by company and maturity date) at the dates indicated: December 31, 2015 2014 EPO senior debt obligations: Commercial Paper Notes, variable-rates $ 1,114.1 $ 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 21,264.1 19,856.5 EPO Junior Subordinated Notes A, fixed/variable-rate, due August 2066 521.1 550.0 EPO Junior Subordinated Notes C, fixed/variable-rate, due June 2067 256.4 285.8 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 22,738.5 21,389.2 Other, non-principal amounts (47.9 ) (25.4 ) Less current maturities of debt (1,863.9 ) (2,206.4 ) Total long-term debt $ 20,826.7 $ 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 3.708%. (2) Fixed rate of 7.000% through September 1, 2017 (i.e., first call date without a make-whole redemption premium); thereafter, variable rate based on 3-month LIBOR plus 2.778%. (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 2.680%. The following table presents contractually scheduled maturities of our consolidated debt obligations outstanding at December 31, 2015 for the next five years, and in total thereafter: Scheduled Maturities of Debt Total 2016 2017 2018 2019 2020 Thereafter Commercial Paper Notes $ 1,114.1 $ 1,114.1 $ -- $ -- $ -- $ -- $ -- Senior Notes 20,150.0 750.0 800.0 1,100.0 1,500.0 1,500.0 14,500.0 Junior Subordinated Notes 1,474.4 -- -- -- -- -- 1,474.4 Total $ 22,738.5 $ 1,864.1 $ 800.0 $ 1,100.0 $ 1,500.0 $ 1,500.0 $ 15,974.4 In February 2016, we repaid EPO's $750 million Senior Notes AA using available cash, borrowings under our Multi-Year Revolving Credit Facility and proceeds from the issuance of short-term notes under our commercial paper program. Parent-Subsidiary Guarantor Relationships Enterprise Products Partners L.P. acts as guarantor of the consolidated debt obligations of EPO, with the exception of the remaining debt obligations of TEPPCO. If EPO were to default on any of its guaranteed debt, Enterprise Products Partners L.P. would be responsible for full and unconditional repayment of that obligation. EPO Debt Obligations Commercial Paper Notes 364-Day Credit Agreement . The 364-Day Credit Agreement contains customary representations, warranties, covenants (affirmative and negative) and events of default, the occurrence of which would permit the lenders to accelerate the maturity date of any amounts borrowed under the 364-Day Credit Agreement. The 364-Day Credit Agreement also restricts EPO's ability to pay cash distributions to its parent, Enterprise Products Partners L.P., if a default or an event of default (as defined in the 364-Day Credit Agreement) has occurred and is continuing at the time such distribution is scheduled to be paid or would result therefrom. Multi-Year Revolving Credit Facility . As defined by the credit agreement, variable interest rates charged under this revolving credit facility bear interest at LIBOR plus an applicable margin. In addition, EPO is required to pay a quarterly facility fee on each lender's commitment irrespective of commitment usage. This revolving credit facility allows us to request up to two one-year extensions of the maturity date, subject to lender approval. The Multi-Year Revolving Credit Facility contains certain financial and other customary affirmative and negative covenants. The credit agreement also restricts EPO's ability to pay cash distributions to Enterprise Products Partners L.P. if a default or an event of default (as defined in the credit agreement) has occurred and is continuing at the time such distribution is scheduled to be paid. EPO's borrowings under this revolving credit facility are unsecured general obligations that are guaranteed by Enterprise Products Partners L.P. and are non-recourse to Enterprise GP. Senior Notes 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. Junior Subordinated Notes . In connection with the issuance of each series of junior notes, EPO entered into separate Replacement Capital Covenants in favor of covered debt holders (as defined in the underlying documents) pursuant to which EPO agreed, for the benefit of such debt holders, that it would not redeem or repurchase such junior notes unless such redemption or repurchase is made using proceeds from the issuance of certain securities. During 2015, EPO repurchased and retired $28.9 million in principal amount of its Junior Subordinated Notes A and $29.4 million in principal amount of its Junior Subordinated Notes C with cash from operations. A $1.6 million gain on the extinguishment of these debt obligations is included in "Other, net" on our Statements of Consolidated Operations. The following table summarizes the interest rate terms of our junior subordinated notes: Series Fixed Annual Interest Rate Variable Annual Interest Rate Thereafter Junior Subordinated Notes A 8.375% through August 2016 3-month LIBOR rate + 3.708% (4) Junior Subordinated Notes B 7.034% through January 2018 (2) Greater of: (i) 3-month LIBOR rate + 2.680% or (ii) 7.034% (5) Junior Subordinated Notes C 7.000% through September 2017 (3) 3-month LIBOR rate + 2.778% (1) Interest is payable semi-annually in arrears in February and August of each year, which commenced in February 2007. (2) Interest is payable semi-annually in arrears in January and July of each year, which commenced in January 2008. (3) Interest is payable semi-annually in arrears in June and December of each year, which commenced in December 2009. (4) Interest is payable quarterly in arrears in February, May, August and November of each year commencing in November 2016. (5) Interest is payable quarterly in arrears in January, April, July and October of each year commencing in April 2018. (6) Interest is payable quarterly in arrears in March, June, September and December of each year commencing in June 2017. Letters of Credit At December 31, 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 December 31, 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 year ended December 31, 2015: Range of Interest Rates Paid Weighted-Average Interest Rate Paid Commercial Paper Notes 0.35% to 0.92% 0.58% Multi-Year Revolving Credit Facility 1.15% to 3.25% 1.30% Debt Issuance Costs At December 31, 2015, we had $159.8 million of unamortized debt issuance costs recorded as assets, of which $149.8 million was attributable to senior and junior subordinated note obligations (collectively referred to as "bond issuance costs") and $10.0 million attributable to revolving credit arrangements. In accordance with recently issued accounting guidance effective January 1, 2016, the unamortized bond issuance costs will be presented as a reduction in the carrying amount of debt (as opposed to an asset), consistent with the presentation of debt discounts.

Equity and Distributions

Equity and Distributions	12 Months Ended
	Dec. 31, 2015
Equity and Distributions [Abstract]
Equity and Distributions	Partners Equity Partners' equity reflects the various classes of limited partner interests (i.e., common units, including restricted common units, and Class B units) that we have outstanding. The following table summarizes changes in the number of our outstanding units since December 31, 2012: Common Units (Unrestricted) Restricted Common Units Total Common Units Number of units outstanding at December 31, 2012 1,789,839,702 7,786,972 1,797,626,674 Common units issued in connection with underwritten offering 36,800,000 -- 36,800,000 Common units issued in connection with ATM program 15,249,378 -- 15,249,378 Common units issued in connection with DRIP and EUPP 10,308,254 -- 10,308,254 Common units issued in connection with the vesting and exercise of unit options 401,764 -- 401,764 Common units issued in connection with the vesting of restricted common unit awards 3,770,696 (3,770,696 ) -- Conversion and reclassification of Class B units to common units 9,040,862 -- 9,040,862 Restricted common unit awards issued -- 3,549,052 3,549,052 Forfeiture of restricted common unit awards -- (344,114 ) (344,114 ) Acquisition and cancellation of treasury units in connection with the vesting of equity-based awards (1,261,854 ) -- (1,261,854 ) Number of units outstanding at December 31, 2013 1,864,148,802 7,221,214 1,871,370,016 Common units issued in connection with ATM program 1,590,334 -- 1,590,334 Common units issued in connection with DRIP and EUPP 9,754,227 -- 9,754,227 Common units issued in connection with Step 1 of Oiltanking acquisition 54,807,352 -- 54,807,352 Common units issued in connection with the vesting and exercise of unit options 1,014,108 -- 1,014,108 Common units issued in connection with the vesting of phantom unit awards 23,311 -- 23,311 Common units issued in connection with the vesting of restricted common unit awards 2,634,074 (2,634,074 ) -- Forfeiture of restricted common unit awards -- (357,350 ) (357,350 ) Acquisition and cancellation of treasury units in connection with the vesting of equity-based awards (894,383 ) -- (894,383 ) Other 17,202 -- 17,202 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 25,520,424 -- 25,520,424 Common units issued in connection with DRIP and EUPP 12,793,913 -- 12,793,913 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 396,158 -- 396,158 Common units issued in connection with the vesting of phantom unit awards 618,395 -- 618,395 Common units issued in connection with the vesting of restricted common unit awards 2,009,970 (2,009,970 ) -- Forfeiture of restricted common unit awards -- (259,300 ) (259,300 ) Acquisition and cancellation of treasury units in connection with the vesting of equity-based awards (683,954 ) -- (683,954 ) Other 15,054 -- 15,054 Number of units outstanding at December 31, 2015 2,010,592,504 1,960,520 2,012,553,024 In accordance with our Partnership Agreement, capital accounts are maintained for our limited partners. The capital account provisions of our Partnership Agreement incorporate principles established for U.S. Federal income tax purposes and are not comparable to the equity amounts presented in our consolidated financial statements prepared in accordance with GAAP. Earnings and cash distributions are allocated to holders of our common units in accordance with their respective percentage interests. 2013 Shelf .  We used the 2010 Shelf to issue 18,400,000 common units to the public (including an over-allotment amount of 2,400,000 common units) at an offering price of $27.28 per unit in February 2013, which generated net cash proceeds of $486.6 million. In addition, EPO issued $2.25 billion of unsecured senior notes during 2013 using the 2010 Shelf.  We used the 2013 Shelf to issue 18,400,000 common units to the public (including an over-allotment amount of 2,400,000 common units) at an offering price of $31.03 per unit in November 2013, which generated net cash proceeds of $553.0 million.  We used the 2013 Shelf to issue $4.75 billion of unsecured senior notes during 2014.  We used the 2013 Shelf to issue $2.5 billion of unsecured senior notes during 2015 (see Note 8). At-the-Market ("ATM") Program . During 2015, we issued 25,520,424 common units under our ATM program for aggregate gross cash proceeds of $825.4 million, resulting in total net cash proceeds of $817.4 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. During 2014, we issued 1,590,334 common units under our ATM program for aggregate gross cash proceeds of $58.3 million, resulting in total net cash proceeds of $57.7 million. During 2013, we issued 15,249,378 common units under our ATM for aggregate gross cash proceeds of $460.4 million, resulting in total net cash proceeds of $456.3 million. 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 December 31, 2015, we have the capacity to issue additional common units under our ATM program up to an aggregate sales price of $1.86 billion. DRIP and EUPP . 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 an employee unit purchase plan ("EUPP"). Activity under our EUPP for the last three years was as follows: 380,562 common units issued during 2015, which generated net cash proceeds of $11.4 million; 273,820 common units issued during 2014, which generated net cash proceeds of $9.8 million; and 283,426 common units issued during 2013, which generated net cash proceeds of $8.5 million. After taking into account the number of common units issued under the EUPP through December 31, 2015, we may issue an additional 6,772,506 common units under this plan. The net cash proceeds we received from the issuance of common units during the year ended December 31, 2015 were used to temporarily reduce amounts outstanding under EPO's commercial paper program and revolving credit facilities and for general company purposes. Registration Rights Agreement Completion of Oiltanking Acquisition . 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 Class B Units Treasury Units A total of 2,009,970 restricted common unit awards granted to employees of EPCO vested and converted to common units during the year ended December 31, 2015. Of this amount, 683,954 were sold back to us by employees to cover related withholding tax requirements. The total cost of these treasury unit purchases was approximately $33.6 million. We cancelled such treasury units immediately upon acquisition. See Note 13 for additional information regarding our equity-based awards. Two-for-One Split of Limited Partner Units Accumulated Other Comprehensive Loss Accumulated other comprehensive income (loss) primarily reflects the effective portion of the gain or loss on derivative instruments designated and qualified as cash flow hedges. Gain or loss amounts related to cash flow hedges recorded in accumulated other comprehensive income (loss) are reclassified to earnings in the same period(s) in which the underlying hedged forecasted transactions affect earnings. If it becomes probable that a forecasted transaction will not occur, the related net gain or loss in accumulated other comprehensive income (loss) is immediately reclassified into earnings. The following tables present the components of accumulated other comprehensive income (loss) as reported on our 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, 2013 $ (14.7 ) $ (347.2 ) $ 2.9 $ (359.0 ) Other comprehensive income before reclassifications 161.3 -- 0.4 161.7 Amounts reclassified from accumulated other comprehensive (income) loss (76.7 ) 32.4 -- (44.3 ) Total other comprehensive income 84.6 32.4 0.4 117.4 Balance, December 31, 2014 69.9 (314.8 ) 3.3 (241.6 ) Other comprehensive income before reclassifications 214.9 -- 0.4 215.3 Amounts reclassified from accumulated other comprehensive (income) loss (228.2 ) 35.3 -- (192.9 ) Total other comprehensive income (loss) (13.3 ) 35.3 0.4 22.4 Balance, December 31, 2015 $ 56.6 $ (279.5 ) $ 3.7 $ (219.2 ) The following table presents reclassifications out of accumulated other comprehensive income (loss) into net income during the periods indicated: For the Year Ended December 31, Location 2015 2014 Losses (gains) on cash flow hedges: Interest rate derivatives Interest expense $ 35.3 $ 32.4 Commodity derivatives Revenue (231.7 ) (75.0 ) Commodity derivatives Operating costs and expenses 3.5 (1.7 ) Total $ (192.9 ) $ (44.3 ) Noncontrolling Interests Noncontrolling interests represent third party equity ownership interests in our consolidated subsidiaries. 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 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 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. The following table presents additional information regarding noncontrolling interests as presented on our Consolidated Balance Sheets at the dates indicated: December 31, 2015 2014 Limited partners of Oiltanking other than EPO $ -- $ 1,408.9 Joint venture partners 206.0 220.1 Total $ 206.0 $ 1,629.0 The following table presents the components of net income attributable to noncontrolling interests as presented on our Statements of Consolidated Operations for the periods indicated: For the Year Ended December 31, 2015 2014 2013 Limited partners of Oiltanking other than EPO $ 7.8 $ 14.2 $ -- Joint venture partners 29.4 31.9 10.2 Total $ 37.2 $ 46.1 $ 10.2 The following table presents cash distributions paid to and cash contributions received from noncontrolling interests as presented on our Statements of Consolidated Cash Flows and Statements of Consolidated Equity for the periods indicated: For the Year Ended December 31, 2015 2014 2013 Cash distributions paid to noncontrolling interests: Limited partners of Oiltanking other than EPO $ 8.1 $ 7.7 $ -- Joint venture partners 39.9 40.9 8.9 Total $ 48.0 $ 48.6 $ 8.9 Cash contributions from noncontrolling interests: Joint venture partners $ 54.0 $ 4.0 $ 115.4 Cash Distributions The following table presents Enterprise's declared quarterly cash distribution rates per common unit with respect to the quarter indicated. Actual cash distributions are paid by Enterprise within 45 days after the end of each fiscal quarter. 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 4th Quarter $ 0.3700 1/30/2015 2/6/2015 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 4th Quarter $ 0.3900 1/29/2016 2/5/2016 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 to partners during calendar years 2013, 2014 and 2015 excluded 47,400,000, 45,120,000 and 35,380,000 Designated Units, respectively. The temporary distribution waiver expired in November 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	12 Months Ended
	Dec. 31, 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. Financial information regarding these segments is evaluated regularly by our chief operating decision makers in deciding how to allocate resources and in assessing operating and financial performance. The President and the Chief Executive Officer of our general partner have been identified as our chief operating decision makers. While these two officers evaluate results in a number of different ways, the business segment structure is the primary basis for which the allocation of resources and financial results are assessed. The following information summarizes the current assets and operations of each business segment (mileage and other statistics are unaudited):  Our NGL Pipelines & Services business segment includes our natural gas processing plants and related NGL marketing activities; approximately 19,500 miles of NGL pipelines; NGL and related product storage facilities; and 15 NGL fractionators. This segment also includes our NGL export docks and related operations.  Our Crude Oil Pipelines & Services business segment includes approximately 5,400 miles of crude oil pipelines, crude oil storage terminals located in Oklahoma and Texas, and our crude oil marketing activities. This segment also includes a fleet of 478 tractor-trailer tank trucks, the majority of which we lease and operate, used to transport crude oil for us and third parties.  Our Natural Gas Pipelines & Services business segment includes approximately 19,100 miles of natural gas pipeline systems that provide for the gathering and transportation of natural gas in Colorado, Louisiana, New Mexico, Texas and Wyoming. We lease underground salt dome natural gas storage facilities located in Texas and Louisiana and own an underground salt dome storage cavern in Texas, all of which are important to our natural gas pipeline operations. This segment also includes our related natural gas marketing activities.  Our Petrochemical & Refined Products Services business segment includes (i) propylene fractionation and related operations, including 674 miles of pipelines; (ii) a butane isomerization complex, associated deisobutanizer units and related pipeline assets; (iii) octane enhancement and high purity isobutylene production facilities; (iv) refined products pipelines aggregating approximately 4,200 miles, terminals and related marketing activities; and (v) marine transportation.  Our Offshore Pipelines & Services business segment, which served some of the most active drilling and development regions, including deepwater production fields, in the northern Gulf of Mexico offshore Texas, Louisiana, Mississippi and Alabama was sold, effective July 24, 2015. Our results of operations reflect ownership of the Offshore Business through July 24, 2015 (see Note 5). 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. We include equity in income of unconsolidated affiliates in our measurement of segment gross operating margin and operating income. Equity investments with industry partners are a significant component of our business strategy. They are a means by which we conduct our operations to align our interests with those of customers and/or suppliers. This method of operation enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed. Many of these businesses perform supporting or complementary roles to our other midstream business operations. Our integrated midstream energy asset network (including the midstream energy assets owned by our equity method investees) provides services to producers and consumers of natural gas, NGLs, crude oil, refined products and certain petrochemicals. In general, hydrocarbons may enter our asset system in a number of ways, such as through a natural gas processing plant, a natural gas gathering pipeline, a crude oil pipeline or terminal, an NGL fractionator, an NGL storage facility or an NGL gathering or transportation pipeline. Many of our equity investees are included within our integrated midstream asset network. For example, we use the Texas Express Pipeline to transport mixed NGLs to our Mont Belvieu complex for fractionation and storage. Given the integral nature of our equity method investees to our operations, we believe the presentation of equity earnings from such investees as a component of gross operating margin and operating income is meaningful and appropriate. 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 remainder of our consolidated total assets, which consist primarily of working capital assets, are excluded from segment assets since these amounts are not attributable to one specific segment (e.g. cash). The results of operations from our liquids pipelines are primarily dependent upon the volumes transported and the associated fees we charge for such transportation services. Typically, pipeline transportation revenue is recognized when volumes are re-delivered to customers. However, under certain pipeline transportation agreements, customers are required to ship a minimum volume over an agreed-upon period. These arrangements typically entail the shipper paying a transportation fee based on a minimum volume commitment, with a provision that allows the shipper to make-up any volume shortfalls over the agreed-upon period (referred to as shipper "make-up rights"). Revenue pursuant to such agreements, including that associated with make-up rights, is initially deferred and subsequently recognized at the earlier of when the deficiency volume is shipped, when the shipper's ability to meet the minimum volume commitment has expired (typically a one year contractual period), or when the pipeline is otherwise released from its transportation service performance obligation. However, management includes deferred transportation revenues relating to the "make-up rights" of committed shippers when reviewing the financial results of certain major new pipeline projects. From an internal (and segment) reporting standpoint, management considers the transportation fees paid by committed shippers on major new pipeline projects, including any non-refundable revenues that may be deferred under GAAP related to make-up rights, to be important in assessing the financial performance of these pipeline assets. Since management includes these deferred revenues in non-GAAP gross operating margin, these amounts are deducted in determining GAAP-based operating income. Our consolidated revenues do not reflect any deferred revenues until the conditions for recognizing such revenues are met in accordance with GAAP. Several of our major new liquids pipeline projects experienced periods where shippers were unable to meet their contractual minimum volume commitments. In general, we expect that these types of shortfalls will continue in 2016 due to the current business environment, with the recognition of revenue associated with past deferrals associated with make-up rights partially or entirely offsetting any new make-up right deferrals. The following table presents our measurement of non-GAAP total segment gross operating margin for the periods indicated: For the Year Ended December 31, 2015 2014 2013 Revenues $ 27,027.9 $ 47,951.2 $ 47,727.0 Subtract operating costs and expenses (23,668.7 ) (44,220.5 ) (44,238.7 ) Add equity in income of unconsolidated affiliates 373.6 259.5 167.3 Add depreciation, amortization and accretion expense amounts not reflected in gross operating margin 1,428.2 1,282.7 1,148.9 Add impairment charges not reflected in gross operating margin 162.6 34.0 92.6 Add net losses or subtract net gains attributable to asset sales and insurance recoveries not reflected in gross operating margin (see Note 19) 15.6 (102.1 ) (83.4 ) Add non-refundable deferred revenues attributable to shipper make-up rights on major new pipeline projects reflected in gross operating margin 53.6 84.6 4.4 Subtract subsequent recognition of deferred revenues attributable to make-up rights not reflected in gross operating margin (60.7 ) (2.9 ) -- Total segment gross operating margin $ 5,332.1 $ 5,286.5 $ 4,818.1 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 Year Ended December 31, 2015 2014 2013 Total segment gross operating margin $ 5,332.1 $ 5,286.5 $ 4,818.1 Adjustments to reconcile total segment gross operating margin to operating income: Subtract depreciation, amortization and accretion expense amounts not reflected in gross operating margin (1,428.2 ) (1,282.7 ) (1,148.9 ) Subtract impairment charges not reflected in gross operating margin (162.6 ) (34.0 ) (92.6 ) Add net gains or subtract net losses attributable to asset sales and insurance recoveries not reflected in gross operating margin (15.6 ) 102.1 83.4 Subtract non-refundable deferred revenues attributable to shipper make-up rights on major new pipeline projects reflected in gross operating margin (53.6 ) (84.6 ) (4.4 ) Add subsequent recognition of deferred revenues attributable to make-up rights not reflected in gross operating margin 60.7 2.9 -- Subtract general and administrative costs not reflected in gross operating margin (192.6 ) (214.5 ) (188.3 ) Operating income 3,540.2 3,775.7 3,467.3 Other expense, net (984.3 ) (919.1 ) (802.7 ) Income before income taxes $ 2,555.9 $ 2,856.6 $ 2,664.6 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: Year ended December 31, 2015 $ 9,779.0 $ 10,258.3 $ 2,729.5 $ 4,111.9 $ 76.9 $ -- $ 26,955.6 Year ended December 31, 2014 17,078.4 20,151.9 4,182.6 6,316.5 150.3 -- 47,879.7 Year ended December 31, 2013 17,119.1 20,609.1 3,522.7 6,258.5 151.7 -- 47,661.1 Revenues from related parties: Year ended December 31, 2015 9.0 47.6 13.8 -- 1.9 -- 72.3 Year ended December 31, 2014 11.4 32.4 21.2 -- 6.5 -- 71.5 Year ended December 31, 2013 1.1 41.3 15.8 -- 7.7 -- 65.9 Intersegment and intrasegment revenues: Year ended December 31, 2015 10,217.9 5,162.0 662.1 1,126.0 0.6 (17,168.6 ) -- Year ended December 31, 2014 13,716.5 12,678.7 1,106.7 1,779.6 6.5 (29,288.0 ) -- Year ended December 31, 2013 11,096.6 10,222.3 959.7 1,764.0 9.6 (24,052.2 ) -- Total revenues: Year ended December 31, 2015 20,005.9 15,467.9 3,405.4 5,237.9 79.4 (17,168.6 ) 27,027.9 Year ended December 31, 2014 30,806.3 32,863.0 5,310.5 8,096.1 163.3 (29,288.0 ) 47,951.2 Year ended December 31, 2013 28,216.8 30,872.7 4,498.2 8,022.5 169.0 (24,052.2 ) 47,727.0 Equity in income (loss) of unconsolidated affiliates: Year ended December 31, 2015 57.5 281.4 3.8 (15.7 ) 46.6 -- 373.6 Year ended December 31, 2014 30.6 184.6 3.6 (13.3 ) 54.0 -- 259.5 Year ended December 31, 2013 15.7 140.3 3.8 (22.3 ) 29.8 -- 167.3 Gross operating margin: Year ended December 31, 2015 2,771.6 961.9 782.6 718.5 97.5 -- 5,332.1 Year ended December 31, 2014 2,877.7 762.5 803.3 681.0 162.0 -- 5,286.5 Year ended December 31, 2013 2,514.4 742.7 789.0 625.9 146.1 -- 4,818.1 Property, plant and equipment, net: At December 31, 2015 12,909.7 3,550.3 8,620.0 3,060.7 -- 3,894.0 32,034.7 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 At December 31, 2013 9,957.8 1,479.9 8,917.3 2,712.4 1,223.7 2,655.5 26,946.6 Investments in unconsolidated affiliates: At December 31, 2015 718.7 1,813.4 22.5 73.9 -- -- 2,628.5 At December 31, 2014 682.3 1,767.7 23.2 75.1 493.7 -- 3,042.0 At December 31, 2013 645.5 1,165.2 24.2 70.4 531.8 -- 2,437.1 Intangible assets, net: At December 31, 2015 380.3 2,377.5 1,087.7 191.7 -- -- 4,037.2 At December 31, 2014 689.2 2,223.6 972.9 374.8 41.6 -- 4,302.1 At December 31, 2013 285.2 4.5 1,017.8 100.0 54.7 -- 1,462.2 Goodwill: At December 31, 2015 2,651.7 1,841.0 296.3 956.2 -- -- 5,745.2 At December 31, 2014 2,210.2 918.7 296.3 793.0 82.0 -- 4,300.2 At December 31, 2013 341.2 305.1 296.3 1,055.3 82.1 -- 2,080.0 Segment assets: At December 31, 2015 16,660.4 9,582.2 10,026.5 4,282.5 -- 3,894.0 44,445.6 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 At December 31, 2013 11,229.7 2,954.7 10,255.6 3,938.1 1,892.3 2,655.5 32,925.9 The following table presents additional information regarding our consolidated revenues and costs and expenses for the periods indicated: For the Year Ended December 31, 2015 2014 2013 NGL Pipelines & Services: Sales of NGLs and related products $ 8,044.8 $ 15,460.1 $ 15,916.0 Midstream services 1,743.2 1,629.7 1,204.2 Total 9,788.0 17,089.8 17,120.2 Crude Oil Pipelines & Services: Sales of crude oil 9,732.9 19,783.9 20,371.3 Midstream services 573.0 400.4 279.1 Total 10,305.9 20,184.3 20,650.4 Natural Gas Pipelines & Services: Sales of natural gas 1,722.6 3,181.7 2,571.6 Midstream services 1,020.7 1,022.1 966.9 Total 2,743.3 4,203.8 3,538.5 Petrochemical & Refined Products Services: Sales of petrochemicals and refined products 3,333.5 5,575.5 5,568.8 Midstream services 778.4 741.0 689.7 Total 4,111.9 6,316.5 6,258.5 Offshore Pipelines & Services: Sales of natural gas -- 0.3 0.5 Sales of crude oil 3.2 8.6 5.7 Midstream services 75.6 147.9 153.2 Total 78.8 156.8 159.4 Total consolidated revenues $ 27,027.9 $ 47,951.2 $ 47,727.0 Consolidated costs and expenses Operating costs and expenses: Cost of sales $ 19,612.9 $ 40,464.1 $ 40,770.2 Other operating costs and expenses (1) 2,449.4 2,541.8 2,310.4 Depreciation, amortization and accretion 1,428.2 1,282.7 1,148.9 Ne t losses (g and insurance recoveries 15.6 (102.1 ) (83.4 ) Non-cash asset impairment charges 162.6 34.0 92.6 General and administrative costs 192.6 214.5 188.3 Total consolidated costs and expenses $ 23,861.3 $ 44,435.0 $ 44,427.0 (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. Major Customer Information Our largest non-affiliated customer for 2015 was Shell Oil Company and its affiliates (collectively, "Shell"), which accounted for $2.0 billion, or 7.4%, of our consolidated revenues for the year. The following table presents our consolidated revenues from Shell by business segment for the year ended December 31, 2015: NGL Pipelines & Services $ 400.4 Crude Oil Pipelines & Services 1,335.8 Natural Gas Pipelines & Services 48.6 Petrochemical & Refined Products Services 206.5 Offshore Pipelines & Services 8.0 Total $ 1,999.3 Shell was also our largest non-affiliated customer for 2014, accounting for 8.5% of our consolidated revenues for the year ended December 31, 2014. BP p.l.c. and its affiliates was our largest non-affiliated customer for 2013, accounting for 9.0% of our consolidated revenues for the year ended December 31, 2013.

Earnings Per Unit

Earnings Per Unit	12 Months Ended
	Dec. 31, 2015
Earnings Per Unit [Abstract]
Earnings Per Unit	Basic earnings per unit is computed by dividing net income or loss available to our common unitholders by the weighted-average number of our distribution-bearing units outstanding during a period, which excludes the Designated Units (see Note 9) to the extent such units do not participate in the distributions to be paid with respect to such period. Diluted earnings per unit is computed by dividing net income or loss attributable to our limited partners by the sum of (i) the weighted-average number of our distribution-bearing units outstanding during a period (as used in determining basic earnings per unit), (ii) the weighted-average number of our Class B units (see Note 9) outstanding during a period, (iii) the weighted-average number of Designated Units outstanding during a period and (iv) the number of incremental common units resulting from the assumed exercise of dilutive unit options outstanding during a period (the "incremental option units"). In a period of net losses, the Class B units, Designated Units and incremental option units are excluded from the calculation of diluted earnings per unit due to their antidilutive effect. The dilutive incremental option units are calculated using the treasury stock method, which assumes that proceeds from the exercise of all in-the-money options at the end of each period are used to repurchase common units at an average market price during the period. The amount of common units remaining after the proceeds are exhausted represents the potentially dilutive effect of the securities. The following table presents our calculation of basic and diluted earnings per unit for the periods indicated: For the Year Ended December 31, 2015 2014 2013 BASIC EARNINGS PER UNIT Net income attributable to limited partners $ 2,521.2 $ 2,787.4 $ 2,596.9 Undistributed earnings allocated and cash payments on phantom unit awards (1) (8.7 ) (5.2 ) -- Net income available to common unitholders $ 2,512.5 $ 2,782.2 $ 2,596.9 Basic weighted-average number of common units outstanding 1,966.6 1,848.7 1,788.0 Basic earnings per unit $ 1.28 $ 1.51 $ 1.45 DILUTED EARNINGS PER UNIT Net income attributable to limited partners $ 2,521.2 $ 2,787.4 $ 2,596.9 Diluted weighted-average number of units outstanding: Distribution-bearing common units 1,966.6 1,848.7 1,788.0 Designated Units 26.5 42.7 46.8 Class B units (2) -- -- 5.4 Phantom units (1) 5.4 2.9 -- Incremental option units 0.1 0.9 2.4 Total 1,998.6 1,895.2 1,842.6 Diluted earnings per unit $ 1.26 $ 1.47 $ 1.41 (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. (2) The Class B units automatically converted into an equal number of distribution-bearing common units in August 2013.

Business Combinations

Business Combinations	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Business Combinations	Acquisition of EFS Midstream In July 2015, we purchased 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 approximately $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. The EFS Midstream System provides condensate gathering and processing services as well as gathering, treating and compression services for the associated natural gas. The EFS Midstream System includes approximately 460 miles of gathering pipelines, ten central gathering plants, 119 thousand barrels per day of condensate stabilization capacity and 780 million cubic feet per day of associated natural gas treating capacity. Our primary purpose in acquiring the EFS Midstream System was to secure the underlying production, particularly the processed condensate, for our midstream asset network. 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. 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 System. 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 our final purchase price allocation for the EFS Midstream acquisition: Consideration: Cash $ 1,069.9 Accrued liability related to EFS Midstream acquisition 986.6 Total consideration $ 2,056.5 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 (see Note 7) 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 2,056.5 Goodwill $ 82.6 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. Our consolidated revenues and net income include $117.8 million and $59.9 million, respectively, from EFS Midstream for the six months ended December 31, 2015. Since the effective date of the EFS Midstream acquisition was July 1, 2015, our 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 years ended December 31, 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 Year Ended December 31, 2015 2014 Pro forma earnings data: Revenues $ 27,148.5 $ 48,180.4 Costs and expenses 23,937.1 44,583.6 Operating income 3,585.0 3,856.3 Net income 2,594.4 2,896.1 Net income attributable to noncontrolling interests 37.2 46.1 Net income attributable to limited partners 2,557.2 2,850.0 Basic earnings per unit: As reported basic earnings per unit $ 1.28 $ 1.51 Pro forma basic earnings per unit $ 1.30 $ 1.54 Diluted earnings per unit: As reported diluted earnings per unit $ 1.26 $ 1.47 Pro forma diluted earnings per unit $ 1.28 $ 1.50 Acquisition of Oiltanking On October 1, 2014, we acquired Oiltanking GP and the related IDRs, 15,899,802 common units and 38,899,802 subordinated units of Oiltanking from OTA. We paid total consideration of approximately $4.4 billion to OTA comprised of $2.21 billion in cash and 54,807,352 Enterprise common units for these ownership interests and rights. We also paid $228.3 million to assume the outstanding loans, including related accrued interest, owed by Oiltanking or its subsidiaries to OTA. Collectively, these transactions are referred to as "Step 1" of the Oiltanking acquisition. We funded the cash consideration for the Step 1 transactions using borrowings under our 364-Day Credit Agreement, proceeds from the sale of short-term notes under our commercial paper program and cash on hand. As a result of completing Step 1 of the acquisition, we began consolidating the financial statements of Oiltanking and its general partner on October 1, 2014. Oiltanking owned marine terminals located on the Houston Ship Channel and at the Port of Beaumont with a total of 12 ship and barge docks and approximately 26 MMBbls of crude oil and petroleum products storage capacity. Oiltanking's marine terminal on the Houston Ship Channel is connected by pipeline to our Mont Belvieu, Texas complex and is integral to our growing LPG export, crude oil storage and octane enhancement and propylene businesses. Our ECHO facility is also connected to Oiltanking's system. We had a strategic relationship and enjoyed mutual growth with Oiltanking and its predecessors since 1983. The combination of our legacy midstream assets and Oiltanking's access to waterborne markets and crude oil and petroleum products storage assets extended and broadened our midstream energy services business. We engaged an independent third party business valuation expert to assist us in estimating the fair values of the tangible and intangible assets of Oiltanking. The following table summarizes our final purchase price allocation for the Oiltanking acquisition: Consideration: Cash $ 2,438.3 Equity instruments (54,807,352 common units of Enterprise) (1) 2,171.5 Fair value of total consideration transferred in Step 1 $ 4,609.8 Identifiable assets acquired in business combination: Current assets, including cash of $21.5 million $ 68.0 Property, plant and equipment 1,080.1 Identifiable intangible assets: Customer relationship intangible assets 1,192.4 Contract-based intangible assets 297.5 IDRs (2) 1,459.2 Total identifiable intangible assets 2,949.1 Other assets 227.6 Total assets acquired 4,324.8 Liabilities assumed in business combination: Current liabilities (84.8 ) Long-term debt (223.3 ) Other long-term liabilities (3) (230.0 ) Total liabilities assumed (538.1 ) Noncontrolling interest in Oiltanking (1,397.2 ) Total assets acquired less liabilities assumed and noncontrolling interest 2,389.5 Total consideration given for ownership interests in Oiltanking in Step 1 4,609.8 Goodwill $ 2,220.3 (1) The fair value of the equity-based consideration paid in connection with Step 1 of the Oiltanking acquisition was based on the closing market price of our common units of $39.62 per unit on the acquisition date. (2) The IDRs represented contractual rights to future cash incentive distributions to be paid by Oiltanking. These rights were granted to Oiltanking GP under the terms of Oiltanking's partnership agreement. Oiltanking GP could separate and sell the IDRs independent of its other residual general partner interest in Oiltanking. In February 2015 (following completion of Step 2 of the Oiltanking acquisition), the Oiltanking IDRs were cancelled and the carrying value of this intangible asset was reclassified to goodwill. (3) In connection with Step 1, we entered into the Liquidity Option Agreement with OTA and Marquard & Bahls ("M&B", a German corporation and ultimate parent company of OTA). Other long-term liabilities includes $219.7 million for the Liquidity Option Agreement (see Note 17). (4) From an accounting perspective, Enterprise acquired control of Oiltanking as a result of completing Step 1. The estimated fair value of Oiltanking's common units held by parties other than Enterprise following Step 1 (i.e., the "noncontrolling interest") is based on 28,328,890 common units held by third parties on October 1, 2014 multiplied by the closing unit price for Oiltanking common units of $49.32 per unit on that date. Although we are not subject to federal income tax, our partners are individually responsible for paying federal income taxes on their share of our taxable income. In deriving our taxable income, the amount assigned to goodwill in this transaction will be amortized over a period of 15 years. Our consolidated revenues and net income included $57.5 million and $8.1 million, respectively, from Oiltanking for the three months ended December 31, 2014. We incurred $3.8 million of direct transaction costs in connection with Step 1 of the Oiltanking acquisition in the year ended December 31, 2014. These costs are included in general and administrative costs in the accompanying Statements of Consolidated Operations. Since the effective date of Step 1 of the Oiltanking acquisition was October 1, 2014, our 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 year ended December 31, 2014 as if the acquisition had been completed on January 1, 2013. This pro forma information was prepared using historical financial data for Oiltanking 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 year ended December 31, 2014 had we acquired Oiltanking on January 1, 2013. Pro forma earnings data: Revenues $ 48,087.5 Costs and expenses 44,509.0 Operating income 3,838.0 Net income 2,877.5 Net income attributable to noncontrolling interests 75.0 Net income attributable to limited partners 2,802.5 Basic earnings per unit: As reported basic units outstanding 1,848.7 Pro forma basic units outstanding 1,903.5 As reported basic earnings per unit $ 1.51 Pro forma basic earnings per unit $ 1.47 Diluted earnings per unit: As reported diluted units outstanding 1,895.2 Pro forma diluted units outstanding 1,950.0 As reported diluted earnings per unit $ 1.47 Pro forma diluted earnings per unit $ 1.44 Automatic conversion of subordinated units Step 2 of the Oiltanking acquisition  the merger of a wholly owned subsidiary of ours with and into Oiltanking, with Oiltanking surviving the merger as our wholly owned subsidiary; 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 us and our subsidiaries) to be cancelled and converted into our common units based on an exchange ratio of 1.30 of our 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 $6.02 billion. Since we had a controlling financial interest in Oiltanking before and after completion of Step 2, the increase in our ownership interest in Oiltanking was accounted for as an equity transaction with no gain or loss recognized. Step 2 represented our acquisition of the noncontrolling interests in Oiltanking; therefore, approximately $1.4 billion of noncontrolling interests attributable to Oiltanking were reclassified to limited partners' equity to reflect the February 2015 issuance of 36,827,517 new common units. Upon completion of the merger, the IDRs of Oiltanking were cancelled since we now own 100% of the future cash flows attributable to the Oiltanking business we acquired. As a result, the $1.46 billion carrying value of the IDR intangible asset was reclassified to goodwill and allocated among our business segments (see Note 7). See Note 17 for information regarding a Federal Trade Commission ("FTC") inquiry related to the Oiltanking acquisition and our operations.

Equity-Based Awards

Equity-Based Awards	12 Months Ended
	Dec. 31, 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 Year Ended December 31, 2015 2014 2013 Equity-classified awards: Restricted common unit awards $ 14.7 $ 42.1 $ 71.5 Phantom unit awards 78.3 45.1 -- Unit option awards -- -- 0.8 Liability-classified awards 0.2 0.3 0.5 Total $ 93.2 $ 87.5 $ 72.8 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 December 31, 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"). The 1998 Plan provides for awards of our common units and other rights to our non-employee directors and to employees of EPCO and its affiliates providing services to us. Awards under the 1998 Plan may be granted in the form of unit options, restricted common units, phantom units and distribution equivalent rights ("DERs"). Up to 14,000,000 of our common units may be issued as awards under the 1998 Plan. After giving effect to awards granted under the 1998 Plan through December 31, 2015, a total of 3,073,703 additional common units were available for issuance. The 2008 Plan (as amended and restated) is a long-term incentive plan under which any employee or consultant of EPCO, us or our affiliates that provides services to us, directly or indirectly, may receive incentive compensation awards in the form of options, restricted common units, phantom units, DERs, unit appreciation rights ("UARs"), unit awards, other unit-based awards or substitute awards. Non-employee directors of our general partner may also participate in the 2008 Plan. The maximum number of common units available for issuance under the 2008 Plan was 30,000,000 at December 31, 2015. This amount automatically increased 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. The 2008 Plan is effective until September 30, 2023 or, if earlier, until the time that all available common units under the 2008 Plan have been delivered to participants or the time of termination of the 2008 Plan by the Board of Directors of EPCO or by the Audit and Conflicts Committee. After giving effect to awards granted under the 2008 Plan through December 31, 2015, a total of 16,669,007 additional common units were available for issuance. 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 December 31, 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. These awards were first issued in February 2014. The following table presents phantom unit award activity for the periods indicated: Number of Units Weighted- Average Grant Date Fair Value per Unit Phantom unit awards at December 31, 2013 -- $ -- Granted (2) 3,530,710 $ 33.12 Vested (38,200 ) $ 33.04 Forfeited (150,120 ) $ 33.12 Phantom unit awards at December 31, 2014 3,342,390 $ 33.13 Granted (3) 3,496,140 $ 33.96 Vested (940,415 ) $ 33.14 Forfeited (471,166 ) $ 33.51 Phantom unit awards at December 31, 2015 5,426,949 $ 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 2014 was $117.0 million based on a grant date market price of our common units ranging from $33.04 to $37.59 per unit. An estimated annual forfeiture rate of 3.4% was applied to these awards. (3) The aggregate grant date fair value of phantom unit awards issued during 2015 was $118.7 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. After taking into account tax withholding requirements, we issued 618,395 common units and 23,311 common units in connection with the vesting of phantom unit awards in the years ended December 31, 2015 and 2014, respectively. Our long-term incentive plans provide for the issuance of 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 Year Ended December 31, 2015 2014 2013 Cash payments made in connection with DERs $ 7.7 $ 3.7 $ -- Total intrinsic value of phantom unit awards that vested during period $ 31.2 $ 1.4 $ -- For the EPCO group of companies, the unrecognized compensation cost associated with phantom unit awards was $77.0 million at December 31, 2015, of which our share of the cost is currently estimated to be $69.2 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. 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 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 restricted common unit award activity for the periods indicated: Number of Units Weighted- Average Grant Date Fair Value per Unit Restricted common units at December 31, 2012 7,786,972 $ 20.43 Granted (2) 3,549,052 $ 28.61 Vested (3,770,696 ) $ 17.48 Forfeited (344,114 ) $ 23.82 Restricted common units at December 31, 2013 7,221,214 $ 25.83 Vested (2,634,074 ) $ 23.94 Forfeited (357,350 ) $ 26.38 Restricted common units at December 31, 2014 4,229,790 $ 26.96 Vested (2,009,970 ) $ 26.00 Forfeited (259,300 ) $ 27.53 Restricted common units at December 31, 2015 1,960,520 $ 27.88 (1) Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued. (2) The aggregate grant date fair value of restricted common unit awards issued during 2013 was $101.5 million based on a grant date market price of our common units ranging from $28.56 to $31.74 per unit. An estimated annual forfeiture rate of 3.9% was applied to these awards. 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 Statements of Consolidated Cash Flows. The following table presents supplemental information regarding our restricted common unit awards for the periods indicated: For the Year Ended December 31, 2015 2014 2013 Cash distributions paid to restricted common unitholders $ 4.0 $ 7.3 $ 10.6 Total intrinsic value of restricted common unit awards that vested during period $ 67.3 $ 87.1 $ 109.9 For the EPCO group of companies, the unrecognized compensation cost associated with restricted common unit awards was an aggregate $7.2 million at December 31, 2015, of which our share of the cost is currently estimated to be $5.7 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 1.0 year. Unit Option Awards EPCO's long-term incentive plans provide for the issuance of non-qualified incentive options denominated in our common units. All of our unit option awards had been exercised as of December 31, 2015 and no new unit option awards were granted during the three years ended December 31, 2015. When issued, the exercise price of each unit option award was equal to the market price of our common units on the date of grant. In general, unit option awards had a vesting period of four years from the date of grant and expired at the end of the calendar year following the year of vesting. The fair value of each unit option award was estimated on the date of grant using a Black-Scholes option pricing model, which incorporated various assumptions including expected life of the option, risk-free interest rates, expected distribution yield of our common units, and expected price volatility of our common units. Compensation expense recorded in connection with unit option awards was 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 unit option award activity for the periods indicated: Number of Units Weighted- Average Strike Price (dollars/unit) Unit option awards at December 31, 2012 5,522,280 $ 13.71 Exercised (1,472,280 ) $ 14.98 Unit option awards at December 31, 2013 4,050,000 $ 13.24 Exercised (2,720,000 ) $ 11.83 Forfeited (60,000 ) $ 16.14 Unit option awards at December 31, 2014 1,270,000 $ 16.14 Exercised (1,270,000 ) $ 16.14 Unit option awards at December 31, 2015 -- $ -- (1) All of the unit option awards outstanding at December 31, 2014 vested during 2014 and were exercised during 2015. In order to fund its unit option award-related obligations, EPCO purchased our common units at fair value 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 our unit option awards during the periods indicated: For the Year Ended December 31, 2015 2014 2013 Total intrinsic value of unit option awards exercised during period $ 21.7 $ 57.5 $ 19.8 Cash received from EPCO in connection with the exercise of unit option awards $ 13.1 $ 33.4 $ 11.5 Unit option award-related cash reimbursements to EPCO $ 21.7 $ 57.5 $ 19.8 As of December 31, 2015, all compensation expense related to unit option awards had been recognized.

Derivative Instruments, Hedging

Derivative Instruments, Hedging Activities and Fair Value Measurements	12 Months Ended
	Dec. 31, 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. The following table summarizes our portfolio of interest rate swaps at December 31, 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 0.82% Fair value hedge As a result of market conditions in 2014, we elected to terminate all of our interest rate swaps then outstanding. Since these interest rate swaps were accounted for as fair value hedges, the aggregate $27.6 million of gains was recorded as a component of long-term debt and is being amortized to earnings (as a decrease in interest expense) using the effective interest method over the remaining life of the associated debt obligations. Of the total gain, $17.6 million was amortized through January 2016 and $10.0 million will be amortized through October 2019. In connection with the issuance of senior notes during 2013, we settled 16 forward starting swaps having an aggregate notional amount of $1.0 billion, which resulted in cash losses totaling $168.8 million. As cash flow hedges, losses on these derivative instruments are a component of accumulated other comprehensive loss and are being amortized into earnings (as an increase in interest expense) over the remaining life of the associated debt obligations using the effective interest method. The $168.8 million loss will be amortized into earnings through March 2023. 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 December 31, 2015 (volume measures as noted): Volume Accounting Derivative Purpose Current Long-Term Treatment Derivatives designated as hedging instruments: Natural gas processing: Forecasted natural gas purchases for plant thermal reduction (Bcf) 9.1 n/a Cash flow hedge Forecasted sales of NGLs (MMBbls) 2.1 n/a Cash flow hedge Natural gas marketing: Forecasted purchases of natural gas for fuel (Bcf) 2.4 n/a Cash flow hedge Natural gas storage inventory management activities (Bcf) 10.7 n/a Fair value hedge NGL marketing: Forecasted purchases of NGLs and related hydrocarbon products (MMBbls) 28.7 0.4 Cash flow hedge Forecasted sales of NGLs and related hydrocarbon products (MMBbls) 42.2 0.1 Cash flow hedge Refined products marketing: Forecasted purchases of refined products (MMBbls) 2.7 n/a Cash flow hedge Forecasted sales of refined products (MMBbls) 0.8 0.1 Cash flow hedge Refined products inventory management activities (MMBbls) 1.3 n/a Fair value hedge Crude oil marketing: Forecasted purchases of crude oil (MMBbls) 15.0 n/a Cash flow hedge Forecasted sales of crude oil (MMBbls) 17.6 n/a Cash flow hedge Crude oil inventory management activities (MMBbls) 0.7 n/a Fair value hedge Derivatives not designated as hedging instruments: Natural gas risk management activities (Bcf) (3,4) 48.2 8.2 Mark-to-market NGL risk management activities (MMBbls) (4) 1.8 n/a Mark-to-market Crude oil risk management activities (MMBbls) (4) 11.8 n/a Mark-to-market (1) Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes. (2) The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is December 2017, January 2017 and March 2018, respectively. (3) Current and long-term volumes include 24.3 Bcf and 2.1 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. (4) Reflects the use of derivative instruments to manage risks associated with transportation, processing and storage assets. At December 31, 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. Certain basis swaps, basis spread options and other derivative instruments not designated as hedging instruments are used to manage market risks associated with anticipated purchases and sales of commodity products. There is some uncertainty involved in the timing of these transactions often due to the development of more favorable profit opportunities or when spreads are insufficient to cover variable costs thus reducing the likelihood that the transactions will occur during the periods originally forecasted. In accordance with derivatives accounting guidance, these instruments do not qualify for hedge accounting even though they are effective at managing the risk exposures of the underlying assets. Due to volatility in commodity prices, any non-cash, mark-to-market earnings variability cannot be predicted. 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 December 31, 2015 December 31, 2014 December 31, 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 $ 3.2 Current assets $ -- Other current liabilities $ -- Other current liabilities $ -- Interest rate derivatives Other assets -- Other assets -- Other liabilities 3.7 Other liabilities -- Total interest rate derivatives 3.2 -- 3.7 -- Commodity derivatives Current assets 253.8 Current assets 217.9 Other current liabilities 137.5 Other current liabilities 145.3 Commodity derivatives Other assets 0.2 Other assets -- Other liabilities 1.4 Other liabilities -- Total commodity derivatives 254.0 217.9 138.9 145.3 Total derivatives designated as hedging instruments $ 257.2 $ 217.9 $ 142.6 $ 145.3 Derivatives not designated as hedging instruments Interest rate derivatives Current assets $ -- Current assets $ -- Other current liabilities $ -- Other current liabilities $ -- Commodity derivatives Current assets 1.6 Current assets 8.1 Other current liabilities 3.1 Other current liabilities 0.7 Commodity derivatives Other assets -- Other assets 0.6 Other liabilities 1.0 Other liabilities 1.4 Total commodity derivatives 1.6 8.7 4.1 2.1 Total derivatives not designated as hedging instruments $ 1.6 $ 8.7 $ 4.1 $ 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 Not Offset in the Balance Sheet Gross Amounts of Recognized Assets Gross Amounts Offset in the Balance Sheet Amounts of Assets Presented in the Balance Sheet Financial Instruments Cash Collateral Paid Cash Collateral Received Amounts That Would Have Been Presented On Net Basis (i) (ii) (iii) = (i) – (ii) (iv) (v) = (iii) + (iv) As of December 31, 2015: Interest rate derivatives $ 3.2 $ -- $ 3.2 $ (3.2 ) $ -- $ -- $ -- Commodity derivatives 255.6 -- 255.6 (143.0 ) (40.1 ) (72.2 ) 0.3 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 Not Offset in the Balance Sheet Gross Amounts of Recognized Liabilities Gross Amounts Offset in the Balance Sheet Amounts of Liabilities Presented in the Balance Sheet Financial Instruments Cash Collateral Paid Amounts That Would Have Been Presented On Net Basis (i) (ii) (iii) = (i) – (ii) (iv) (v) = (iii) + (iv) As of December 31, 2015: Interest rate derivatives $ 3.7 $ -- $ 3.7 $ (3.2 ) $ -- $ 0.5 Commodity derivatives 143.0 -- 143.0 (143.0 ) -- -- As of December 31, 2014: Commodity derivatives $ 147.4 $ -- $ 147.4 $ (147.3 ) $ -- $ 0.1 Derivative assets and liabilities recorded on our Consolidated Balance Sheets are presented on a gross-basis and determined at the individual transaction level. This presentation method is applied regardless of whether the respective exchange clearing agreements, counterparty contracts or master netting agreements contain netting language often referred to as "rights of offset." Although derivative amounts are presented on a gross-basis, having rights of offset enable the settlement of a net as opposed to gross receivable or payable amount under a counterparty default or liquidation scenario. Cash is paid and received as collateral under certain agreements, particularly for those associated with exchange transactions. For any cash collateral payments or receipts, corresponding assets or liabilities are recorded to reflect the variation margin deposits or receipts with exchange clearing brokers and customers. These balances are also presented on a gross-basis on our Consolidated Balance Sheets. 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 Statements of Consolidated Operations for the periods indicated: Derivatives in Fair Value Hedging Relationships Location Gain (Loss) Recognized in Income on Derivative For the Year Ended December 31, 2015 2014 2013 Interest rate derivatives Interest expense $ (1.4 ) $ (26.5 ) $ (13.1 ) Commodity derivatives Revenue 19.1 11.9 (0.1 ) Total $ 17.7 $ (14.6 ) $ (13.2 ) Derivatives in Fair Value Hedging Relationships Location Gain (Loss) Recognized in Income on Hedged Item For the Year Ended December 31, 2015 2014 2013 Interest rate derivatives Interest expense $ 1.4 $ 26.4 $ 12.8 Commodity derivatives Revenue 0.2 (11.8 ) (5.7 ) Total $ 1.6 $ 14.6 $ 7.1 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 Statements of Consolidated Operations and 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 Year Ended December 31, 2015 2014 2013 Interest rate derivatives $ -- $ -- $ 6.6 Commodity derivatives – Revenue (1) 217.6 161.3 (47.9 ) Commodity derivatives – Operating costs and expenses (1) (2.7 ) -- 1.0 Total $ 214.9 $ 161.3 $ (40.3 ) (1) The fair value of these derivative instruments will be reclassified to their respective locations on the 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 Year Ended December 31, 2015 2014 2013 Interest rate derivatives Interest expense $ (35.3 ) $ (32.4 ) $ (29.2 ) Commodity derivatives Revenue 231.7 75.0 (22.4 ) Commodity derivatives Operating costs and expenses (3.5 ) 1.7 0.3 Total $ 192.9 $ 44.3 $ (51.3 ) Derivatives in Cash Flow Hedging Relationships Location Gain (Loss) Recognized in Income on Derivative (Ineffective Portion) For the Year Ended December 31, 2015 2014 2013 Commodity derivatives Revenue $ 4.7 $ (0.3 ) $ 0.2 Commodity derivatives Operating costs and expenses 0.1 -- -- Total $ 4.8 $ (0.3 ) $ 0.2 Over the next twelve months, we expect to reclassify $37.4 million of losses attributable to interest rate derivative instruments from accumulated other comprehensive loss to earnings as an increase in interest expense. Likewise, we expect to reclassify $57.6 million of net gains attributable to commodity derivative instruments from accumulated other comprehensive income to earnings, $57.3 million as an increase in revenue and $0.3 million as a decrease to operating costs and expenses. The following table presents the effect of our derivative instruments not designated as hedging instruments on our Statements of Consolidated Operations for the periods indicated: Derivatives Not Designated as Hedging Instruments Location Gain (Loss) Recognized in Income on Derivative For the Year Ended December 31, 2015 2014 2013 Interest rate derivatives Interest expense $ -- $ (0.1 ) $ (0.7 ) Commodity derivatives Revenue 1.0 (23.0 ) 7.3 Commodity derivatives Operating costs and expense 0.1 -- -- Total $ 1.1 $ (23.1 ) $ 6.6 Fair Value Measurements The following tables set forth, by level within the Level 1, 2 and 3 fair value hierarchy (see Note 2), 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. December 31, 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 $ -- $ 3.2 $ -- $ 3.2 Commodity derivatives 109.5 145.2 0.9 255.6 Total $ 109.5 $ 148.4 $ 0.9 $ 258.8 Financial liabilities: Liquidity Option Agreement $ -- $ -- $ 245.1 $ 245.1 Interest rate derivatives -- 3.7 -- 3.7 Commodity derivatives 31.3 109.2 2.5 143.0 Total $ 31.3 $ 112.9 $ 247.6 $ 391.8 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 Year Ended December 31, Location 2015 2014 Financial asset (liability) balance, net, January 1 $ (219.3 ) $ 3.2 Total gains (losses) included in: Net income (1) Revenue (0.9 ) 0.9 Net income Other expense, net (25.4 ) -- Other comprehensive income (loss) Commodity derivative instruments – changes in fair value of cash flow hedges (19.2 ) (2.6 ) Settlements 0.1 (3.4 ) Acquisition of Liquidity Option Agreement (see Note 17) -- (219.7 ) Transfers out of Level 3 (2) 18.0 2.3 Financial liability balance, net, December 31 $ (246.7 ) $ (219.3 ) (1) There were $0.9 million and $2.6 million of unrealized losses included in these amounts for the years ended December 31, 2015 and 2014, respectively. (2) Transfers out of Level 3 into Level 2 were due to shorter remaining transaction maturities falling inside of the Level 2 range at December 31, 2015 and 2014. The following Fair Value At December 31, 2015 Financial Assets Financial Liabilities Valuation Techniques Unobservable Input Range Commodity derivatives – Crude oil $ 0.9 $ 1.2 Discounted cash flow Forward commodity prices $35.63-$43.84/barrel Commodity derivatives – Propane -- 1.3 Discounted cash flow Forward commodity prices $0.42-$0.44/gallon Total $ 0.9 $ 2.5 Fair Value At December 31, 2014 Financial Assets Financial Liabilities Valuation Techniques Unobservable Input Range Commodity derivatives – Crude oil $ 1.0 $ 0.4 Discounted cash flow Forward commodity prices $49.26-$53.27/barrel Commodity derivatives – Natural gas -- 0.2 Discounted cash flow Forward commodity prices $3.05-$4.09/MMBtu Total $ 1.0 $ 0.6 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 December 31, 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. The recurring fair value measurement pertaining to the Liquidity Option Agreement is based on a number of Level 3 inputs. See Note 17 for a discussion of this liability. Nonrecurring Fair Value Measurements We measure certain assets, primarily long-lived assets and equity method investments, at fair value on a nonrecurring basis. These assets are recognized at fair value when they are deemed to be other-than-temporarily impaired. The following table summarizes our non-cash impairment charges by segment during each of the periods indicated: For the Year Ended December 31, 2015 2014 2013 NGL Pipelines & Services $ 20.8 $ 16.2 $ 30.6 Crude Oil Pipelines & Services 33.5 2.9 30.1 Natural Gas Pipelines & Services 21.6 0.7 -- Petrochemical & Refined Products Services 28.2 9.1 18.7 Offshore Pipelines & Services 58.5 5.1 18.0 Total $ 162.6 $ 34.0 $ 97.4 As presented in the following tables, our estimated fair values were based on management's expectation of the market values for such assets based on their knowledge and experience in the industry (a Level 3 type measure involving significant unobservable inputs). In many cases, there are no active markets (Level 1) or other similar recent transactions (Level 2) to compare to. Our assumptions used in such analyses are based on the highest and best use of the asset and includes estimated probabilities where multiple cash flow outcomes are possible. When probability weights are used, the weights are generally obtained from business management personnel having oversight responsibilities for the assets being tested. Key commercial assumptions (e.g., anticipated operating margins, throughput or processing volume growth rates, timing of cash flows, etc.) that represent Level 3 unobservable inputs and test results are reviewed and certified by members of senior management. Our non-cash asset impairment charges for the year ended December 31, 2015 are a component of operating costs and expenses and primarily reflect the $54.8 million charge we recorded in connection with the sale of our Offshore Business (see Note 5) and the abandonment of certain natural gas and crude oil pipeline assets in Texas. The following table presents categories of long-lived assets, primarily property, plant and equipment, that were subject to non-recurring fair value measurements during the year ended December 31, 2015: Fair Value Measurements at the End of the Reporting Period Using Carrying Value at December 31, 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 $ 81.4 Long-lived assets held for sale 18.0 -- -- 18.0 14.2 Long-lived assets disposed of by sale (1) -- -- -- -- 67.0 Total $ 162.6 (1) Includes a $54.8 million charge recorded in connection with the sale of our Offshore Business. Our non-cash asset impairment charges for the year ended December 31, 2014 are a component of operating costs and expenses and primarily relate to the abandonment of certain natural gas processing equipment in Louisiana, natural gas pipeline segments in the Gulf of Mexico, refined products terminal and pipeline assets in Arkansas, and NGL storage caverns in Oklahoma and Texas. The following table presents categories of long-lived assets, primarily property, plant and equipment, that were subject to non-recurring fair value measurements during the year ended December 31, 2014: Fair Value Measurements at the End of the Reporting Period Using Carrying Value at December 31, 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 $ -- $ -- $ -- $ -- $ 26.7 Long-lived assets held for sale 1.5 -- -- 1.5 3.6 Long-lived assets disposed of by sale -- -- -- -- 3.7 Total $ 34.0 Our non-cash asset impairment charges for the year ended December 31, 2013 primarily relate to the abandonment of certain crude oil and natural gas pipeline segments in Texas, Oklahoma and the Gulf of Mexico, certain refined products terminal assets in Texas, an NGL storage cavern in Arizona and an NGL fractionator and storage cavern facility in Ohio. These impairment charges totaled $92.6 million and are a component of operating costs and expenses. The remaining charge, or $4.8 million, relates to the impairment of an equity method investment and was presented as a component of equity in income of unconsolidated affiliates. The following table presents categories of long-lived assets that were subject to non-recurring fair value measurements during the year ended December 31, 2013: Fair Value Measurements at the End of the Reporting Period Using Carrying Value at December 31, 2013 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 $ -- $ -- $ -- $ -- $ 79.4 Long-lived assets held and used 44.6 -- -- 44.6 9.0 Long-lived assets held for sale 0.6 -- -- 0.6 3.4 Long-lived assets disposed of by sale -- -- -- -- 5.6 Total $ 97.4 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 $19.51 billion and $22.16 billion at December 31, 2015 and 2014, respectively. The aggregate carrying value of these debt obligations was $20.87 billion and $20.48 billion at December 31, 2015 and 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 December 31, 2015, exclude those amounts hedged using fixed-to-floating interest rate swaps. See " Interest Rate Hedging Activities

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Related Party Transactions	The following table summarizes our related party transactions for the periods indicated: For the Year Ended December 31, 2015 2014 2013 Revenues – related parties: Unconsolidated affiliates $ 72.3 $ 71.5 $ 65.9 Costs and expenses – related parties: EPCO and its privately held affiliates $ 949.3 $ 939.9 $ 892.2 Unconsolidated affiliates 245.3 183.0 160.0 Total $ 1,194.6 $ 1,122.9 $ 1,052.2 The following table summarizes our related party accounts receivable and accounts payable balances at the dates indicated: December 31, 2015 2014 Accounts receivable - related parties: Unconsolidated affiliates $ 1.2 $ 2.8 Accounts payable - related parties: EPCO and its privately held affiliates $ 75.6 $ 98.1 Unconsolidated affiliates 8.5 20.8 Total $ 84.1 $ 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 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 December 31, 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 677,159,667 33.6% 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 December 31, 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 years ended December 31, 2015, 2014 and 2013, we paid EPCO and its privately held affiliates cash distributions totaling $948.3 million, $877.0 million and $811.4 million, respectively. Distributions paid during the years ended December 31, 2015, 2014 and 2013 excluded 35,380,000, 45,120,000 and 47,400,000 Designated Units, respectively (see Note 9). From time-to-time, EPCO and its privately held affiliates elect to reinvest a portion of the cash distributions received from us into the purchase of additional common units under our DRIP. These purchases totaled $100 million for each of the years ended December 31, 2015 and 2014. 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. In January 2016, privately held affiliates of EPCO purchased 3,830,256 common units from us under our ATM program, generating gross proceeds of $100 million. In February 2016, privately held affiliates of EPCO reinvested an additional $100 million in us, resulting in the issuance of 4,481,504 of our common units under our DRIP. See Note 9 for additional information regarding our DRIP and ATM program. We lease office space from affiliates of EPCO. The rental rates in these lease agreements approximate market rates. EPCO ASA  EPCO will provide selling, general and administrative services and management and operating services as may be necessary to manage and operate our businesses, properties and assets (all in accordance with prudent industry practices). EPCO will employ or otherwise retain the services of such personnel.  We are required to reimburse EPCO for its services in an amount equal to the sum of all costs and expenses incurred by EPCO which are directly or indirectly related to our business or activities (including expenses reasonably allocated to us by EPCO). In addition, we have agreed to pay all sales, use, excise, value added or similar taxes, if any, that may be applicable from time to time with respect to the services provided to us by EPCO.  EPCO will allow us to participate as a named insured in its overall insurance program, with the associated premiums and other costs being allocated to us. See Note 18 for additional information regarding our insurance programs. Our operating costs and expenses include amounts paid to EPCO for the costs it incurs to operate our facilities, including the compensation of its employees. We reimburse EPCO for actual direct and indirect expenses it incurs related to the operation of our assets. Likewise, our general and administrative costs include amounts paid to EPCO for administrative services, including the compensation of its employees. In general, our reimbursement to EPCO for administrative services is either (i) on an actual basis for direct expenses it may incur on our behalf (e.g., the purchase of office supplies) or (ii) based on an allocation of such charges between the various parties to the ASA based on the estimated use of such services by each party (e.g., the allocation of legal or accounting salaries based on estimates of time spent on each entity's business and affairs). The following table presents our related party costs and expenses attributable to the ASA with EPCO for the periods indicated: For the Year Ended December 31, 2015 2014 2013 Operating costs and expenses $ 826.4 $ 801.6 $ 770.6 General and administrative expenses 105.2 121.7 105.2 Total costs and expenses $ 931.6 $ 923.3 $ 875.8 Since the vast majority of such expenses are charged to us on an actual basis (i.e., no mark-up or subsidy is charged or received by EPCO), we believe that such expenses are representative of what the amounts would have been on a standalone basis. With respect to allocated costs, we believe that the proportional direct allocation method employed by EPCO is reasonable and reflective of the estimated level of costs we would have incurred on a standalone basis. Relationships with Unconsolidated Affiliates Many of our unconsolidated affiliates perform supporting or complementary roles to our other business operations. The following information summarizes significant related party transactions with our current unconsolidated affiliates:  For the years ended December 31, 2015, 2014 and 2013, we paid Seaway $175.8 million, $130.8 million and $132.4 million, respectively, for pipeline transportation and storage services in connection with our crude oil marketing activities. Revenues from Seaway were $47.7 million, $29.4 million and $41.3 million for the years ended December 31, 2015, 2014 and 2013, respectively.  We pay Promix for the transportation, storage and fractionation of NGLs. In addition, we sell natural gas to Promix for its plant fuel requirements. Revenues from Promix were $8.8 million, $11.1 million and $9.8 million for the years ended December 31, 2015, 2014 and 2013, respectively. Expenses with Promix were $24.9 million, $25.8 million and $28.1 million for the years ended December 31, 2015, 2014 and 2013, respectively.  For the years ended December 31, 2015, 2014 and 2013, we paid Eagle Ford Crude Oil Pipeline $39.4 million, $25.8 million and $5.4 million, respectively, for crude oil transportation.  We perform management services for certain of our unconsolidated affiliates. We charged such affiliates $19.1 million, $24.5 million and $21.8 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Provision for Income Taxes

Provision for Income Taxes	12 Months Ended
	Dec. 31, 2015
Provision for Income Taxes [Abstract]
Provision for Income Taxes	Publicly traded partnerships like ours are treated as corporations unless they have 90% or more in qualifying income (as that term is defined in the Internal Revenue Code). We satisfied this requirement in each of the years ended December 31, 2015, 2014 and 2013 and, as a result, are not subject to federal income tax. However, our partners are individually responsible for paying federal income taxes on their share of our taxable income. Net earnings for financial reporting purposes may differ significantly from taxable income reportable to our unitholders as a result of differences between the tax basis and financial reporting basis of certain assets and liabilities and other factors. We do not have access to information regarding each partner's individual tax basis in our limited partner interests. Provision for income taxes primarily reflects our state tax obligations under the Revised Texas Franchise Tax (the "Texas Margin Tax"). Deferred income tax assets and liabilities are recognized for temporary differences between the assets and liabilities of our tax paying entities for financial reporting and tax purposes. Our federal, state and foreign income tax provision (benefit) is summarized below: For the Year Ended December 31, 2015 2014 2013 Current: Federal $ 0.9 $ 2.2 $ (0.5 ) State 15.5 13.4 19.3 Foreign 1.7 1.4 0.8 Total current 18.1 17.0 19.6 Deferred: Federal (1.4 ) 2.2 (0.5 ) State (19.2 ) 3.5 38.9 Foreign -- 0.4 (0.5 ) Total deferred (20.6 ) 6.1 37.9 Total provision for (benefit from) income taxes $ (2.5 ) $ 23.1 $ 57.5 A reconciliation of the provision for (benefit from) income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows: For the Year Ended December 31, 2015 2014 2013 Pre-Tax Net Book Income ("NBI") $ 2,555.9 $ 2,856.6 $ 2,664.6 Texas Margin Tax (1) $ (3.7 ) $ 17.5 $ 58.3 State income taxes (net of federal benefit) 0.7 0.2 (0.1 ) Federal income taxes computed by applying the federal statutory rate to NBI of corporate entities 1.1 1.5 (1.4 ) Expiration of tax net operating loss -- -- 0.1 Other permanent differences (0.6 ) 3.9 0.6 Provision for (benefit from) income taxes $ (2.5 ) $ 23.1 $ 57.5 Effective income tax rate (0.1)% 0.8% 2.2% (1) Although the Texas Margin Tax is not considered a state income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers our Texas-sourced revenues and expenses. During 2015, certain legislative changes were enacted to the Texas Margin Tax, which reduced the tax rate for business entities that operate within the state. The following table presents the significant components of deferred tax assets and deferred tax liabilities at the dates indicated: December 31, 2015 2014 Deferred tax assets: Net operating loss carryovers (1) $ 0.2 $ 0.3 Accruals 1.6 1.8 Total deferred tax assets 1.8 2.1 Less: Deferred tax liabilities: Property, plant and equipment 44.9 64.4 Equity investment in partnerships 2.7 4.1 Total deferred tax liabilities 47.6 68.5 Total net deferred tax liabilities $ 45.8 $ 66.4 Current portion of total net deferred tax assets $ 0.3 $ 0.2 Long-term portion of total net deferred tax liabilities $ 46.1 $ 66.6 (1) These losses expire in various years between 2016 and 2033 and are subject to limitations on their utilization. Accounting guidance provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. We did not rely on any uncertain tax positions in recording our income tax-related amounts during the years ended December 31, 2015, 2014 or 2013.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 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 December 31, 2015 and 2014, our accruals for litigation contingencies were $4.6 million and $2.4 million, respectively, and were recorded in our 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%, 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 December 31, 2015, we have not recorded a provision for this matter as management believes payment of damages in this case is not probable. FTC Inquiry regarding Oiltanking Acquisition On February 23, 2015, we received a Civil Investigative Demand and a related Subpoena Duces Tecum Redelivery Commitments We store natural gas, crude oil, NGLs and certain petrochemical products owned by third parties under various agreements. Under the terms of these agreements, we are generally required to redeliver volumes to the owner on demand. At December 31, 2015, we had approximately 10.2 trillion British thermal units ("TBtus") of natural gas, 18.7 MMBbls of crude oil, and 37.5 MMBbls of NGL and petrochemical products in our custody that were owned by third parties. We maintain insurance coverage related to such volumes that we believe is consistent with our exposure. See Note 18 for information regarding insurance matters. Commitments Under Equity Compensation Plans of EPCO In accordance with our agreements with EPCO, we reimburse EPCO for our share of its compensation expense associated with certain employees who perform management, administrative and operating functions for us. See Notes 13 and 15 for additional information regarding our accounting for equity-based awards and related party information, respectively. Contractual Obligations The following table summarizes our various contractual obligations at December 31, 2015. A description of each type of contractual obligation follows: Payment or Settlement due by Period Contractual Obligations Total 2016 2017 2018 2019 2020 Thereafter Scheduled maturities of debt obligations $ 22,738.5 $ 1,864.1 $ 800.0 $ 1,100.0 $ 1,500.0 $ 1,500.0 $ 15,974.4 Estimated cash interest payments $ 21,734.1 $ 1,053.0 $ 1,036.1 $ 975.6 $ 917.5 $ 859.7 $ 16,892.2 Operating lease obligations $ 494.0 $ 64.2 $ 58.4 $ 50.3 $ 44.7 $ 41.0 $ 235.4 Purchase obligations: Product purchase commitments: Estimated payment obligations: Natural gas $ 1,160.8 $ 451.3 $ 215.6 $ 215.6 $ 143.8 $ 73.5 $ 61.0 NGLs $ 376.9 $ 319.3 $ 21.8 $ 23.9 $ 11.9 $ -- $ -- Crude oil $ 441.5 $ 389.4 $ 17.9 $ 17.9 $ 16.3 $ -- $ -- Petrochemicals & refined products $ 1,921.4 $ 1,868.6 $ 52.8 $ -- $ -- $ -- $ -- Other $ 33.2 $ 8.7 $ 6.9 $ 4.1 $ 4.1 $ 2.7 $ 6.7 Underlying major volume commitments: Natural gas (in TBtus) 647 243 128 128 81 37 30 NGLs (in MMBbls) 39 30 3 4 2 -- -- Crude oil (in MMBbls) 14 11 1 1 1 -- -- Petrochemicals & refined products (in MMBbls) 146 126 20 -- -- -- -- Service payment commitments $ 685.9 $ 184.5 $ 160.1 $ 91.8 $ 71.1 $ 43.7 $ 134.7 Capital expenditure commitments $ 113.9 $ 113.9 $ -- $ -- $ -- $ -- $ -- Scheduled Maturities of Debt . Estimated Cash Interest Payments . Operating Lease Obligations Our significant lease agreements consist of (i) land held pursuant to right-of-way agreements and property leases, (ii) the lease of underground storage caverns for natural gas and NGLs, (iii) the lease of transportation equipment used in our operations, and (iv) leased office space with affiliates of EPCO. Currently, our significant lease agreements have terms that range from 5 to 30 years. The Lease expense is charged to operating costs and expenses on a straight-line basis over the period of expected economic benefit. Contingent rental payments are expensed as incurred. We are generally required to perform routine maintenance on the underlying leased assets. In addition, certain leases give us the option to make leasehold improvements. Maintenance and repairs of leased assets resulting from our operations are charged to expense as incurred. Consolidated costs and expenses include lease and rental expense amounts of $104.3 million, $94.2 million and $87.6 million during the years ended December 31, 2015, 2014 and 2013, respectively. Purchase Obligations .  We have long and short-term product purchase obligations for natural gas, NGLs, crude oil, petrochemicals and refined products with third party suppliers. The prices that we are obligated to pay under these contracts approximate market prices at the time we take delivery of the volumes. The preceding table shows our volume commitments and estimated payment obligations under these contracts for the periods presented. Our estimated future payment obligations are based on the contractual price in each agreement at December 31, 2015 applied to all future volume commitments. Actual future payment obligations may vary depending on prices at the time of delivery. At December 31, 2015, we did not have any significant product purchase commitments with fixed or minimum pricing provisions with remaining terms in excess of one year.  We have long and short-term commitments to pay service providers. Our contractual service payment commitments primarily represent our obligations under firm pipeline transportation contracts. Payment obligations vary by contract, but generally represent a price per unit of volume multiplied by a firm transportation volume commitment.  We have short-term payment obligations relating to our capital spending program, including our share of the capital spending of our unconsolidated affiliates. These commitments represent unconditional payment obligations for services to be rendered or products to be delivered in connection with capital projects. Other Commitments In connection with the agreements to acquire EFS Midstream (see Note 12), 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. Other Long-Term Liabilities The following table summarizes the components of "Other long-term liabilities" as presented on Consolidated Balance Sheets at the dates indicated: December 31, 2015 2014 Noncurrent portion of AROs (see Note 5) $ 52.9 $ 83.2 Deferred revenues – non-current portion (see Note 3) 78.3 73.0 Liquidity Option Agreement (see Note 12) 245.1 219.7 Centennial guarantees 6.1 7.0 Other 29.1 28.2 Total $ 411.5 $ 411.1 Liquidity Option Agreement In connection with Step 1 of the Oiltanking acquisition (see Note 12), we entered into the Liquidity Option Agreement ("Liquidity Option") with OTA and M&B, whereby 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 have not been sold by M&B prior to the option exercise date pursuant to the related Registration Rights Agreement (see Note 9) or otherwise. If M&B exercises the Liquidity Option, any assets or liabilities held by OTA at the time of exercise (e.g., any deferred tax liability), including any Enterprise common units held by OTA, will be indirectly acquired by us upon receipt of OTA's capital stock. The aggregate consideration to be paid by us for OTA's capital stock would equal 100% of the then-current fair market value of the Enterprise common units owned by OTA at the exercise date. The consideration paid may be in the form of newly issued Enterprise common units, cash or any mix thereof, as determined solely by us. We have the ability to issue the requisite number of common units needed to satisfy any potential obligation under the Liquidity Option. If a Trigger Event occurs (as defined in the underlying agreements), the Liquidity Option may be exercised earlier within a 135-day period following notice of such event. Trigger Events include, among other scenarios, any "Enterprise Tax Event," which includes certain events in which OTA would recognize taxable gain on the Enterprise units that it owns. If the Liquidity Option is exercised, we would indirectly acquire any Enterprise common units owned by OTA and assume all future income tax obligations of OTA associated with (i) owning common units encumbered by the entity-level taxes of a U.S. corporation and (ii) OTA's tax liabilities resulting from differences in the book and tax basis of such common units. We assigned a fair value of $219.7 million to the Liquidity Option at October 1, 2014 using an income approach, specifically a discounted cash flow analysis. The fair value of the Liquidity Option, at any measurement date, represents the present value of estimated federal and state income tax payments that we believe a market participant would incur on the taxable income of OTA. 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 we believe could be employed. Our valuation estimate for the Liquidity Option is based on significant inputs that are not observable in the market (i.e., Level 3 inputs). For example, the fair value of the Liquidity Option at December 31, 2015 was estimated at $245.1 million and was based on the following Level 3 inputs: § OTA remains in existence (i.e., is not dissolved and its assets sold) between one and 30 years following exercise of the Liquidity Option, depending on the liquidity preference of its owner. An equal probability was assigned to each year in the 30-year forecast period; § Forecast annual growth rates of Enterprise's taxable earnings before interest, taxes, depreciation and amortization ranging from 2% to 15%; § OTA's ownership interest in Enterprise common units is assumed to be diluted over time in connection with Enterprise's issuance of equity for general company reasons. For purposes of the valuation at December 31, 2015, we used ownership interests ranging from 1.9% to 2.7%; § OTA assumes approximately $2.2 billion of existing long-term debt (30-year maturity) immediately after the Liquidity Option is exercised. For purposes of the valuation at December 31, 2015, we used a market rate commensurate with level of debt and tenure of approximately 6.4%; § A forecasted yield on Enterprise common units of 5.8% to 6.6%; § OTA pays an aggregate federal and state income tax rate of 38% on its taxable income; and § A discount rate of 7.5% based on our weighted-average cost of capital at December 31, 2015. Furthermore, our valuation estimate incorporates probability-weighted scenarios reflecting the likelihood that M&B may elect to divest a portion of the Enterprise common units held by OTA prior to exercise of the option. Based on these scenarios, we expect that OTA would own approximately 78.9% of the 54,807,352 Enterprise common units it received on October 1, 2014 when the option period begins in February 2020. Changes in the fair value of the Liquidity Option are recognized in earnings as a component of other income (expense) on our Statements of Consolidated Operations. Results for the year ended December 31, 2015 include $25.4 million of aggregate non-cash expense attributable to accretion and changes in management estimates regarding inputs to the valuation model. The carrying value of the Liquidity Option Agreement, which is a component of "Other long-term liabilities" on our Consolidated Balance Sheet, increased to $245.1 million at December 31, 2015 as of a result of these changes. The estimated liability for the Liquidity Option at October 1, 2014 reflects a $100.3 million retrospective adjustment made in the third quarter of 2015 upon finalization of the purchase price allocation for the Oiltanking acquisition. The retrospective adjustment was applied in our December 31, 2014 Consolidated Balance Sheet as an 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. If M&B exercises the Liquidity Option, any assets or liabilities held by OTA at the time of exercise (e.g., any deferred tax liability), including any Enterprise common units held by OTA, will be indirectly acquired by us upon receipt of OTA's capital stock. To the extent that OTA's deferred tax liability exceeds the then current book value of the Liquidity Option liability, we will recognize expense for the difference. Centennial Guarantees At December 31, 2015, Centennial's debt obligations consisted of $67.2 million borrowed under a master shelf loan agreement. Borrowings under the master shelf agreement mature in May 2024 and are collateralized by substantially all of Centennial's assets and severally guaranteed 50% by us and 50% by our joint venture partner in Centennial. If Centennial were to default on its debt obligations, we and our joint venture partner would each be required to make an approximate $33.6 million payment to Centennial's lenders in connection with the guarantee agreements (based on Centennial's debt principal outstanding at December 31, 2015). We recognized a liability of $4.9 million for our share of the Centennial debt guaranty at December 31, 2015. In lieu of Centennial procuring insurance to satisfy third party claims arising from a catastrophic event, we and Centennial's other joint venture partner have entered a limited cash call agreement. We are obligated to contribute up to a maximum of $50.0 million in the event of a catastrophic event. At December 31, 2015, we have a recorded liability of $2.1 million representing the estimated fair value of our cash call guaranty. Our cash contributions to Centennial under the agreement may be covered by our other insurance policies depending on the nature of the catastrophic event.

Significant Risks and Uncertain

Significant Risks and Uncertainties	12 Months Ended
	Dec. 31, 2015
Significant Risks and Uncertainties [Abstract]
Significant Risks and Uncertainties	Nature of Operations We operate predominantly in the midstream energy industry, which includes gathering, transporting, processing, fractionating and storing natural gas, NGLs, crude oil, petrochemical and refined products. As such, changes in the prices of hydrocarbon products and in the relative price levels among hydrocarbon products could have a material adverse effect on our financial position, results of operations and cash flows. Changes in prices may impact demand for hydrocarbon products, which in turn may impact production, demand and the volumes of products for which we provide services. In addition, decreases in demand may be caused by other factors, including prevailing economic conditions, reduced demand by consumers for the end products made with hydrocarbon products, increased competition, adverse weather conditions and government regulations affecting prices and production levels. The crude oil, natural gas and NGLs currently transported, gathered or processed at our facilities originate primarily from existing domestic resource basins, which naturally deplete over time. To offset this natural decline, our facilities need access to production from newly discovered properties. Many economic and business factors beyond our control can adversely affect the decision by producers to explore for and develop new reserves. These factors could include relatively low crude oil and natural gas prices, cost and availability of equipment and labor, regulatory changes, capital budget limitations, the lack of available capital or the probability of success in finding hydrocarbons. A decrease in exploration and development activities in the regions where our facilities and other energy logistics assets are located could result in a decrease in volumes handled by our assets, which could have a material adverse effect on our financial position, results of operations and cash flows. Even if crude oil and natural gas reserves exist in the areas served by our assets, we may not be chosen by producers in these areas to gather, transport, process, fractionate, store or otherwise handle the hydrocarbons extracted. We compete with other companies, including producers of crude oil and natural gas, for any such production on the basis of many factors, including but not limited to geographic proximity to the production, costs of connection, available capacity, rates and access to markets. Credit Risk We may incur credit risk to the extent counterparties do not fulfill their obligations to us in connection with our marketing of natural gas, NGLs, petrochemicals, refined products and crude oil and long-term contracts with minimum volume commitments or fixed demand charges. Risks of nonpayment and nonperformance by customers are a major consideration in our businesses, and our credit procedures and policies may not be adequate to sufficiently eliminate customer credit risk. Further, adverse economic conditions in our industry, such as those experienced throughout 2015 and that we continue to experience at the beginning of 2016, increase the risk of nonpayment and nonperformance by customers, particularly customers that have sub-investment grade credit ratings or small-scale companies. We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions may utilize letters of credit, prepayments, net out agreements and guarantees. However, these procedures and policies do not fully eliminate customer credit risk. Our primary market areas are located in the Gulf Coast, Southwest, Rocky Mountain, Northeast and Midwest regions of the U.S. We have a concentration of trade receivable balances due from major integrated oil companies, independent oil companies and other pipelines and wholesalers. These concentrations of market areas may affect our overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors. In those situations where we are exposed to credit risk in our derivative instrument transactions, we analyze the counterparty's financial condition prior to entering into an agreement, establish credit and/or margin limits and monitor the appropriateness of these limits on an ongoing basis. Generally, we do not require collateral for such transactions nor do we currently anticipate nonperformance by our material counterparties. Insurance Matters We participate as a named insured in EPCO's insurance program, which provides us with property damage, business interruption and other insurance coverage, the scope and amounts of which we believe are customary and prudent for the nature and extent of our operations. While we believe EPCO maintains adequate insurance coverage on our behalf, insurance may not fully cover every type of damage, interruption or other loss that might occur. If we were to incur a significant loss for which we were not fully insured, it could have a material impact on our financial position, results of operations and cash flows. In addition, there may be timing differences between amounts we accrue related to property damage expense, amounts we are required to pay in connection with a loss, and amounts we subsequently receive from insurance carriers as reimbursements. Any event that materially interrupts the revenues generated by our consolidated operations, or other losses that require us to make material expenditures not reimbursed by insurance, could reduce our ability to pay distributions to our unitholders and, accordingly, adversely affect the market price of our common units. Involuntary conversions result from the loss of an asset due to some unforeseen event (e.g., destruction due to a fire). Some of these events are covered by insurance, thus resulting in a property damage insurance recovery. Amounts we receive from insurance carriers are net of any deductibles related to the covered event. We record a receivable from insurance to the extent we recognize a loss from an involuntary conversion event and the likelihood of our recovering such loss is deemed probable. To the extent that any of our insurance claim receivables are later judged not probable of recovery (e.g., due to new information), such amounts are expensed. We recognize gains on involuntary conversions when the amount received from insurance exceeds the net book value of the retired assets. In addition, we do not recognize gains related to insurance recoveries until all contingencies related to such proceeds have been resolved, that is, a non-refundable cash payment is received from the insurance carrier or we have a binding settlement agreement with the carrier that clearly states that a non-refundable payment will be made. To the extent that an asset is rebuilt, the associated expenditures are capitalized, as appropriate, on our Consolidated Balance Sheets and presented as "Capital expenditures" on our Statements of Consolidated Cash Flows. Under our current insurance program, the standalone deductible for property damage claims is $55 million. We also have business interruption protection; however, such claims must involve physical damage and have a combined loss value in excess of $55 million and the period of interruption must exceed 60 days. We received $95.0 million and $15.0 million of nonrefundable insurance proceeds during the years ended December 31, 2014 and 2013, respectively, attributable to property damage claims we filed in connection with a February 2011 NGL release and fire at the West Storage location of our Mont Belvieu, Texas underground storage facility. Operating income for the years ended December 31, 2014 and 2013 includes $95.0 million and $15.0 million of gains, respectively, related to these insurance recoveries. The amounts we received during the first quarter of 2014 represent the final payments on this property damage claim.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	The following table provides information regarding the net effect of changes in our operating accounts and cash payments for interest and income taxes for the periods indicated: For the Year Ended December 31, 2015 2014 2013 Decrease (increase) in: Accounts receivable – trade $ 1,279.3 $ 1,685.4 $ (1,136.2 ) Accounts receivable – related parties 1.3 3.8 (3.6 ) Inventories (72.7 ) (105.6 ) 38.6 Prepaid and other current assets (59.1 ) (74.6 ) (6.3 ) Other assets (5.8 ) 18.7 2.4 Increase (decrease) in: Accounts payable – trade (52.9 ) (141.0 ) (10.1 ) Accounts payable – related parties (34.8 ) (31.6 ) 23.6 Accrued product payables (1,342.4 ) (1,647.8 ) 1,043.8 Accrued interest 16.5 31.3 3.5 Other current liabilities (67.1 ) 141.3 (35.1 ) Other liabilities 14.4 11.9 (18.2 ) Net effect of changes in operating accounts $ (323.3 ) $ (108.2 ) $ (97.6 ) Cash payments for interest, net of $149.1, $77.9 and $133.0 capitalized in 2015, 2014 and 2013, respectively $ 911.6 $ 832.1 $ 781.5 Cash payments for federal and state income taxes $ 17.5 $ 16.1 $ 35.0 We incurred liabilities for construction in progress that had not been paid at December 31, 2015, 2014 and 2013 of $472.8 million, $372.8 million and $205.3 million, respectively. Such amounts are not included under the caption "Capital expenditures" on the 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 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 12). The following table presents our cash proceeds from asset sales and insurance recoveries for the periods indicated: For the Year Ended December 31, 2015 2014 2013 Sale of Offshore Business (see Note 5) $ 1,527.7 $ -- $ -- Insurance recoveries attributable to West Storage claims (see Note 18) -- 95.0 15.0 Cash proceeds from other asset sales 80.9 50.3 265.6 Total $ 1,608.6 $ 145.3 $ 280.6 The following table presents net gains (losses) attributable to asset sales and insurance recoveries for the periods indicated: For the Year Ended December 31, 2015 2014 2013 Sale of Offshore Business $ (12.3 ) $ -- $ -- Gains attributable to West Storage insurance recoveries (see Note 18) -- 95.0 15.0 Net gains (losses) attributable to other asset sales (3.3 ) 7.1 68.3 Total $ (15.6 ) $ 102.1 $ 83.3 See Note 12 for information regarding non-cash consideration we issued in connection with the Oiltanking acquisition.

Quarterly Financial Information

Quarterly Financial Information (Unaudited)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information (Unaudited) [Abstract]
Quarterly Financial Information (Unaudited)	The following table presents selected quarterly financial data for the periods indicated: First Quarter Second Quarter Third Quarter Fourth Quarter For the Year Ended December 31, 2015: Revenues $ 7,472.5 $ 7,092.5 $ 6,307.9 $ 6,155.0 Operating income 896.0 800.3 909.4 934.5 Net income 650.6 556.6 657.7 693.5 Net income attributable to limited partners 636.1 551.0 649.3 684.8 Earnings per unit: Basic $ 0.33 $ 0.28 $ 0.33 $ 0.34 Diluted $ 0.32 $ 0.28 $ 0.32 $ 0.34 For the Year Ended December 31, 2014: Revenues $ 12,909.9 $ 12,520.8 $ 12,330.2 $ 10,190.3 Operating income 1,032.7 884.3 937.7 921.0 Net income 806.7 646.5 699.2 681.1 Net income attributable to limited partners 798.8 637.7 691.1 659.8 Earnings per unit: Basic $ 0.44 $ 0.35 $ 0.38 $ 0.35 Diluted $ 0.43 $ 0.34 $ 0.37 $ 0.34 The sum of our quarterly earnings per unit amounts may not equal our full year amounts due to slight rounding differences.

Condensed Consolidating Financi

Condensed Consolidating Financial Information	12 Months Ended
	Dec. 31, 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 8 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. Condensed Consolidating Balance Sheet December 31, 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 $ 14.4 $ 71.1 $ (50.6 ) $ 34.9 $ -- $ -- $ 34.9 Accounts receivable – trade, net 811.3 1,755.8 2.8 2,569.9 -- -- 2,569.9 Accounts receivable – related parties 59.0 795.4 (853.0 ) 1.4 -- (0.2 ) 1.2 Inventories 786.9 251.4 (0.2 ) 1,038.1 -- -- 1,038.1 Derivative assets 150.4 108.2 -- 258.6 -- -- 258.6 Prepaid and other current assets 168.3 249.1 (7.1 ) 410.3 -- -- 410.3 Total current assets 1,990.3 3,231.0 (908.1 ) 4,313.2 -- (0.2 ) 4,313.0 Property, plant and equipment, net 3,859.8 28,173.5 1.4 32,034.7 -- -- 32,034.7 Investments in unconsolidated affiliates 38,655.0 4,067.3 (40,093.8 ) 2,628.5 20,540.2 (20,540.2 ) 2,628.5 Intangible assets, net 721.2 3,330.7 (14.7 ) 4,037.2 -- -- 4,037.2 Goodwill 459.5 5,285.7 -- 5,745.2 -- -- 5,745.2 Other assets 280.2 47.9 (135.2 ) 192.9 0.5 -- 193.4 Total assets $ 45,966.0 $ 44,136.1 $ (41,150.4 ) $ 48,951.7 $ 20,540.7 $ (20,540.4 ) $ 48,952.0 LIABILITIES AND EQUITY Current liabilities: Current maturities of debt $ 1,863.8 $ 0.1 $ -- $ 1,863.9 $ -- $ -- $ 1,863.9 Accounts payable – trade 375.3 535.1 (50.6 ) 859.8 0.3 -- 860.1 Accounts payable – related parties 885.3 62.3 (863.5 ) 84.1 0.2 (0.2 ) 84.1 Accrued product payables 997.7 1,489.3 (2.6 ) 2,484.4 -- -- 2,484.4 Accrued liability related to EFS Midstream acquisition -- 993.2 -- 993.2 -- -- 993.2 Accrued interest 352.0 0.1 -- 352.1 -- -- 352.1 Other current liabilities 178.7 357.1 (7.0 ) 528.8 -- -- 528.8 Total current liabilities 4,652.8 3,437.2 (923.7 ) 7,166.3 0.5 (0.2 ) 7,166.6 Long-term debt 20,811.4 15.3 -- 20,826.7 -- -- 20,826.7 Deferred tax liabilities 3.4 40.8 (0.8 ) 43.4 -- 2.7 46.1 Other long-term liabilities 14.5 286.9 (135.0 ) 166.4 245.1 -- 411.5 Commitments and contingencies Equity: Partners' and other owners' equity 20,483.9 40,297.2 (40,266.8 ) 20,514.3 20,295.1 (20,514.3 ) 20,295.1 Noncontrolling interests -- 58.7 175.9 234.6 -- (28.6 ) 206.0 Total equity 20,483.9 40,355.9 (40,090.9 ) 20,748.9 20,295.1 (20,542.9 ) 20,501.1 Total liabilities and equity $ 45,966.0 $ 44,136.1 $ (41,150.4 ) $ 48,951.7 $ 20,540.7 $ (20,540.4 ) $ 48,952.0 Enterprise Products Partners L.P. 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. Condensed Consolidating Statement of Operations For the Year Ended December 31, 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 $ 20,104.8 $ 19,087.0 $ (12,163.9 ) $ 27,027.9 $ -- $ -- $ 27,027.9 Costs and expenses: Operating costs and expenses 19,283.7 16,549.3 (12,164.3 ) 23,668.7 -- -- 23,668.7 General and administrative costs 38.2 152.3 -- 190.5 2.1 -- 192.6 Total costs and expenses 19,321.9 16,701.6 (12,164.3 ) 23,859.2 2.1 -- 23,861.3 Equity in income of unconsolidated affiliates 2,718.4 417.5 (2,762.3 ) 373.6 2,548.7 (2,548.7 ) 373.6 Operating income 3,501.3 2,802.9 (2,761.9 ) 3,542.3 2,546.6 (2,548.7 ) 3,540.2 Other income (expense): Interest expense (952.9 ) (12.0 ) 3.1 (961.8 ) -- -- (961.8 ) Other, net 5.2 0.8 (3.1 ) 2.9 (25.4 ) -- (22.5 ) Total other expense, net (947.7 ) (11.2 ) -- (958.9 ) (25.4 ) -- (984.3 ) Income before income taxes 2,553.6 2,791.7 (2,761.9 ) 2,583.4 2,521.2 (2,548.7 ) 2,555.9 Benefit from (provision for) income taxes (8.7 ) 12.7 -- 4.0 -- (1.5 ) 2.5 Net income 2,544.9 2,804.4 (2,761.9 ) 2,587.4 2,521.2 (2,550.2 ) 2,558.4 Net loss (income) attributable to noncontrolling interests -- 0.9 (42.9 ) (42.0 ) -- 4.8 (37.2 ) Net income attributable to entity $ 2,544.9 $ 2,805.3 $ (2,804.8 ) $ 2,545.4 $ 2,521.2 $ (2,545.4 ) $ 2,521.2 Enterprise Products Partners L.P. Condensed Consolidating Statement of Operations For the Year Ended 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 Revenues $ 32,468.5 $ 32,488.2 $ (17,005.5 ) $ 47,951.2 $ -- $ -- $ 47,951.2 Costs and expenses: Operating costs and expenses 31,579.2 29,647.6 (17,006.3 ) 44,220.5 -- -- 44,220.5 General and administrative costs 39.1 173.2 -- 212.3 2.2 -- 214.5 Total costs and expenses 31,618.3 29,820.8 (17,006.3 ) 44,432.8 2.2 -- 44,435.0 Equity in income of unconsolidated affiliates 2,865.2 354.3 (2,960.0 ) 259.5 2,789.6 (2,789.6 ) 259.5 Operating income 3,715.4 3,021.7 (2,959.2 ) 3,777.9 2,787.4 (2,789.6 ) 3,775.7 Other income (expense): Interest expense (921.3 ) (2.5 ) 2.8 (921.0 ) -- -- (921.0 ) Other, net 3.4 1.3 (2.8 ) 1.9 -- -- 1.9 Total other expense, net (917.9 ) (1.2 ) -- (919.1 ) -- -- (919.1 ) Income before income taxes 2,797.5 3,020.5 (2,959.2 ) 2,858.8 2,787.4 (2,789.6 ) 2,856.6 Provision for income taxes (11.5 ) (9.8 ) 0.2 (21.1 ) -- (2.0 ) (23.1 ) Net income 2,786.0 3,010.7 (2,959.0 ) 2,837.7 2,787.4 (2,791.6 ) 2,833.5 Net loss (income) attributable to noncontrolling interests -- 0.4 (51.5 ) (51.1 ) -- 5.0 (46.1 ) Net income attributable to entity $ 2,786.0 $ 3,011.1 $ (3,010.5 ) $ 2,786.6 $ 2,787.4 $ (2,786.6 ) $ 2,787.4 Enterprise Products Partners L.P. Condensed Consolidating Statement of Operations For the Year Ended December 31, 2013 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 $ 30,007.4 $ 31,641.3 $ (13,921.7 ) $ 47,727.0 $ -- $ -- $ 47,727.0 Costs and expenses: Operating costs and expenses 29,176.7 28,983.7 (13,921.7 ) 44,238.7 -- -- 44,238.7 General and administrative costs 29.1 157.0 -- 186.1 2.2 -- 188.3 Total costs and expenses 29,205.8 29,140.7 (13,921.7 ) 44,424.8 2.2 -- 44,427.0 Equity in income of unconsolidated affiliates 2,609.0 204.8 (2,646.5 ) 167.3 2,599.1 (2,599.1 ) 167.3 Operating income 3,410.6 2,705.4 (2,646.5 ) 3,469.5 2,596.9 (2,599.1 ) 3,467.3 Other income (expense): Interest expense (800.8 ) (1.7 ) -- (802.5 ) -- -- (802.5 ) Other, net 0.3 (0.5 ) -- (0.2 ) -- -- (0.2 ) Total other expense, net (800.5 ) (2.2 ) -- (802.7 ) -- -- (802.7 ) Income before income taxes 2,610.1 2,703.2 (2,646.5 ) 2,666.8 2,596.9 (2,599.1 ) 2,664.6 Provision for income taxes (13.9 ) (42.6 ) -- (56.5 ) -- (1.0 ) (57.5 ) Net income 2,596.2 2,660.6 (2,646.5 ) 2,610.3 2,596.9 (2,600.1 ) 2,607.1 Net loss (income) attributable to noncontrolling interests -- (1.2 ) (12.9 ) (14.1 ) -- 3.9 (10.2 ) Net income attributable to entity $ 2,596.2 $ 2,659.4 $ (2,659.4 ) $ 2,596.2 $ 2,596.9 $ (2,596.2 ) $ 2,596.9 Enterprise Products Partners L.P. Condensed Consolidating Statement of Comprehensive Income For the Year Ended December 31, 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 $ 2,578.6 $ 2,793.1 $ (2,761.9 ) $ 2,609.8 $ 2,543.6 $ (2,572.6 ) $ 2,580.8 Comprehensive loss (income) attributable to noncontrolling interests -- 0.9 (42.9 ) (42.0 ) -- 4.8 (37.2 ) Comprehensive income attributable to entity $ 2,578.6 $ 2,794.0 $ (2,804.8 ) $ 2,567.8 $ 2,543.6 $ (2,567.8 ) $ 2,543.6 Enterprise Products Partners L.P. Condensed Consolidating Statement of Comprehensive Income For the Year Ended 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 Comprehensive income $ 2,856.4 $ 3,057.6 $ (2,958.9 ) $ 2,955.1 $ 2,904.8 $ (2,909.0 ) $ 2,950.9 Comprehensive loss (income) attributable to noncontrolling interests -- 0.4 (51.5 ) (51.1 ) -- 5.0 (46.1 ) Comprehensive income attributable to entity $ 2,856.4 $ 3,058.0 $ (3,010.4 ) $ 2,904.0 $ 2,904.8 $ (2,904.0 ) $ 2,904.8 Enterprise Products Partners L.P. Condensed Consolidating Statement of Comprehensive Income For the Year Ended December 31, 2013 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 $ 2,616.5 $ 2,651.6 $ (2,646.5 ) $ 2,621.6 $ 2,608.3 $ (2,611.4 ) $ 2,618.5 Comprehensive income attributable to noncontrolling interests -- (1.2 ) (12.9 ) (14.1 ) -- 3.9 (10.2 ) Comprehensive income attributable to entity $ 2,616.5 $ 2,650.4 $ (2,659.4 ) $ 2,607.5 $ 2,608.3 $ (2,607.5 ) $ 2,608.3 Enterprise Products Partners L.P. Condensed Consolidating Statement of Cash Flows For the Year Ended December 31, 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 $ 2,544.9 $ 2,804.4 $ (2,761.9 ) $ 2,587.4 $ 2,521.2 $ (2,550.2 ) $ 2,558.4 Reconciliation of net income to net cash flows provided by operating activities: Depreciation, amortization and accretion 144.9 1,371.5 (0.4 ) 1,516.0 -- -- 1,516.0 Equity in income of unconsolidated affiliates (2,718.4 ) (417.5 ) 2,762.3 (373.6 ) (2,548.7 ) 2,548.7 (373.6 ) Distributions received from unconsolidated affiliates 1,989.6 307.7 (1,835.2 ) 462.1 3,000.2 (3,000.2 ) 462.1 Net effect of changes in operating accounts and other operating activities 882.8 (1,031.0 ) (35.9 ) (184.1 ) 22.1 1.5 (160.5 ) Net cash flows provided by operating activities 2,843.8 3,035.1 (1,871.1 ) 4,007.8 2,994.8 (3,000.2 ) 4,002.4 Investing activities: Capital expenditures, net of contributions in aid of construction costs (1,180.0 ) (2,631.6 ) -- (3,811.6 ) -- -- (3,811.6 ) Cash used for business combinations, net of cash received (1,069.9 ) 13.4 -- (1,056.5 ) -- -- (1,056.5 ) Proceeds from asset sales and insurance recoveries 1,531.3 77.3 -- 1,608.6 -- -- 1,608.6 Other investing activities (1,513.4 ) (1,248.2 ) 2,579.3 (182.3 ) (1,179.8 ) 1,179.8 (182.3 ) Cash used in investing activities (2,232.0 ) (3,789.1 ) 2,579.3 (3,441.8 ) (1,179.8 ) 1,179.8 (3,441.8 ) Financing activities: Borrowings under debt agreements 21,081.1 133.9 (133.9 ) 21,081.1 -- -- 21,081.1 Repayments of debt (19,867.2 ) -- -- (19,867.2 ) -- -- (19,867.2 ) Cash distributions paid to partners (3,000.2 ) (1,882.4 ) 1,882.4 (3,000.2 ) (2,943.7 ) 3,000.2 (2,943.7 ) Cash payments made in connection with DERs -- -- -- -- (7.7 ) -- (7.7 ) Cash distributions paid to noncontrolling interests -- (0.8 ) (47.2 ) (48.0 ) -- -- (48.0 ) Cash contributions from noncontrolling interests -- 54.4 (0.4 ) 54.0 -- -- 54.0 Net cash proceeds from issuance of common units -- -- -- -- 1,188.6 -- 1,188.6 Cash contributions from owners 1,179.8 2,445.0 (2,445.0 ) 1,179.8 -- (1,179.8 ) -- Other financing activities (24.0 ) 3.1 -- (20.9 ) (52.2 ) -- (73.1 ) Cash provided by (used in) financing activities (630.5 ) 753.2 (744.1 ) (621.4 ) (1,815.0 ) 1,820.4 (616.0 ) Net change in cash and cash equivalents (18.7 ) (0.8 ) (35.9 ) (55.4 ) -- -- (55.4 ) Cash and cash equivalents, January 1 18.7 70.4 (14.7 ) 74.4 -- -- 74.4 Cash and cash equivalents, December 31 $ -- $ 69.6 $ (50.6 ) $ 19.0 $ -- $ -- $ 19.0 Enterprise Products Partners L.P. Condensed Consolidating Statement of Cash Flows For the Year Ended 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 Operating activities: Net income $ 2,786.0 $ 3,010.7 $ (2,959.0 ) $ 2,837.7 $ 2,787.4 $ (2,791.6 ) $ 2,833.5 Reconciliation of net income to net cash flows provided by operating activities: Depreciation, amortization and accretion 153.0 1,208.0 (0.5 ) 1,360.5 -- -- 1,360.5 Equity in income of unconsolidated affiliates (2,865.2 ) (354.3 ) 2,960.0 (259.5 ) (2,789.6 ) 2,789.6 (259.5 ) Distributions received from unconsolidated affiliates 4,539.9 327.1 (4,491.9 ) 375.1 2,702.9 (2,702.9 ) 375.1 Net effect of changes in operating accounts and other operating activities (627.0 ) 479.4 5.7 (141.9 ) (7.5 ) 2.0 (147.4 ) Net cash flows provided by operating activities 3,986.7 4,670.9 (4,485.7 ) 4,171.9 2,693.2 (2,702.9 ) 4,162.2 Investing activities: Capital expenditures, net of contributions in aid of construction costs (647.9 ) (2,216.1 ) -- (2,864.0 ) -- -- (2,864.0 ) Cash used for business combinations, net of cash received (2,437.5 ) 20.7 -- (2,416.8 ) -- -- (2,416.8 ) Proceeds from asset sales and insurance recoveries 4.3 141.0 -- 145.3 -- -- 145.3 Other investing activities (2,603.4 ) (660.0 ) 2,601.0 (662.4 ) (384.6 ) 384.6 (662.4 ) Cash used in investing activities (5,684.5 ) (2,714.4 ) 2,601.0 (5,797.9 ) (384.6 ) 384.6 (5,797.9 ) Financing activities: Borrowings under debt agreements 18,361.1 -- -- 18,361.1 -- -- 18,361.1 Repayments of debt (14,341.1 ) -- -- (14,341.1 ) -- -- (14,341.1 ) Cash distributions paid to partners (2,702.9 ) (4,537.8 ) 4,537.8 (2,702.9 ) (2,638.1 ) 2,702.9 (2,638.1 ) Cash payments made in connection with DERs -- -- -- -- (3.7 ) -- (3.7 ) Cash distributions paid to noncontrolling interests -- (2.7 ) (45.9 ) (48.6 ) -- -- (48.6 ) Cash contributions from noncontrolling interests -- -- 4.0 4.0 -- -- 4.0 Net cash proceeds from issuance of common units -- -- -- -- 388.8 -- 388.8 Cash contributions from owners 384.6 2,604.9 (2,604.9 ) 384.6 -- (384.6 ) -- Other financing activities (13.6 ) -- -- (13.6 ) (55.6 ) -- (69.2 ) Cash provided by (used in) financing activities 1,688.1 (1,935.6 ) 1,891.0 1,643.5 (2,308.6 ) 2,318.3 1,653.2 Net change in cash and cash equivalents (9.7 ) 20.9 6.3 17.5 -- -- 17.5 Cash and cash equivalents, January 1 28.4 49.5 (21.0 ) 56.9 -- -- 56.9 Cash and cash equivalents, December 31 $ 18.7 $ 70.4 $ (14.7 ) $ 74.4 $ -- $ -- $ 74.4 Enterprise Products Partners L.P. Condensed Consolidating Statement of Cash Flows For the Year Ended December 31, 2013 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 $ 2,596.2 $ 2,660.6 $ (2,646.5 ) $ 2,610.3 $ 2,596.9 $ (2,600.1 ) $ 2,607.1 Reconciliation of net income to net cash flows provided by operating activities: Depreciation, amortization and accretion 143.5 1,072.8 1.3 1,217.6 -- -- 1,217.6 Equity in income of unconsolidated affiliates (2,609.0 ) (204.8 ) 2,646.5 (167.3 ) (2,599.1 ) 2,599.1 (167.3 ) Distributions received from unconsolidated affiliates 4,523.2 233.7 (4,505.3 ) 251.6 2,454.4 (2,454.4 ) 251.6 Net effect of changes in operating accounts and other operating activities (1,351.0 ) 1,323.4 (10.1 ) (37.7 ) (7.8 ) 2.0 (43.5 ) Net cash flows provided by operating activities 3,302.9 5,085.7 (4,514.1 ) 3,874.5 2,444.4 (2,453.4 ) 3,865.5 Investing activities: Capital expenditures, net of contributions in aid of construction costs (517.8 ) (2,864.4 ) -- (3,382.2 ) -- -- (3,382.2 ) Proceeds from asset sales and insurance recoveries 59.6 221.0 -- 280.6 -- -- 280.6 Other investing activities (3,163.6 ) (769.5 ) 2,777.2 (1,155.9 ) (1,791.1 ) 1,791.1 (1,155.9 ) Cash used in investing activities (3,621.8 ) (3,412.9 ) 2,777.2 (4,257.5 ) (1,791.1 ) 1,791.1 (4,257.5 ) Financing activities: Borrowings under debt agreements 13,852.8 -- -- 13,852.8 -- -- 13,852.8 Repayments of debt (12,650.8 ) (29.8 ) -- (12,680.6 ) -- -- (12,680.6 ) Cash distributions paid to partners (2,453.4 ) (4,514.1 ) 4,514.1 (2,453.4 ) (2,400.4 ) 2,453.5 (2,400.3 ) Cash distributions paid to noncontrolling interests -- -- (8.9 ) (8.9 ) -- -- (8.9 ) Cash contributions from noncontrolling interests -- -- 115.4 115.4 -- -- 115.4 Net cash proceeds from issuance of common units -- -- -- -- 1,792.0 -- 1,792.0 Cash contributions from owners 1,791.2 2,892.6 (2,892.6 ) 1,791.2 -- (1,791.2 ) -- Other financing activities (192.5 ) -- -- (192.5 ) (45.1 ) -- (237.6 ) Cash provided by (used in) financing activities 347.3 (1,651.3 ) 1,728.0 424.0 (653.5 ) 662.3 432.8 Net change in cash and cash equivalents 28.4 21.5 (8.9 ) 41.0 (0.2 ) -- 40.8 Cash and cash equivalents, January 1 -- 28.0 (12.1 ) 15.9 0.2 -- 16.1 Cash and cash equivalents, December 31 $ 28.4 $ 49.5 $ (21.0 ) $ 56.9 $ -- $ -- $ 56.9

Summary of Significant Accoun29

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
Summary of Significant Accounting Policies [Abstract]
Allowance for Doubtful Accounts	Allowance for Doubtful Accounts Our allowance for doubtful accounts is determined based on specific identification and estimates of future uncollectible accounts, including those related to natural gas imbalances. Our procedure for estimating the allowance for doubtful accounts is based on: (i) historical experience with customers, (ii) the perceived financial stability of customers based on our research and (iii) the levels of credit we grant to customers. In addition, we may increase the allowance for doubtful accounts in response to the specific identification of customers involved in bankruptcy proceedings and similar financial difficulties. On a routine basis, we review estimates associated with the allowance for doubtful accounts to ensure that we have recorded sufficient reserves to cover potential losses. The following table presents our allowance for doubtful accounts activity for the periods indicated: For the Year Ended December 31, 2015 2014 2013 Balance at beginning of period $ 13.9 $ 7.5 $ 13.2 Charged to costs and expenses 0.8 8.4 2.1 Deductions (2.6 ) (2.0 ) (7.8 ) Balance at end of period $ 12.1 $ 13.9 $ 7.5 See "Credit Risk" in Note 18 for additional information.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and cash equivalents represent unrestricted cash on hand and highly liquid investments with original maturities of less than three months from the date of purchase.
Consolidation Policy	Consolidation Policy Our consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest, after the elimination of all intercompany accounts and transactions. We also consolidate other entities and ventures in which we possess a controlling financial interest as well as partnership interests where we are the sole general partner of the partnership. We evaluate our financial interests in business enterprises to determine if they represent variable interest entities where we are the primary beneficiary. If such criteria are met, we consolidate the financial statements of such businesses with those of our own. Third party or affiliate ownership interests in our controlled subsidiaries are presented as noncontrolling interests. See Note 9 for information regarding noncontrolling interests. If the entity is organized as a limited partnership or limited liability company and maintains separate ownership accounts, we account for our investment using the equity method if our ownership interest is between 3% and 50%, unless our interest is so minor that we have virtually no influence over the investee's operating and financial policies. For all other types of investments, we apply the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the investee's operating and financial policies. In consolidation, we eliminate our proportionate share of profits and losses from transactions with equity method unconsolidated affiliates to the extent such amounts remain on our Consolidated Balance Sheets (or those of our equity method investments) in inventory or similar accounts.
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 17 for additional information regarding our contingencies.
Current Assets and Current Liabilities	Current Assets and Current Liabilities We present, as individual captions in our Consolidated Balance Sheets, all components of current assets and current liabilities that exceed 5% of total current assets and current liabilities, respectively.
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. We are required to recognize derivative instruments at fair value as either assets or liabilities on our Consolidated Balance Sheets unless such instruments meet certain normal purchase/normal sale criteria. While all derivatives are required to be reported at fair value on the balance sheet, changes in fair value of derivative instruments are reported in different ways, depending on the nature and effectiveness of the hedging activities to which they relate. After meeting specified conditions, a qualified derivative may be designated as a total or partial hedge of:  Changes in the fair value of a recognized asset or liability, or an unrecognized firm commitment – In a fair value hedge, gains and losses for both the derivative instrument and the hedged item are recognized in income during the period of change.  Variable cash flows of a forecasted transaction – In a cash flow hedge, the effective portion of the hedge is reported in other comprehensive income (loss) and is reclassified into earnings when the forecasted transaction affects earnings. An effective hedge relationship is one in which the change in fair value of a derivative instrument can be expected to offset 80% to 125% of the changes in fair value of a hedged item at inception and throughout the life of the hedging relationship. The effective portion of a hedge relationship is the amount by which the derivative instrument exactly offsets the change in fair value of the hedged item during the reporting period. Conversely, ineffectiveness represents the change in the fair value of the derivative instrument that does not exactly offset the change in the fair value of the hedged item. Any ineffectiveness associated with a hedge relationship is recognized in earnings immediately. Ineffectiveness can be caused by, among other things, changes in the timing of forecasted transactions or a mismatch of terms between the derivative instrument and the hedged item. A contract designated as a cash flow hedge of an anticipated transaction that is not probable of occurring is immediately recognized in earnings. Certain of our derivative instruments do not qualify for hedge accounting treatment; therefore, these instruments are accounted for using mark-to-market accounting. 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 14 for additional information regarding our derivative instruments.
Environmental Costs	Environmental Costs Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management's best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals. Expenditures to mitigate or prevent future environmental contamination are capitalized. Ongoing environmental compliance costs are charged to expense as incurred. In accruing for environmental remediation liabilities, costs of future expenditures for environmental remediation are not discounted to their present value, unless the amount and timing of the expenditures are fixed or reliably determinable. At December 31, 2015, none of our estimated environmental remediation liabilities were discounted to present value since the ultimate amount and timing of cash payments for such liabilities were not readily determinable. The following table presents the activity of our environmental reserves for the periods indicated: For the Year Ended December 31, 2015 2014 2013 Balance at beginning of period $ 15.6 $ 9.9 $ 13.7 Charged to costs and expenses 6.4 11.9 3.9 Acquisition-related additions and other 1.1 2.5 0.7 Deductions (10.1 ) (8.7 ) (8.4 ) Balance at end of period $ 13.0 $ 15.6 $ 9.9 At December 31, 2015 and 2014, $5.8 million and $8.1 million, respectively, of our environmental reserves were classified as current liabilities.
Estimates	Estimates Preparing our consolidated financial statements in conformity with U.S. generally accepted accounting principles ("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.
Fair Value Measurements	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. The characteristics of fair value amounts classified within each level of the hierarchy are described as follows:  Level 1 fair values are based on quoted prices, which are available in active markets for identical assets or liabilities as of the measurement date. Active markets are defined as those in which transactions for identical assets or liabilities occur with sufficient frequency so as to provide pricing information on an ongoing basis (e.g., the New York Mercantile Exchange ("NYMEX")). Our Level 1 fair values consist of financial assets and liabilities such as exchange-traded commodity derivative instruments.  Level 2 fair values are based on pricing inputs other than quoted prices in active markets (as reflected in Level 1 fair values) and are either directly or indirectly observable as of the measurement date. Level 2 fair values include instruments that are valued using financial models or other appropriate valuation methodologies. Such financial models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, the time value of money, volatility factors, current market and contractual prices for the underlying instruments and other relevant economic measures. Substantially all of these assumptions (i) are observable in the marketplace throughout the full term of the instrument; (ii) can be derived from observable data; or (iii) are validated by inputs other than quoted prices (e.g., interest rate and yield curves at commonly quoted intervals). Our Level 2 fair values primarily consist of commodity derivative instruments such as forwards, swaps and other instruments transacted on an exchange or over-the-counter and interest rate derivative instruments. The fair values of these derivative instruments are based on observable price quotes for similar products and locations. The fair value of our interest rate derivatives are determined using financial models that incorporate the implied forward LIBOR yield curve for the same period as the future interest rate swap settlements.  Level 3 fair values are based on unobservable inputs. Unobservable inputs are used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. Unobservable inputs reflect management's ideas about the assumptions that market participants would use in pricing an asset or liability (including assumptions about risk). Unobservable inputs are based on the best information available to us in the circumstances, which might include our internally developed data. Level 3 inputs are typically used in connection with internally developed valuation methodologies where we make our best estimate of an instrument's fair value. With regards to commodity derivatives, our Level 3 fair values primarily consist of ethane, propane, normal butane and natural gasoline-based contracts with terms greater than one year and certain options used to hedge natural gas storage inventory and transportation capacities. In addition, we often rely on price quotes from reputable brokers who publish price quotes on certain products and compare these prices to other reputable brokers for the same products in the same markets whenever possible. These prices, when combined with data from our commodity derivative instruments, are used in our models to determine the fair value of such instruments. Transfers within the fair value hierarchy routinely occur for certain term contracts as prices and other inputs used for the valuation of future delivery periods become more observable with the passage of time. Other transfers are made periodically in response to changing market conditions that affect liquidity, price observability and other inputs used in determining valuations. We deem any such transfers to have occurred at the end of the quarter in which they transpired. There were no transfers between Level 1 and 2 during the years ended December 31, 2015 and 2014. We have a risk management policy that covers our Level 3 commodity derivatives. Governance and oversight of risk management activities for these commodities are provided by our Chief Executive Officer with guidance and support from a risk management committee ("RMC") that meets quarterly (or on a more frequent basis, if needed). Members of executive management attend the RMC meetings, which are chaired by the head of our commodities risk control group. This group is responsible for preparing and distributing daily reports and risk analysis to members of the RMC and other appropriate members of management. These reports include mark-to-market valuations with the one-day and month-to-date changes in fair values. This group also develops and validates the forward commodity price curves used to estimate the fair values of our Level 3 commodity derivatives. These forward curves incorporate published indexes, market quotes and other observable inputs to the extent available.
Impairment Testing for Goodwill	Impairment Testing for Goodwill Our goodwill amounts are assessed for impairment on a routine annual basis or when impairment indicators are present. If such indicators occur (e.g., the loss of a significant customer or technological obsolescence of assets), the estimated fair value of the reporting unit to which the goodwill is assigned is determined and compared to its carrying value. If the fair value of the reporting unit is less than its carrying value including associated goodwill amounts, a charge to earnings is recorded to reduce the carrying value of the goodwill to its implied fair value. Our reporting unit estimated fair values are based on assumptions regarding the future economic prospects of the businesses that comprise each reporting unit. Such assumptions include: (i) discrete financial forecasts for the assets classified within the reporting unit, which, in turn, rely on management's estimates of operating margins, throughput volumes and similar factors; (ii) long-term growth rates for cash flows beyond the discrete forecast period; and (iii) appropriate discount rates. We believe the assumptions we use in estimating reporting unit fair values are consistent with those that would be employed by market participants is their fair value estimation process. Based on our most recent goodwill impairment test at December 31, 2015, each reporting unit's fair value was substantially in excess of its carrying value (i.e., by at least 10%). See Note 7 for additional information regarding goodwill.
Impairment Testing for Long-Lived Assets	Impairment Testing for Long-Lived Assets Long-lived assets (including intangible assets with finite useful lives and property, plant and equipment) are reviewed for impairment 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 carrying value of a long-lived asset is deemed not recoverable if it exceeds the sum of undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the asset's carrying value exceeds the sum of its undiscounted cash flows, a non-cash asset impairment charge equal to the excess of the asset's carrying value over its estimated fair value is recorded. Fair value is defined as the price that would be received to sell an asset or be paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. We measure fair value using market price indicators or, in the absence of such data, appropriate valuation techniques. See Note 14 for information regarding impairment charges related to long-lived assets.
Impairment Testing for Unconsolidated Affiliates	Impairment Testing for Unconsolidated Affiliates We evaluate our equity method investments for impairment when events or changes in circumstances indicate that there is a loss in value of the investment attributable to an other than temporary decline. Examples of such events or changes in circumstances include continuing operating losses of the entity and/or long-term negative changes in the entity's industry. In the event we determine that the loss in value of an investment is an other than temporary decline, we record a charge to equity earnings to adjust the carrying value of the investment to its estimated fair value. There were no impairment charges in 2015 and 2014 related to our equity method investments. See Note 6 for information regarding our equity method investments, and Note 14 for information for the related impairment charge recorded during 2013.
Inventories	Inventories Inventories primarily consist of NGLs, petrochemicals, refined products, crude oil and natural gas volumes that are valued at the lower of average cost or market. We capitalize, as a cost of inventory, shipping and handling charges (e.g., pipeline transportation and storage fees) and other related costs associated with purchased volumes. As volumes are sold and delivered out of inventory, the cost of these volumes (including freight-in charges that have been capitalized as part of inventory cost) are charged to operating costs and expenses. Shipping and handling fees associated with products we sell and deliver to customers are charged to operating costs and expenses as incurred. See Note 4 for additional information regarding our inventories.
Property, Plant and Equipment	Property, Plant and Equipment Property, plant and equipment is recorded at cost. Expenditures for additions, improvements and other enhancements to property, plant and equipment are capitalized, and minor replacements, maintenance, and repairs that do not extend asset life or add value are charged to expense as incurred. When property, plant and equipment assets are retired or otherwise disposed of, the related cost and accumulated depreciation is removed from the accounts and any resulting gain or loss is included in results of operations for the respective period. 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. In general, depreciation is the systematic and rational allocation of an asset's cost, less its residual value (if any), to the periods it benefits. The majority of our property, plant and equipment is depreciated using the straight-line method, which results in depreciation expense being incurred evenly over the life of an asset. Our estimate of depreciation expense incorporates management assumptions regarding the useful economic lives and residual values of our assets. With respect to midstream energy assets such as natural gas gathering systems that are reliant upon a specific natural resource basin for throughput volumes, the anticipated useful economic life of such assets may be limited by the estimated life of the associated natural resource basin from which the assets derive benefit. Our forecast of the remaining life for the applicable resource basins is based on several factors, including information published by the U.S. Energy Information Administration. Where appropriate, we use other depreciation methods (generally accelerated) for tax purposes. Leasehold improvements are recorded as a component of property, plant and equipment. The cost of leasehold improvements is charged to earnings using the straight-line method over the shorter of (i) the remaining lease term or (ii) the estimated useful lives of the improvements. We consider renewal terms that are deemed reasonably assured when estimating remaining lease terms. Our assumptions regarding the useful economic lives and residual values of our assets may change in response to new facts and circumstances, which would prospectively impact our depreciation expense amounts. Examples of such circumstances include, but are not limited to: (i) changes in laws and regulations that limit the estimated economic life of an asset; (ii) changes in technology that render an asset obsolete; (iii) changes in expected salvage values or (iv) significant changes in the forecast life of the applicable resource basins, if any. Certain of our plant operations entail periodic planned outages for major maintenance activities. These planned shutdowns typically result in significant expenditures, which are principally comprised of amounts paid to third parties for materials, contract services and related items. We use the expense-as-incurred method for our planned major maintenance activities for plant operations; however, the cost of annual planned major maintenance projects for such plants are deferred and recognized ratably until the next planned annual outage. With regard to the planned major maintenance activities on our marine transportation assets and underground storage caverns, we use the deferral method to account for such costs. Under this method, major maintenance costs are capitalized and amortized over the period until the next major overhaul or cavern integrity project. Asset retirement obligations ("AROs") are legal obligations associated with the retirement of tangible long-lived assets that result from their acquisition, construction, development and/or normal operation. When an ARO is incurred, we record a liability for the ARO and capitalize an equal amount as an increase in the carrying value of the related long-lived asset. ARO amounts are measured at their estimated fair value using expected present value techniques. Over time, the ARO liability is accreted to its present value (through accretion expense) and the capitalized amount is depreciated over the remaining useful life of the related long-lived asset. We will incur a gain or loss to the extent that our ARO liabilities are not settled at their recorded amounts. See Note 5 for additional information regarding our property, plant and equipment and AROs.
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 December 31, 2015, our restricted cash amount was $15.9 million. We did not have any restricted cash as of December 31, 2014. See Note 14 for information regarding our derivative instruments and hedging activities.

Summary of Significant Accoun30

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
Summary of Significant Accounting Policies [Abstract]
Allowance for Doubtful Accounts Activity	The following table presents our allowance for doubtful accounts activity for the periods indicated: For the Year Ended December 31, 2015 2014 2013 Balance at beginning of period $ 13.9 $ 7.5 $ 13.2 Charged to costs and expenses 0.8 8.4 2.1 Deductions (2.6 ) (2.0 ) (7.8 ) Balance at end of period $ 12.1 $ 13.9 $ 7.5
Environmental Reserves Activity	The following table presents the activity of our environmental reserves for the periods indicated: For the Year Ended December 31, 2015 2014 2013 Balance at beginning of period $ 15.6 $ 9.9 $ 13.7 Charged to costs and expenses 6.4 11.9 3.9 Acquisition-related additions and other 1.1 2.5 0.7 Deductions (10.1 ) (8.7 ) (8.4 ) Balance at end of period $ 13.0 $ 15.6 $ 9.9

Inventories (Tables)

Inventories (Tables)	12 Months Ended
	Dec. 31, 2015
Inventories [Abstract]
Inventory Amounts by Product Type	Our inventory amounts by product type were as follows at the dates indicated: December 31, 2015 2014 NGLs $ 639.9 $ 579.1 Petrochemicals and refined products 148.0 295.6 Crude oil 222.1 97.8 Natural gas 28.1 41.7 Total $ 1,038.1 $ 1,014.2
Cost of Sales and Lower of Cost or Market Adjustments	The following table presents our total cost of sales amounts and lower of cost or market adjustments for the periods indicated: For the Year Ended December 31, 2015 2014 2013 Cost of sales (1) $ 19,612.9 $ 40,464.1 $ 40,770.2 Lower of cost or market adjustments within cost of sales 19.8 22.8 18.5 (1) Cost of sales is a component of "Operating costs and expenses," as presented on our 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)	12 Months Ended
	Dec. 31, 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 December 31, in Years 2015 2014 Plants, pipelines and facilities (1) 3-45 (6) $ 32,525.0 $ 30,834.9 Underground and other storage facilities (2) 5-40 (7) 3,000.5 2,584.2 Platforms and facilities (3) 20-31 -- 659.7 Transportation equipment (4) 3-10 159.9 154.2 Marine vessels (5) 15-30 769.8 796.4 Land 262.7 262.6 Construction in progress 3,894.0 2,754.7 Total 40,611.9 38,046.7 Less accumulated depreciation 8,577.2 8,165.1 Property, plant and equipment, net $ 32,034.7 $ 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; buildings; office furniture and equipment; 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. (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; buildings, 20-40 years; office furniture and equipment, 3-20 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 Year Ended December 31, 2015 2014 2013 Depreciation expense (1) $ 1,161.6 $ 1,114.1 $ 1,012.4 Capitalized interest (2) 149.1 77.9 133.0 (1) Depreciation expense is a component of "Costs and expenses" as presented on our Statements of Consolidated Operations. (2) Capitalized interest is a component of "Interest expense" as presented on our Statements of Consolidated Operations.
AROs	The following table presents information regarding our AROs for the periods indicated: For the Year Ended December 31, 2015 2014 2013 ARO liability beginning balance $ 98.3 $ 90.2 $ 105.2 Liabilities incurred 2.7 0.1 1.7 Liabilities settled (6.3 ) (2.7 ) (14.2 ) Revisions in estimated cash flows 49.7 4.6 (8.6 ) Accretion expense 5.2 6.1 6.1 AROs related to Offshore Business sold in July 2015 (91.1 ) -- -- ARO liability ending balance $ 58.5 $ 98.3 $ 90.2
Forecasted Accretion Expense Associated with AROs	The following table presents our forecast of accretion expense for the periods indicated: 2016 2017 2018 2019 2020 $ 3.7 $ 4.0 $ 4.3 $ 4.7 $ 5.0

Investments in Unconsolidated33

Investments in Unconsolidated Affiliates (Tables)	12 Months Ended
	Dec. 31, 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 December 31, 2015 December 31, 2015 2014 NGL Pipelines & Services: Venice Energy Service Company, L.L.C. ("VESCO") 13.1% $ 25.9 $ 27.7 K/D/S Promix, L.L.C. ("Promix") 50% 38.3 38.5 Baton Rouge Fractionators LLC ("BRF") 32.2% 18.5 18.8 Skelly-Belvieu Pipeline Company, L.L.C. ("Skelly-Belvieu") 50% 39.8 40.1 Texas Express Pipeline LLC ("Texas Express") 35% 342.0 349.3 Texas Express Gathering LLC ("TEG") 45% 36.8 37.9 Front Range Pipeline LLC ("Front Range") 33.3% 171.2 170.0 Delaware Basin Gas Processing LLC ("Delaware Processing") 50% 46.2 -- Crude Oil Pipelines & Services: Seaway Crude Pipeline Company LLC ("Seaway") 50% 1,396.0 1,431.2 Eagle Ford Pipeline LLC ("Eagle Ford Crude Oil Pipeline") 50% 388.8 336.5 Eagle Ford Terminals Corpus Christi LLC ("Eagle Ford Corpus Christi") 50% 28.6 -- Natural Gas Pipelines & Services: White River Hub, LLC ("White River Hub") 50% 22.5 23.2 Petrochemical & Refined Products Services: Baton Rouge Propylene Concentrator, LLC ("BRPC") 30% 5.4 6.5 Centennial Pipeline LLC ("Centennial") 50% 65.6 66.1 Other Various 2.9 2.5 Offshore Pipelines & Services: Various, sold to Genesis in July 2015 (see Note 5) n/a -- 493.7 Total investments in unconsolidated affiliates $ 2,628.5 $ 3,042.0 The following table presents our equity in income (loss) of unconsolidated affiliates by business segment for the periods indicated: For the Year Ended December 31, 2015 2014 2013 NGL Pipelines & Services $ 57.5 $ 30.6 $ 15.7 Crude Oil Pipelines & Services 281.4 184.6 140.3 Natural Gas Pipelines & Services 3.8 3.6 3.8 Petrochemical & Refined Products Services (1) (15.7 ) (13.3 ) (22.3 ) Offshore Pipelines & Services 46.6 54.0 29.8 Total $ 373.6 $ 259.5 $ 167.3 (1) Losses are primarily attributable to our investment in Centennial. As a result of a trend in declining earnings, we estimated the fair value of this equity-method investment during each of the last three fiscal years. Our estimates, based on a combination of the market and income approaches, indicate that the fair value of this investment remains substantially in excess of its carrying value. The following table presents our unamortized excess cost amounts by business segment at the dates indicated: December 31, 2015 2014 NGL Pipelines & Services $ 25.3 $ 26.5 Crude Oil Pipelines & Services 19.3 21.7 Petrochemical & Refined Products Services 2.3 2.4 Offshore Pipelines & Services (1) -- 9.0 Total $ 46.9 $ 59.6 (1) Our investments in unconsolidated affiliates classified within the Offshore Pipelines & Services segment were sold to Genesis in July 2015. Combined balance sheet information for the last two years and results of operations data for the last three years for our unconsolidated affiliates are summarized in the following table (all data presented on a 100% basis): December 31, 2015 2014 Balance Sheet Data: Current assets $ 204.5 $ 289.9 Property, plant and equipment, net 5,671.1 6,766.5 Other assets 58.9 60.4 Total assets $ 5,934.5 $ 7,116.8 Current liabilities $ 306.7 $ 305.9 Other liabilities 103.2 309.9 Combined equity 5,524.6 6,501.0 Total liabilities and combined equity $ 5,934.5 $ 7,116.8 For the Year Ended December 31, 2015 2014 2013 Income Statement Data: Revenues $ 1,426.6 $ 1,311.3 $ 947.4 Operating income 825.8 600.0 423.9 Net income 814.1 587.9 382.6

Intangible Assets and Goodwill

Intangible Assets and Goodwill (Tables)	12 Months Ended
	Dec. 31, 2015
Intangible Assets and Goodwill [Abstract]
Intangible Assets by Segment	The following table summarizes our intangible assets by business segment at the dates indicated: December 31, 2015 December 31, 2014 Gross Value Accumulated Amortization Carrying Value Gross Value Accumulated Amortization Carrying Value NGL Pipelines & Services: Customer relationship intangibles $ 447.4 $ (156.9 ) $ 290.5 $ 340.8 $ (183.2 ) $ 157.6 Contract-based intangibles 283.0 (193.2 ) 89.8 277.7 (178.7 ) 99.0 IDRs (1) -- -- -- 432.6 -- 432.6 Segment total 730.4 (350.1 ) 380.3 1,051.1 (361.9 ) 689.2 Crude Oil Pipelines & Services: Customer relationship intangibles 2,204.4 (39.1 ) 2,165.3 1,108.0 (7.7 ) 1,100.3 Contract-based intangibles 281.4 (69.2 ) 212.2 281.4 (13.5 ) 267.9 IDRs (1) -- -- -- 855.4 -- 855.4 Segment total 2,485.8 (108.3 ) 2,377.5 2,244.8 (21.2 ) 2,223.6 Natural Gas Pipelines & Services: Customer relationship intangibles 1,350.3 (366.3 ) 984.0 1,163.6 (308.9 ) 854.7 Contract-based intangibles 464.7 (361.0 ) 103.7 466.0 (347.8 ) 118.2 Segment total 1,815.0 (727.3 ) 1,087.7 1,629.6 (656.7 ) 972.9 Petrochemical & Refined Products Services: Customer relationship intangibles 185.5 (38.3 ) 147.2 198.4 (43.3 ) 155.1 Contract-based intangibles 56.3 (11.8 ) 44.5 56.3 (7.8 ) 48.5 IDRs (1) -- -- -- 171.2 -- 171.2 Segment total 241.8 (50.1 ) 191.7 425.9 (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 $ 5,273.0 $ (1,235.8 ) 4,037.2 $ 5,548.4 $ (1,246.3 ) $ 4,302.1 (1) We recorded intangible assets having an aggregate carrying value of $1.46 billion in connection with our October 2014 acquisition of the IDRs of Oiltanking. The IDRs represented contractual rights to future cash incentive distributions to be paid by Oiltanking. These rights were granted to Oiltanking GP under the terms of Oiltanking's partnership agreement. Oiltanking GP could separate and sell the IDRs independent of its other residual general partner interest in Oiltanking. In February 2015 (following completion of Step 2 of the Oiltanking acquisition), the Oiltanking IDRs were cancelled and the carrying value of this intangible asset was reclassified to goodwill. (2) Our intangible assets classified within the Offshore Pipelines & Services segment were sold to Genesis in July 2015 (see Note 5).
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 Year Ended December 31, 2015 2014 2013 NGL Pipelines & Services $ 33.6 $ 33.1 $ 36.4 Crude Oil Pipelines & Services 87.1 15.7 1.4 Natural Gas Pipelines & Services 40.0 45.0 50.1 Petrochemical & Refined Products Services 8.9 6.9 6.2 Offshore Pipelines & Services 4.5 9.9 11.5 Total $ 174.1 $ 110.6 $ 105.6
Forecasted Amortization Expense	The following table presents our forecast of amortization expense associated with existing intangible assets for the years indicated: 2016 2017 2018 2019 2020 $ 181.6 $ 177.4 $ 171.6 $ 167.0 $ 166.3
Significant Acquired Intangible Assets	At December 31, 2015, the carrying value of our portfolio of customer relationship intangible assets was $3.59 billion, the principal components of which are as follows: Weighted Average Remaining Amortization Period at December 31, 2015 December 31, 2015 Gross Value Accumulated Amortization Carrying Value Basin-specific customer relationships: EFS Midstream (1) 26.4 years $ 1,409.8 $ (26.2 ) $ 1,383.6 State Line and Fairplay (2) 31.2 years 895.0 (141.7 ) 753.3 San Juan Gathering (3) 23.8 years 331.3 (196.4 ) 134.9 Encinal (4) 11.0 years 132.9 (86.9 ) 46.0 General customer relationships: Oiltanking (5) 28.0 years 1,192.5 (11.5 ) 1,181.0 (1) We acquired these intangible assets in connection with our acquisition of EFS Midstream in July 2015 (see Note 12 for additional information). (2) These customer relationships are associated with our State Line and Fairplay Gathering Systems, which we acquired in 2010. The State Line system serves producers in the Haynesville and Bossier Shale supply basins and the Cotton Valley and Taylor Sand formations in Louisiana and eastern Texas. The Fairplay system serves producers in the Cotton Valley and Taylor Sand formations within Panola and Rusk counties in East Texas. (3) These customer relationships are associated with our San Juan Gathering System, which serves producers in the San Juan Basin of northern New Mexico and southern Colorado. We acquired this intangible asset in 2004. (4) These customer relationships are associated with our Encinal Gathering System, which serves producers in the Olmos and Wilcox formations in South Texas. We acquired this intangible asset in 2006. (5) We acquired these intangible assets in connection with our acquisition of Oiltanking in October 2014 (see Note 12 for additional information).
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. Goodwill is not amortized; however, it is subject to annual impairment testing at the end of each fiscal year, and more frequently, if circumstances indicate it is probable that the fair value of goodwill is below its carrying amount. The following table presents changes in the carrying amount of goodwill during the periods indicated: NGL Pipelines & Services Crude Oil Pipelines & Services Natural Gas Pipelines & Services Petrochemical & Refined Products Services Offshore Pipelines & Services Consolidated Total Balance at December 31, 2012 $ 341.2 $ 311.2 $ 296.3 $ 1,056.0 $ 82.1 $ 2,086.8 Reduction in goodwill related to the sale of assets -- (6.1 ) -- (0.7 ) -- (6.8 ) Balance at December 31, 2013 341.2 305.1 296.3 1,055.3 82.1 2,080.0 Reclassification of goodwill between segments 520.0 -- -- (520.0 ) -- -- Reduction in goodwill related to the sale of assets -- -- -- -- (0.1 ) (0.1 ) Addition to goodwill related to the acquisition of Oiltanking 1,349.0 613.6 -- 257.7 -- 2,220.3 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 -- (2.1 ) -- -- (82.0 ) (84.1 ) Addition to goodwill related to the acquisition of EFS Midstream 8.9 73.7 -- -- -- 82.6 Goodwill reclassified to assets held-for-sale -- -- -- (7.6 ) -- (7.6 ) Balance at December 31, 2015 $ 2,651.7 $ 1,841.0 $ 296.3 $ 956.2 $ -- $ 5,745.2

Debt Obligations (Tables)

Debt Obligations (Tables)	12 Months Ended
	Dec. 31, 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: December 31, 2015 2014 EPO senior debt obligations: Commercial Paper Notes, variable-rates $ 1,114.1 $ 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 21,264.1 19,856.5 EPO Junior Subordinated Notes A, fixed/variable-rate, due August 2066 521.1 550.0 EPO Junior Subordinated Notes C, fixed/variable-rate, due June 2067 256.4 285.8 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 22,738.5 21,389.2 Other, non-principal amounts (47.9 ) (25.4 ) Less current maturities of debt (1,863.9 ) (2,206.4 ) Total long-term debt $ 20,826.7 $ 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 3.708%. (2) Fixed rate of 7.000% through September 1, 2017 (i.e., first call date without a make-whole redemption premium); thereafter, variable rate based on 3-month LIBOR plus 2.778%. (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 2.680%.
Consolidated Debt Maturities	The following table presents contractually scheduled maturities of our consolidated debt obligations outstanding at December 31, 2015 for the next five years, and in total thereafter: Scheduled Maturities of Debt Total 2016 2017 2018 2019 2020 Thereafter Commercial Paper Notes $ 1,114.1 $ 1,114.1 $ -- $ -- $ -- $ -- $ -- Senior Notes 20,150.0 750.0 800.0 1,100.0 1,500.0 1,500.0 14,500.0 Junior Subordinated Notes 1,474.4 -- -- -- -- -- 1,474.4 Total $ 22,738.5 $ 1,864.1 $ 800.0 $ 1,100.0 $ 1,500.0 $ 1,500.0 $ 15,974.4
Junior Subordinated Notes Interest Rate Terms	The following table summarizes the interest rate terms of our junior subordinated notes: Series Fixed Annual Interest Rate Variable Annual Interest Rate Thereafter Junior Subordinated Notes A 8.375% through August 2016 3-month LIBOR rate + 3.708% (4) Junior Subordinated Notes B 7.034% through January 2018 (2) Greater of: (i) 3-month LIBOR rate + 2.680% or (ii) 7.034% (5) Junior Subordinated Notes C 7.000% through September 2017 (3) 3-month LIBOR rate + 2.778% (1) Interest is payable semi-annually in arrears in February and August of each year, which commenced in February 2007. (2) Interest is payable semi-annually in arrears in January and July of each year, which commenced in January 2008. (3) Interest is payable semi-annually in arrears in June and December of each year, which commenced in December 2009. (4) Interest is payable quarterly in arrears in February, May, August and November of each year commencing in November 2016. (5) Interest is payable quarterly in arrears in January, April, July and October of each year commencing in April 2018. (6) Interest is payable quarterly in arrears in March, June, September and December of each year commencing in June 2017.
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 year ended December 31, 2015: Range of Interest Rates Paid Weighted-Average Interest Rate Paid Commercial Paper Notes 0.35% to 0.92% 0.58% Multi-Year Revolving Credit Facility 1.15% to 3.25% 1.30%

Equity and Distributions (Table

Equity and Distributions (Tables)	12 Months Ended
	Dec. 31, 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, and Class B units) that we have outstanding. The following table summarizes changes in the number of our outstanding units since December 31, 2012: Common Units (Unrestricted) Restricted Common Units Total Common Units Number of units outstanding at December 31, 2012 1,789,839,702 7,786,972 1,797,626,674 Common units issued in connection with underwritten offering 36,800,000 -- 36,800,000 Common units issued in connection with ATM program 15,249,378 -- 15,249,378 Common units issued in connection with DRIP and EUPP 10,308,254 -- 10,308,254 Common units issued in connection with the vesting and exercise of unit options 401,764 -- 401,764 Common units issued in connection with the vesting of restricted common unit awards 3,770,696 (3,770,696 ) -- Conversion and reclassification of Class B units to common units 9,040,862 -- 9,040,862 Restricted common unit awards issued -- 3,549,052 3,549,052 Forfeiture of restricted common unit awards -- (344,114 ) (344,114 ) Acquisition and cancellation of treasury units in connection with the vesting of equity-based awards (1,261,854 ) -- (1,261,854 ) Number of units outstanding at December 31, 2013 1,864,148,802 7,221,214 1,871,370,016 Common units issued in connection with ATM program 1,590,334 -- 1,590,334 Common units issued in connection with DRIP and EUPP 9,754,227 -- 9,754,227 Common units issued in connection with Step 1 of Oiltanking acquisition 54,807,352 -- 54,807,352 Common units issued in connection with the vesting and exercise of unit options 1,014,108 -- 1,014,108 Common units issued in connection with the vesting of phantom unit awards 23,311 -- 23,311 Common units issued in connection with the vesting of restricted common unit awards 2,634,074 (2,634,074 ) -- Forfeiture of restricted common unit awards -- (357,350 ) (357,350 ) Acquisition and cancellation of treasury units in connection with the vesting of equity-based awards (894,383 ) -- (894,383 ) Other 17,202 -- 17,202 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 25,520,424 -- 25,520,424 Common units issued in connection with DRIP and EUPP 12,793,913 -- 12,793,913 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 396,158 -- 396,158 Common units issued in connection with the vesting of phantom unit awards 618,395 -- 618,395 Common units issued in connection with the vesting of restricted common unit awards 2,009,970 (2,009,970 ) -- Forfeiture of restricted common unit awards -- (259,300 ) (259,300 ) Acquisition and cancellation of treasury units in connection with the vesting of equity-based awards (683,954 ) -- (683,954 ) Other 15,054 -- 15,054 Number of units outstanding at December 31, 2015 2,010,592,504 1,960,520 2,012,553,024
Components of Accumulated Other Comprehensive Income (Loss)	The following tables present the components of accumulated other comprehensive income (loss) as reported on our 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, 2013 $ (14.7 ) $ (347.2 ) $ 2.9 $ (359.0 ) Other comprehensive income before reclassifications 161.3 -- 0.4 161.7 Amounts reclassified from accumulated other comprehensive (income) loss (76.7 ) 32.4 -- (44.3 ) Total other comprehensive income 84.6 32.4 0.4 117.4 Balance, December 31, 2014 69.9 (314.8 ) 3.3 (241.6 ) Other comprehensive income before reclassifications 214.9 -- 0.4 215.3 Amounts reclassified from accumulated other comprehensive (income) loss (228.2 ) 35.3 -- (192.9 ) Total other comprehensive income (loss) (13.3 ) 35.3 0.4 22.4 Balance, December 31, 2015 $ 56.6 $ (279.5 ) $ 3.7 $ (219.2 )
Reclassifications out of Accumulated Other Comprehensive Income (Loss) Into Net Income	The following table presents reclassifications out of accumulated other comprehensive income (loss) into net income during the periods indicated: For the Year Ended December 31, Location 2015 2014 Losses (gains) on cash flow hedges: Interest rate derivatives Interest expense $ 35.3 $ 32.4 Commodity derivatives Revenue (231.7 ) (75.0 ) Commodity derivatives Operating costs and expenses 3.5 (1.7 ) Total $ (192.9 ) $ (44.3 )
Components of Noncontrolling Interests	The following table presents additional information regarding noncontrolling interests as presented on our Consolidated Balance Sheets at the dates indicated: December 31, 2015 2014 Limited partners of Oiltanking other than EPO $ -- $ 1,408.9 Joint venture partners 206.0 220.1 Total $ 206.0 $ 1,629.0
Components of Net Income Attributable to Noncontrolling Interests	The following table presents the components of net income attributable to noncontrolling interests as presented on our Statements of Consolidated Operations for the periods indicated: For the Year Ended December 31, 2015 2014 2013 Limited partners of Oiltanking other than EPO $ 7.8 $ 14.2 $ -- Joint venture partners 29.4 31.9 10.2 Total $ 37.2 $ 46.1 $ 10.2
Cash Distributions Paid to and Cash Contributions Received From Noncontrolling Interests	The following table presents cash distributions paid to and cash contributions received from noncontrolling interests as presented on our Statements of Consolidated Cash Flows and Statements of Consolidated Equity for the periods indicated: For the Year Ended December 31, 2015 2014 2013 Cash distributions paid to noncontrolling interests: Limited partners of Oiltanking other than EPO $ 8.1 $ 7.7 $ -- Joint venture partners 39.9 40.9 8.9 Total $ 48.0 $ 48.6 $ 8.9 Cash contributions from noncontrolling interests: Joint venture partners $ 54.0 $ 4.0 $ 115.4
Declared Quarterly Cash Distribution Rates	The following table presents Enterprise's declared quarterly cash distribution rates per common unit with respect to the quarter indicated. Actual cash distributions are paid by Enterprise within 45 days after the end of each fiscal quarter. 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 4th Quarter $ 0.3700 1/30/2015 2/6/2015 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 4th Quarter $ 0.3900 1/29/2016 2/5/2016

Business Segments (Tables)

Business Segments (Tables)	12 Months Ended
	Dec. 31, 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 Year Ended December 31, 2015 2014 2013 Revenues $ 27,027.9 $ 47,951.2 $ 47,727.0 Subtract operating costs and expenses (23,668.7 ) (44,220.5 ) (44,238.7 ) Add equity in income of unconsolidated affiliates 373.6 259.5 167.3 Add depreciation, amortization and accretion expense amounts not reflected in gross operating margin 1,428.2 1,282.7 1,148.9 Add impairment charges not reflected in gross operating margin 162.6 34.0 92.6 Add net losses or subtract net gains attributable to asset sales and insurance recoveries not reflected in gross operating margin (see Note 19) 15.6 (102.1 ) (83.4 ) Add non-refundable deferred revenues attributable to shipper make-up rights on major new pipeline projects reflected in gross operating margin 53.6 84.6 4.4 Subtract subsequent recognition of deferred revenues attributable to make-up rights not reflected in gross operating margin (60.7 ) (2.9 ) -- Total segment gross operating margin $ 5,332.1 $ 5,286.5 $ 4,818.1
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 Year Ended December 31, 2015 2014 2013 Total segment gross operating margin $ 5,332.1 $ 5,286.5 $ 4,818.1 Adjustments to reconcile total segment gross operating margin to operating income: Subtract depreciation, amortization and accretion expense amounts not reflected in gross operating margin (1,428.2 ) (1,282.7 ) (1,148.9 ) Subtract impairment charges not reflected in gross operating margin (162.6 ) (34.0 ) (92.6 ) Add net gains or subtract net losses attributable to asset sales and insurance recoveries not reflected in gross operating margin (15.6 ) 102.1 83.4 Subtract non-refundable deferred revenues attributable to shipper make-up rights on major new pipeline projects reflected in gross operating margin (53.6 ) (84.6 ) (4.4 ) Add subsequent recognition of deferred revenues attributable to make-up rights not reflected in gross operating margin 60.7 2.9 -- Subtract general and administrative costs not reflected in gross operating margin (192.6 ) (214.5 ) (188.3 ) Operating income 3,540.2 3,775.7 3,467.3 Other expense, net (984.3 ) (919.1 ) (802.7 ) Income before income taxes $ 2,555.9 $ 2,856.6 $ 2,664.6
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: Year ended December 31, 2015 $ 9,779.0 $ 10,258.3 $ 2,729.5 $ 4,111.9 $ 76.9 $ -- $ 26,955.6 Year ended December 31, 2014 17,078.4 20,151.9 4,182.6 6,316.5 150.3 -- 47,879.7 Year ended December 31, 2013 17,119.1 20,609.1 3,522.7 6,258.5 151.7 -- 47,661.1 Revenues from related parties: Year ended December 31, 2015 9.0 47.6 13.8 -- 1.9 -- 72.3 Year ended December 31, 2014 11.4 32.4 21.2 -- 6.5 -- 71.5 Year ended December 31, 2013 1.1 41.3 15.8 -- 7.7 -- 65.9 Intersegment and intrasegment revenues: Year ended December 31, 2015 10,217.9 5,162.0 662.1 1,126.0 0.6 (17,168.6 ) -- Year ended December 31, 2014 13,716.5 12,678.7 1,106.7 1,779.6 6.5 (29,288.0 ) -- Year ended December 31, 2013 11,096.6 10,222.3 959.7 1,764.0 9.6 (24,052.2 ) -- Total revenues: Year ended December 31, 2015 20,005.9 15,467.9 3,405.4 5,237.9 79.4 (17,168.6 ) 27,027.9 Year ended December 31, 2014 30,806.3 32,863.0 5,310.5 8,096.1 163.3 (29,288.0 ) 47,951.2 Year ended December 31, 2013 28,216.8 30,872.7 4,498.2 8,022.5 169.0 (24,052.2 ) 47,727.0 Equity in income (loss) of unconsolidated affiliates: Year ended December 31, 2015 57.5 281.4 3.8 (15.7 ) 46.6 -- 373.6 Year ended December 31, 2014 30.6 184.6 3.6 (13.3 ) 54.0 -- 259.5 Year ended December 31, 2013 15.7 140.3 3.8 (22.3 ) 29.8 -- 167.3 Gross operating margin: Year ended December 31, 2015 2,771.6 961.9 782.6 718.5 97.5 -- 5,332.1 Year ended December 31, 2014 2,877.7 762.5 803.3 681.0 162.0 -- 5,286.5 Year ended December 31, 2013 2,514.4 742.7 789.0 625.9 146.1 -- 4,818.1 Property, plant and equipment, net: At December 31, 2015 12,909.7 3,550.3 8,620.0 3,060.7 -- 3,894.0 32,034.7 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 At December 31, 2013 9,957.8 1,479.9 8,917.3 2,712.4 1,223.7 2,655.5 26,946.6 Investments in unconsolidated affiliates: At December 31, 2015 718.7 1,813.4 22.5 73.9 -- -- 2,628.5 At December 31, 2014 682.3 1,767.7 23.2 75.1 493.7 -- 3,042.0 At December 31, 2013 645.5 1,165.2 24.2 70.4 531.8 -- 2,437.1 Intangible assets, net: At December 31, 2015 380.3 2,377.5 1,087.7 191.7 -- -- 4,037.2 At December 31, 2014 689.2 2,223.6 972.9 374.8 41.6 -- 4,302.1 At December 31, 2013 285.2 4.5 1,017.8 100.0 54.7 -- 1,462.2 Goodwill: At December 31, 2015 2,651.7 1,841.0 296.3 956.2 -- -- 5,745.2 At December 31, 2014 2,210.2 918.7 296.3 793.0 82.0 -- 4,300.2 At December 31, 2013 341.2 305.1 296.3 1,055.3 82.1 -- 2,080.0 Segment assets: At December 31, 2015 16,660.4 9,582.2 10,026.5 4,282.5 -- 3,894.0 44,445.6 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 At December 31, 2013 11,229.7 2,954.7 10,255.6 3,938.1 1,892.3 2,655.5 32,925.9
Consolidated Revenues and Expenses	The following table presents additional information regarding our consolidated revenues and costs and expenses for the periods indicated: For the Year Ended December 31, 2015 2014 2013 NGL Pipelines & Services: Sales of NGLs and related products $ 8,044.8 $ 15,460.1 $ 15,916.0 Midstream services 1,743.2 1,629.7 1,204.2 Total 9,788.0 17,089.8 17,120.2 Crude Oil Pipelines & Services: Sales of crude oil 9,732.9 19,783.9 20,371.3 Midstream services 573.0 400.4 279.1 Total 10,305.9 20,184.3 20,650.4 Natural Gas Pipelines & Services: Sales of natural gas 1,722.6 3,181.7 2,571.6 Midstream services 1,020.7 1,022.1 966.9 Total 2,743.3 4,203.8 3,538.5 Petrochemical & Refined Products Services: Sales of petrochemicals and refined products 3,333.5 5,575.5 5,568.8 Midstream services 778.4 741.0 689.7 Total 4,111.9 6,316.5 6,258.5 Offshore Pipelines & Services: Sales of natural gas -- 0.3 0.5 Sales of crude oil 3.2 8.6 5.7 Midstream services 75.6 147.9 153.2 Total 78.8 156.8 159.4 Total consolidated revenues $ 27,027.9 $ 47,951.2 $ 47,727.0 Consolidated costs and expenses Operating costs and expenses: Cost of sales $ 19,612.9 $ 40,464.1 $ 40,770.2 Other operating costs and expenses (1) 2,449.4 2,541.8 2,310.4 Depreciation, amortization and accretion 1,428.2 1,282.7 1,148.9 Ne t losses (g and insurance recoveries 15.6 (102.1 ) (83.4 ) Non-cash asset impairment charges 162.6 34.0 92.6 General and administrative costs 192.6 214.5 188.3 Total consolidated costs and expenses $ 23,861.3 $ 44,435.0 $ 44,427.0 (1) Represents cost of operating our plants, pipelines and other fixed assets, excluding depreciation, amortization and accretion charges. Our largest non-affiliated customer for 2015 was Shell Oil Company and its affiliates (collectively, "Shell"), which accounted for $2.0 billion, or 7.4%, of our consolidated revenues for the year. The following table presents our consolidated revenues from Shell by business segment for the year ended December 31, 2015: NGL Pipelines & Services $ 400.4 Crude Oil Pipelines & Services 1,335.8 Natural Gas Pipelines & Services 48.6 Petrochemical & Refined Products Services 206.5 Offshore Pipelines & Services 8.0 Total $ 1,999.3

Earnings Per Unit (Tables)

Earnings Per Unit (Tables)	12 Months Ended
	Dec. 31, 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 Year Ended December 31, 2015 2014 2013 BASIC EARNINGS PER UNIT Net income attributable to limited partners $ 2,521.2 $ 2,787.4 $ 2,596.9 Undistributed earnings allocated and cash payments on phantom unit awards (1) (8.7 ) (5.2 ) -- Net income available to common unitholders $ 2,512.5 $ 2,782.2 $ 2,596.9 Basic weighted-average number of common units outstanding 1,966.6 1,848.7 1,788.0 Basic earnings per unit $ 1.28 $ 1.51 $ 1.45 DILUTED EARNINGS PER UNIT Net income attributable to limited partners $ 2,521.2 $ 2,787.4 $ 2,596.9 Diluted weighted-average number of units outstanding: Distribution-bearing common units 1,966.6 1,848.7 1,788.0 Designated Units 26.5 42.7 46.8 Class B units (2) -- -- 5.4 Phantom units (1) 5.4 2.9 -- Incremental option units 0.1 0.9 2.4 Total 1,998.6 1,895.2 1,842.6 Diluted earnings per unit $ 1.26 $ 1.47 $ 1.41 (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. (2) The Class B units automatically converted into an equal number of distribution-bearing common units in August 2013.

Business Combinations (Tables)

Business Combinations (Tables)	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Allocation of Total Purchase Prices Paid in Connection with Business Combinations	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 our final purchase price allocation for the EFS Midstream acquisition: Consideration: Cash $ 1,069.9 Accrued liability related to EFS Midstream acquisition 986.6 Total consideration $ 2,056.5 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 (see Note 7) 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 2,056.5 Goodwill $ 82.6 We engaged an independent third party business valuation expert to assist us in estimating the fair values of the tangible and intangible assets of Oiltanking. The following table summarizes our final purchase price allocation for the Oiltanking acquisition: Consideration: Cash $ 2,438.3 Equity instruments (54,807,352 common units of Enterprise) (1) 2,171.5 Fair value of total consideration transferred in Step 1 $ 4,609.8 Identifiable assets acquired in business combination: Current assets, including cash of $21.5 million $ 68.0 Property, plant and equipment 1,080.1 Identifiable intangible assets: Customer relationship intangible assets 1,192.4 Contract-based intangible assets 297.5 IDRs (2) 1,459.2 Total identifiable intangible assets 2,949.1 Other assets 227.6 Total assets acquired 4,324.8 Liabilities assumed in business combination: Current liabilities (84.8 ) Long-term debt (223.3 ) Other long-term liabilities (3) (230.0 ) Total liabilities assumed (538.1 ) Noncontrolling interest in Oiltanking (1,397.2 ) Total assets acquired less liabilities assumed and noncontrolling interest 2,389.5 Total consideration given for ownership interests in Oiltanking in Step 1 4,609.8 Goodwill $ 2,220.3 (1) The fair value of the equity-based consideration paid in connection with Step 1 of the Oiltanking acquisition was based on the closing market price of our common units of $39.62 per unit on the acquisition date. (2) The IDRs represented contractual rights to future cash incentive distributions to be paid by Oiltanking. These rights were granted to Oiltanking GP under the terms of Oiltanking's partnership agreement. Oiltanking GP could separate and sell the IDRs independent of its other residual general partner interest in Oiltanking. In February 2015 (following completion of Step 2 of the Oiltanking acquisition), the Oiltanking IDRs were cancelled and the carrying value of this intangible asset was reclassified to goodwill. (3) In connection with Step 1, we entered into the Liquidity Option Agreement with OTA and Marquard & Bahls ("M&B", a German corporation and ultimate parent company of OTA). Other long-term liabilities includes $219.7 million for the Liquidity Option Agreement (see Note 17). (4) From an accounting perspective, Enterprise acquired control of Oiltanking as a result of completing Step 1. The estimated fair value of Oiltanking's common units held by parties other than Enterprise following Step 1 (i.e., the "noncontrolling interest") is based on 28,328,890 common units held by third parties on October 1, 2014 multiplied by the closing unit price for Oiltanking common units of $49.32 per unit on that date.
Unaudited Pro Forma Earnings Information	Since the effective date of the EFS Midstream acquisition was July 1, 2015, our 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 years ended December 31, 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 Year Ended December 31, 2015 2014 Pro forma earnings data: Revenues $ 27,148.5 $ 48,180.4 Costs and expenses 23,937.1 44,583.6 Operating income 3,585.0 3,856.3 Net income 2,594.4 2,896.1 Net income attributable to noncontrolling interests 37.2 46.1 Net income attributable to limited partners 2,557.2 2,850.0 Basic earnings per unit: As reported basic earnings per unit $ 1.28 $ 1.51 Pro forma basic earnings per unit $ 1.30 $ 1.54 Diluted earnings per unit: As reported diluted earnings per unit $ 1.26 $ 1.47 Pro forma diluted earnings per unit $ 1.28 $ 1.50 Since the effective date of Step 1 of the Oiltanking acquisition was October 1, 2014, our 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 year ended December 31, 2014 as if the acquisition had been completed on January 1, 2013. This pro forma information was prepared using historical financial data for Oiltanking 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 year ended December 31, 2014 had we acquired Oiltanking on January 1, 2013. Pro forma earnings data: Revenues $ 48,087.5 Costs and expenses 44,509.0 Operating income 3,838.0 Net income 2,877.5 Net income attributable to noncontrolling interests 75.0 Net income attributable to limited partners 2,802.5 Basic earnings per unit: As reported basic units outstanding 1,848.7 Pro forma basic units outstanding 1,903.5 As reported basic earnings per unit $ 1.51 Pro forma basic earnings per unit $ 1.47 Diluted earnings per unit: As reported diluted units outstanding 1,895.2 Pro forma diluted units outstanding 1,950.0 As reported diluted earnings per unit $ 1.47 Pro forma diluted earnings per unit $ 1.44

Equity-Based Awards (Tables)

Equity-Based Awards (Tables)	12 Months Ended
	Dec. 31, 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 Year Ended December 31, 2015 2014 2013 Equity-classified awards: Restricted common unit awards $ 14.7 $ 42.1 $ 71.5 Phantom unit awards 78.3 45.1 -- Unit option awards -- -- 0.8 Liability-classified awards 0.2 0.3 0.5 Total $ 93.2 $ 87.5 $ 72.8
Phantom Unit Awards	The following table presents phantom unit award activity for the periods indicated: Number of Units Weighted- Average Grant Date Fair Value per Unit Phantom unit awards at December 31, 2013 -- $ -- Granted (2) 3,530,710 $ 33.12 Vested (38,200 ) $ 33.04 Forfeited (150,120 ) $ 33.12 Phantom unit awards at December 31, 2014 3,342,390 $ 33.13 Granted (3) 3,496,140 $ 33.96 Vested (940,415 ) $ 33.14 Forfeited (471,166 ) $ 33.51 Phantom unit awards at December 31, 2015 5,426,949 $ 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 2014 was $117.0 million based on a grant date market price of our common units ranging from $33.04 to $37.59 per unit. An estimated annual forfeiture rate of 3.4% was applied to these awards. (3) The aggregate grant date fair value of phantom unit awards issued during 2015 was $118.7 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.
Supplemental Information Regarding Phantom Unit Awards	The following table presents supplemental information regarding our phantom unit awards and DERs for the periods indicated: For the Year Ended December 31, 2015 2014 2013 Cash payments made in connection with DERs $ 7.7 $ 3.7 $ -- Total intrinsic value of phantom unit awards that vested during period $ 31.2 $ 1.4 $ --
Restricted Common Unit Awards	The following table presents restricted common unit award activity for the periods indicated: Number of Units Weighted- Average Grant Date Fair Value per Unit Restricted common units at December 31, 2012 7,786,972 $ 20.43 Granted (2) 3,549,052 $ 28.61 Vested (3,770,696 ) $ 17.48 Forfeited (344,114 ) $ 23.82 Restricted common units at December 31, 2013 7,221,214 $ 25.83 Vested (2,634,074 ) $ 23.94 Forfeited (357,350 ) $ 26.38 Restricted common units at December 31, 2014 4,229,790 $ 26.96 Vested (2,009,970 ) $ 26.00 Forfeited (259,300 ) $ 27.53 Restricted common units at December 31, 2015 1,960,520 $ 27.88 (1) Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued. (2) The aggregate grant date fair value of restricted common unit awards issued during 2013 was $101.5 million based on a grant date market price of our common units ranging from $28.56 to $31.74 per unit. An estimated annual forfeiture rate of 3.9% was applied to these awards.
Supplemental Information Regarding Restricted Common Unit Awards	The following table presents supplemental information regarding our restricted common unit awards for the periods indicated: For the Year Ended December 31, 2015 2014 2013 Cash distributions paid to restricted common unitholders $ 4.0 $ 7.3 $ 10.6 Total intrinsic value of restricted common unit awards that vested during period $ 67.3 $ 87.1 $ 109.9
Unit Option Activity	The following table presents unit option award activity for the periods indicated: Number of Units Weighted- Average Strike Price (dollars/unit) Unit option awards at December 31, 2012 5,522,280 $ 13.71 Exercised (1,472,280 ) $ 14.98 Unit option awards at December 31, 2013 4,050,000 $ 13.24 Exercised (2,720,000 ) $ 11.83 Forfeited (60,000 ) $ 16.14 Unit option awards at December 31, 2014 1,270,000 $ 16.14 Exercised (1,270,000 ) $ 16.14 Unit option awards at December 31, 2015 -- $ -- (1) All of the unit option awards outstanding at December 31, 2014 vested during 2014 and were exercised during 2015.
Supplemental Information Regarding Unit Options	The following table presents supplemental information regarding our unit option awards during the periods indicated: For the Year Ended December 31, 2015 2014 2013 Total intrinsic value of unit option awards exercised during period $ 21.7 $ 57.5 $ 19.8 Cash received from EPCO in connection with the exercise of unit option awards $ 13.1 $ 33.4 $ 11.5 Unit option award-related cash reimbursements to EPCO $ 21.7 $ 57.5 $ 19.8

Derivative Instruments, Hedgi41

Derivative Instruments, Hedging Activities and Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Instruments, Hedging Activities and Fair Value Measurements [Abstract]
Hedging Instruments Under the FASB's Derivative and Hedging Guidance	The following table summarizes our portfolio of interest rate swaps at December 31, 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 0.82% 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 December 31, 2015 (volume measures as noted): Volume Accounting Derivative Purpose Current Long-Term Treatment Derivatives designated as hedging instruments: Natural gas processing: Forecasted natural gas purchases for plant thermal reduction (Bcf) 9.1 n/a Cash flow hedge Forecasted sales of NGLs (MMBbls) 2.1 n/a Cash flow hedge Natural gas marketing: Forecasted purchases of natural gas for fuel (Bcf) 2.4 n/a Cash flow hedge Natural gas storage inventory management activities (Bcf) 10.7 n/a Fair value hedge NGL marketing: Forecasted purchases of NGLs and related hydrocarbon products (MMBbls) 28.7 0.4 Cash flow hedge Forecasted sales of NGLs and related hydrocarbon products (MMBbls) 42.2 0.1 Cash flow hedge Refined products marketing: Forecasted purchases of refined products (MMBbls) 2.7 n/a Cash flow hedge Forecasted sales of refined products (MMBbls) 0.8 0.1 Cash flow hedge Refined products inventory management activities (MMBbls) 1.3 n/a Fair value hedge Crude oil marketing: Forecasted purchases of crude oil (MMBbls) 15.0 n/a Cash flow hedge Forecasted sales of crude oil (MMBbls) 17.6 n/a Cash flow hedge Crude oil inventory management activities (MMBbls) 0.7 n/a Fair value hedge Derivatives not designated as hedging instruments: Natural gas risk management activities (Bcf) (3,4) 48.2 8.2 Mark-to-market NGL risk management activities (MMBbls) (4) 1.8 n/a Mark-to-market Crude oil risk management activities (MMBbls) (4) 11.8 n/a Mark-to-market (1) Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes. (2) The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is December 2017, January 2017 and March 2018, respectively. (3) Current and long-term volumes include 24.3 Bcf and 2.1 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. (4) 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 December 31, 2015 December 31, 2014 December 31, 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 $ 3.2 Current assets $ -- Other current liabilities $ -- Other current liabilities $ -- Interest rate derivatives Other assets -- Other assets -- Other liabilities 3.7 Other liabilities -- Total interest rate derivatives 3.2 -- 3.7 -- Commodity derivatives Current assets 253.8 Current assets 217.9 Other current liabilities 137.5 Other current liabilities 145.3 Commodity derivatives Other assets 0.2 Other assets -- Other liabilities 1.4 Other liabilities -- Total commodity derivatives 254.0 217.9 138.9 145.3 Total derivatives designated as hedging instruments $ 257.2 $ 217.9 $ 142.6 $ 145.3 Derivatives not designated as hedging instruments Interest rate derivatives Current assets $ -- Current assets $ -- Other current liabilities $ -- Other current liabilities $ -- Commodity derivatives Current assets 1.6 Current assets 8.1 Other current liabilities 3.1 Other current liabilities 0.7 Commodity derivatives Other assets -- Other assets 0.6 Other liabilities 1.0 Other liabilities 1.4 Total commodity derivatives 1.6 8.7 4.1 2.1 Total derivatives not designated as hedging instruments $ 1.6 $ 8.7 $ 4.1 $ 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 Not Offset in the Balance Sheet Gross Amounts of Recognized Assets Gross Amounts Offset in the Balance Sheet Amounts of Assets Presented in the Balance Sheet Financial Instruments Cash Collateral Paid Cash Collateral Received Amounts That Would Have Been Presented On Net Basis (i) (ii) (iii) = (i) – (ii) (iv) (v) = (iii) + (iv) As of December 31, 2015: Interest rate derivatives $ 3.2 $ -- $ 3.2 $ (3.2 ) $ -- $ -- $ -- Commodity derivatives 255.6 -- 255.6 (143.0 ) (40.1 ) (72.2 ) 0.3 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 Not Offset in the Balance Sheet Gross Amounts of Recognized Liabilities Gross Amounts Offset in the Balance Sheet Amounts of Liabilities Presented in the Balance Sheet Financial Instruments Cash Collateral Paid Amounts That Would Have Been Presented On Net Basis (i) (ii) (iii) = (i) – (ii) (iv) (v) = (iii) + (iv) As of December 31, 2015: Interest rate derivatives $ 3.7 $ -- $ 3.7 $ (3.2 ) $ -- $ 0.5 Commodity derivatives 143.0 -- 143.0 (143.0 ) -- -- 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 Statements of Consolidated Operations for the periods indicated: Derivatives in Fair Value Hedging Relationships Location Gain (Loss) Recognized in Income on Derivative For the Year Ended December 31, 2015 2014 2013 Interest rate derivatives Interest expense $ (1.4 ) $ (26.5 ) $ (13.1 ) Commodity derivatives Revenue 19.1 11.9 (0.1 ) Total $ 17.7 $ (14.6 ) $ (13.2 ) Derivatives in Fair Value Hedging Relationships Location Gain (Loss) Recognized in Income on Hedged Item For the Year Ended December 31, 2015 2014 2013 Interest rate derivatives Interest expense $ 1.4 $ 26.4 $ 12.8 Commodity derivatives Revenue 0.2 (11.8 ) (5.7 ) Total $ 1.6 $ 14.6 $ 7.1
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 Statements of Consolidated Operations and 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 Year Ended December 31, 2015 2014 2013 Interest rate derivatives $ -- $ -- $ 6.6 Commodity derivatives – Revenue (1) 217.6 161.3 (47.9 ) Commodity derivatives – Operating costs and expenses (1) (2.7 ) -- 1.0 Total $ 214.9 $ 161.3 $ (40.3 ) (1) The fair value of these derivative instruments will be reclassified to their respective locations on the 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 Year Ended December 31, 2015 2014 2013 Interest rate derivatives Interest expense $ (35.3 ) $ (32.4 ) $ (29.2 ) Commodity derivatives Revenue 231.7 75.0 (22.4 ) Commodity derivatives Operating costs and expenses (3.5 ) 1.7 0.3 Total $ 192.9 $ 44.3 $ (51.3 )
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 Year Ended December 31, 2015 2014 2013 Commodity derivatives Revenue $ 4.7 $ (0.3 ) $ 0.2 Commodity derivatives Operating costs and expenses 0.1 -- -- Total $ 4.8 $ (0.3 ) $ 0.2
Gain/(Loss) Recognized in Income on Derivative	The following table presents the effect of our derivative instruments not designated as hedging instruments on our Statements of Consolidated Operations for the periods indicated: Derivatives Not Designated as Hedging Instruments Location Gain (Loss) Recognized in Income on Derivative For the Year Ended December 31, 2015 2014 2013 Interest rate derivatives Interest expense $ -- $ (0.1 ) $ (0.7 ) Commodity derivatives Revenue 1.0 (23.0 ) 7.3 Commodity derivatives Operating costs and expense 0.1 -- -- Total $ 1.1 $ (23.1 ) $ 6.6
Fair Value Measurements of Financial Assets and Liabilities Measured on a Recurring Basis	The following tables set forth, by level within the Level 1, 2 and 3 fair value hierarchy (see Note 2), 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. December 31, 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 $ -- $ 3.2 $ -- $ 3.2 Commodity derivatives 109.5 145.2 0.9 255.6 Total $ 109.5 $ 148.4 $ 0.9 $ 258.8 Financial liabilities: Liquidity Option Agreement $ -- $ -- $ 245.1 $ 245.1 Interest rate derivatives -- 3.7 -- 3.7 Commodity derivatives 31.3 109.2 2.5 143.0 Total $ 31.3 $ 112.9 $ 247.6 $ 391.8 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 Year Ended December 31, Location 2015 2014 Financial asset (liability) balance, net, January 1 $ (219.3 ) $ 3.2 Total gains (losses) included in: Net income (1) Revenue (0.9 ) 0.9 Net income Other expense, net (25.4 ) -- Other comprehensive income (loss) Commodity derivative instruments – changes in fair value of cash flow hedges (19.2 ) (2.6 ) Settlements 0.1 (3.4 ) Acquisition of Liquidity Option Agreement (see Note 17) -- (219.7 ) Transfers out of Level 3 (2) 18.0 2.3 Financial liability balance, net, December 31 $ (246.7 ) $ (219.3 ) (1) There were $0.9 million and $2.6 million of unrealized losses included in these amounts for the years ended December 31, 2015 and 2014, respectively. (2) Transfers out of Level 3 into Level 2 were due to shorter remaining transaction maturities falling inside of the Level 2 range at December 31, 2015 and 2014.
Fair Value Measurements, Valuation Techniques	The following Fair Value At December 31, 2015 Financial Assets Financial Liabilities Valuation Techniques Unobservable Input Range Commodity derivatives – Crude oil $ 0.9 $ 1.2 Discounted cash flow Forward commodity prices $35.63-$43.84/barrel Commodity derivatives – Propane -- 1.3 Discounted cash flow Forward commodity prices $0.42-$0.44/gallon Total $ 0.9 $ 2.5 Fair Value At December 31, 2014 Financial Assets Financial Liabilities Valuation Techniques Unobservable Input Range Commodity derivatives – Crude oil $ 1.0 $ 0.4 Discounted cash flow Forward commodity prices $49.26-$53.27/barrel Commodity derivatives – Natural gas -- 0.2 Discounted cash flow Forward commodity prices $3.05-$4.09/MMBtu Total $ 1.0 $ 0.6
Noncash Impairment Charges by Segment	We measure certain assets, primarily long-lived assets and equity method investments, at fair value on a nonrecurring basis. These assets are recognized at fair value when they are deemed to be other-than-temporarily impaired. The following table summarizes our non-cash impairment charges by segment during each of the periods indicated: For the Year Ended December 31, 2015 2014 2013 NGL Pipelines & Services $ 20.8 $ 16.2 $ 30.6 Crude Oil Pipelines & Services 33.5 2.9 30.1 Natural Gas Pipelines & Services 21.6 0.7 -- Petrochemical & Refined Products Services 28.2 9.1 18.7 Offshore Pipelines & Services 58.5 5.1 18.0 Total $ 162.6 $ 34.0 $ 97.4
Nonrecurring Fair Value Measurements	Our non-cash asset impairment charges for the year ended December 31, 2015 are a component of operating costs and expenses and primarily reflect the $54.8 million charge we recorded in connection with the sale of our Offshore Business (see Note 5) and the abandonment of certain natural gas and crude oil pipeline assets in Texas. The following table presents categories of long-lived assets, primarily property, plant and equipment, that were subject to non-recurring fair value measurements during the year ended December 31, 2015: Fair Value Measurements at the End of the Reporting Period Using Carrying Value at December 31, 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 $ 81.4 Long-lived assets held for sale 18.0 -- -- 18.0 14.2 Long-lived assets disposed of by sale (1) -- -- -- -- 67.0 Total $ 162.6 (1) Includes a $54.8 million charge recorded in connection with the sale of our Offshore Business. Our non-cash asset impairment charges for the year ended December 31, 2014 are a component of operating costs and expenses and primarily relate to the abandonment of certain natural gas processing equipment in Louisiana, natural gas pipeline segments in the Gulf of Mexico, refined products terminal and pipeline assets in Arkansas, and NGL storage caverns in Oklahoma and Texas. The following table presents categories of long-lived assets, primarily property, plant and equipment, that were subject to non-recurring fair value measurements during the year ended December 31, 2014: Fair Value Measurements at the End of the Reporting Period Using Carrying Value at December 31, 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 $ -- $ -- $ -- $ -- $ 26.7 Long-lived assets held for sale 1.5 -- -- 1.5 3.6 Long-lived assets disposed of by sale -- -- -- -- 3.7 Total $ 34.0 Our non-cash asset impairment charges for the year ended December 31, 2013 primarily relate to the abandonment of certain crude oil and natural gas pipeline segments in Texas, Oklahoma and the Gulf of Mexico, certain refined products terminal assets in Texas, an NGL storage cavern in Arizona and an NGL fractionator and storage cavern facility in Ohio. These impairment charges totaled $92.6 million and are a component of operating costs and expenses. The remaining charge, or $4.8 million, relates to the impairment of an equity method investment and was presented as a component of equity in income of unconsolidated affiliates. The following table presents categories of long-lived assets that were subject to non-recurring fair value measurements during the year ended December 31, 2013: Fair Value Measurements at the End of the Reporting Period Using Carrying Value at December 31, 2013 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 $ -- $ -- $ -- $ -- $ 79.4 Long-lived assets held and used 44.6 -- -- 44.6 9.0 Long-lived assets held for sale 0.6 -- -- 0.6 3.4 Long-lived assets disposed of by sale -- -- -- -- 5.6 Total $ 97.4

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2015
Related Party Transaction [Line Items]
Related Party Transactions, Income Statement Effect	The following table summarizes our related party transactions for the periods indicated: For the Year Ended December 31, 2015 2014 2013 Revenues – related parties: Unconsolidated affiliates $ 72.3 $ 71.5 $ 65.9 Costs and expenses – related parties: EPCO and its privately held affiliates $ 949.3 $ 939.9 $ 892.2 Unconsolidated affiliates 245.3 183.0 160.0 Total $ 1,194.6 $ 1,122.9 $ 1,052.2
Related Party Transactions, Balance Sheet Effect	The following table summarizes our related party accounts receivable and accounts payable balances at the dates indicated: December 31, 2015 2014 Accounts receivable - related parties: Unconsolidated affiliates $ 1.2 $ 2.8 Accounts payable - related parties: EPCO and its privately held affiliates $ 75.6 $ 98.1 Unconsolidated affiliates 8.5 20.8 Total $ 84.1 $ 118.9
Schedule of Related Party Transactions	At December 31, 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 677,159,667 33.6% The following table presents our related party costs and expenses attributable to the ASA with EPCO for the periods indicated: For the Year Ended December 31, 2015 2014 2013 Operating costs and expenses $ 826.4 $ 801.6 $ 770.6 General and administrative expenses 105.2 121.7 105.2 Total costs and expenses $ 931.6 $ 923.3 $ 875.8

Provision for Income Taxes (Tab

Provision for Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Provision for Income Taxes [Abstract]
Federal and State Income Tax Provision	Our federal, state and foreign income tax provision (benefit) is summarized below: For the Year Ended December 31, 2015 2014 2013 Current: Federal $ 0.9 $ 2.2 $ (0.5 ) State 15.5 13.4 19.3 Foreign 1.7 1.4 0.8 Total current 18.1 17.0 19.6 Deferred: Federal (1.4 ) 2.2 (0.5 ) State (19.2 ) 3.5 38.9 Foreign -- 0.4 (0.5 ) Total deferred (20.6 ) 6.1 37.9 Total provision for (benefit from) income taxes $ (2.5 ) $ 23.1 $ 57.5
Reconciliation of Provision for Income Taxes	A reconciliation of the provision for (benefit from) income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows: For the Year Ended December 31, 2015 2014 2013 Pre-Tax Net Book Income ("NBI") $ 2,555.9 $ 2,856.6 $ 2,664.6 Texas Margin Tax (1) $ (3.7 ) $ 17.5 $ 58.3 State income taxes (net of federal benefit) 0.7 0.2 (0.1 ) Federal income taxes computed by applying the federal statutory rate to NBI of corporate entities 1.1 1.5 (1.4 ) Expiration of tax net operating loss -- -- 0.1 Other permanent differences (0.6 ) 3.9 0.6 Provision for (benefit from) income taxes $ (2.5 ) $ 23.1 $ 57.5 Effective income tax rate (0.1)% 0.8% 2.2% (1) Although the Texas Margin Tax is not considered a state income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers our Texas-sourced revenues and expenses. During 2015, certain legislative changes were enacted to the Texas Margin Tax, which reduced the tax rate for business entities that operate within the state.
Components of Deferred Tax Assets and Liabilities	The following table presents the significant components of deferred tax assets and deferred tax liabilities at the dates indicated: December 31, 2015 2014 Deferred tax assets: Net operating loss carryovers (1) $ 0.2 $ 0.3 Accruals 1.6 1.8 Total deferred tax assets 1.8 2.1 Less: Deferred tax liabilities: Property, plant and equipment 44.9 64.4 Equity investment in partnerships 2.7 4.1 Total deferred tax liabilities 47.6 68.5 Total net deferred tax liabilities $ 45.8 $ 66.4 Current portion of total net deferred tax assets $ 0.3 $ 0.2 Long-term portion of total net deferred tax liabilities $ 46.1 $ 66.6 (1) These losses expire in various years between 2016 and 2033 and are subject to limitations on their utilization.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies [Abstract]
Summary of Contractual Obligations	The following table summarizes our various contractual obligations at December 31, 2015. A description of each type of contractual obligation follows: Payment or Settlement due by Period Contractual Obligations Total 2016 2017 2018 2019 2020 Thereafter Scheduled maturities of debt obligations $ 22,738.5 $ 1,864.1 $ 800.0 $ 1,100.0 $ 1,500.0 $ 1,500.0 $ 15,974.4 Estimated cash interest payments $ 21,734.1 $ 1,053.0 $ 1,036.1 $ 975.6 $ 917.5 $ 859.7 $ 16,892.2 Operating lease obligations $ 494.0 $ 64.2 $ 58.4 $ 50.3 $ 44.7 $ 41.0 $ 235.4 Purchase obligations: Product purchase commitments: Estimated payment obligations: Natural gas $ 1,160.8 $ 451.3 $ 215.6 $ 215.6 $ 143.8 $ 73.5 $ 61.0 NGLs $ 376.9 $ 319.3 $ 21.8 $ 23.9 $ 11.9 $ -- $ -- Crude oil $ 441.5 $ 389.4 $ 17.9 $ 17.9 $ 16.3 $ -- $ -- Petrochemicals & refined products $ 1,921.4 $ 1,868.6 $ 52.8 $ -- $ -- $ -- $ -- Other $ 33.2 $ 8.7 $ 6.9 $ 4.1 $ 4.1 $ 2.7 $ 6.7 Underlying major volume commitments: Natural gas (in TBtus) 647 243 128 128 81 37 30 NGLs (in MMBbls) 39 30 3 4 2 -- -- Crude oil (in MMBbls) 14 11 1 1 1 -- -- Petrochemicals & refined products (in MMBbls) 146 126 20 -- -- -- -- Service payment commitments $ 685.9 $ 184.5 $ 160.1 $ 91.8 $ 71.1 $ 43.7 $ 134.7 Capital expenditure commitments $ 113.9 $ 113.9 $ -- $ -- $ -- $ -- $ --
Schedule of Other Liabilities	The following table summarizes the components of "Other long-term liabilities" as presented on Consolidated Balance Sheets at the dates indicated: December 31, 2015 2014 Noncurrent portion of AROs (see Note 5) $ 52.9 $ 83.2 Deferred revenues – non-current portion (see Note 3) 78.3 73.0 Liquidity Option Agreement (see Note 12) 245.1 219.7 Centennial guarantees 6.1 7.0 Other 29.1 28.2 Total $ 411.5 $ 411.1

Supplemental Cash Flow Inform45

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Information [Abstract]
Net Effect of Changes in Operating Assets and Liabilities	The following table provides information regarding the net effect of changes in our operating accounts and cash payments for interest and income taxes for the periods indicated: For the Year Ended December 31, 2015 2014 2013 Decrease (increase) in: Accounts receivable – trade $ 1,279.3 $ 1,685.4 $ (1,136.2 ) Accounts receivable – related parties 1.3 3.8 (3.6 ) Inventories (72.7 ) (105.6 ) 38.6 Prepaid and other current assets (59.1 ) (74.6 ) (6.3 ) Other assets (5.8 ) 18.7 2.4 Increase (decrease) in: Accounts payable – trade (52.9 ) (141.0 ) (10.1 ) Accounts payable – related parties (34.8 ) (31.6 ) 23.6 Accrued product payables (1,342.4 ) (1,647.8 ) 1,043.8 Accrued interest 16.5 31.3 3.5 Other current liabilities (67.1 ) 141.3 (35.1 ) Other liabilities 14.4 11.9 (18.2 ) Net effect of changes in operating accounts $ (323.3 ) $ (108.2 ) $ (97.6 ) Cash payments for interest, net of $149.1, $77.9 and $133.0 capitalized in 2015, 2014 and 2013, respectively $ 911.6 $ 832.1 $ 781.5 Cash payments for federal and state income taxes $ 17.5 $ 16.1 $ 35.0
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 Year Ended December 31, 2015 2014 2013 Sale of Offshore Business (see Note 5) $ 1,527.7 $ -- $ -- Insurance recoveries attributable to West Storage claims (see Note 18) -- 95.0 15.0 Cash proceeds from other asset sales 80.9 50.3 265.6 Total $ 1,608.6 $ 145.3 $ 280.6 The following table presents net gains (losses) attributable to asset sales and insurance recoveries for the periods indicated: For the Year Ended December 31, 2015 2014 2013 Sale of Offshore Business $ (12.3 ) $ -- $ -- Gains attributable to West Storage insurance recoveries (see Note 18) -- 95.0 15.0 Net gains (losses) attributable to other asset sales (3.3 ) 7.1 68.3 Total $ (15.6 ) $ 102.1 $ 83.3

Quarterly Financial Informati46

Quarterly Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information (Unaudited) [Abstract]
Quarterly Financial Information (Unaudited)	The following table presents selected quarterly financial data for the periods indicated: First Quarter Second Quarter Third Quarter Fourth Quarter For the Year Ended December 31, 2015: Revenues $ 7,472.5 $ 7,092.5 $ 6,307.9 $ 6,155.0 Operating income 896.0 800.3 909.4 934.5 Net income 650.6 556.6 657.7 693.5 Net income attributable to limited partners 636.1 551.0 649.3 684.8 Earnings per unit: Basic $ 0.33 $ 0.28 $ 0.33 $ 0.34 Diluted $ 0.32 $ 0.28 $ 0.32 $ 0.34 For the Year Ended December 31, 2014: Revenues $ 12,909.9 $ 12,520.8 $ 12,330.2 $ 10,190.3 Operating income 1,032.7 884.3 937.7 921.0 Net income 806.7 646.5 699.2 681.1 Net income attributable to limited partners 798.8 637.7 691.1 659.8 Earnings per unit: Basic $ 0.44 $ 0.35 $ 0.38 $ 0.35 Diluted $ 0.43 $ 0.34 $ 0.37 $ 0.34

Condensed Consolidating Finan47

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2015
Condensed Consolidating Financial Information [Abstract]
Condensed Consolidating Balance Sheet	Enterprise Products Partners L.P. Condensed Consolidating Balance Sheet December 31, 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 $ 14.4 $ 71.1 $ (50.6 ) $ 34.9 $ -- $ -- $ 34.9 Accounts receivable – trade, net 811.3 1,755.8 2.8 2,569.9 -- -- 2,569.9 Accounts receivable – related parties 59.0 795.4 (853.0 ) 1.4 -- (0.2 ) 1.2 Inventories 786.9 251.4 (0.2 ) 1,038.1 -- -- 1,038.1 Derivative assets 150.4 108.2 -- 258.6 -- -- 258.6 Prepaid and other current assets 168.3 249.1 (7.1 ) 410.3 -- -- 410.3 Total current assets 1,990.3 3,231.0 (908.1 ) 4,313.2 -- (0.2 ) 4,313.0 Property, plant and equipment, net 3,859.8 28,173.5 1.4 32,034.7 -- -- 32,034.7 Investments in unconsolidated affiliates 38,655.0 4,067.3 (40,093.8 ) 2,628.5 20,540.2 (20,540.2 ) 2,628.5 Intangible assets, net 721.2 3,330.7 (14.7 ) 4,037.2 -- -- 4,037.2 Goodwill 459.5 5,285.7 -- 5,745.2 -- -- 5,745.2 Other assets 280.2 47.9 (135.2 ) 192.9 0.5 -- 193.4 Total assets $ 45,966.0 $ 44,136.1 $ (41,150.4 ) $ 48,951.7 $ 20,540.7 $ (20,540.4 ) $ 48,952.0 LIABILITIES AND EQUITY Current liabilities: Current maturities of debt $ 1,863.8 $ 0.1 $ -- $ 1,863.9 $ -- $ -- $ 1,863.9 Accounts payable – trade 375.3 535.1 (50.6 ) 859.8 0.3 -- 860.1 Accounts payable – related parties 885.3 62.3 (863.5 ) 84.1 0.2 (0.2 ) 84.1 Accrued product payables 997.7 1,489.3 (2.6 ) 2,484.4 -- -- 2,484.4 Accrued liability related to EFS Midstream acquisition -- 993.2 -- 993.2 -- -- 993.2 Accrued interest 352.0 0.1 -- 352.1 -- -- 352.1 Other current liabilities 178.7 357.1 (7.0 ) 528.8 -- -- 528.8 Total current liabilities 4,652.8 3,437.2 (923.7 ) 7,166.3 0.5 (0.2 ) 7,166.6 Long-term debt 20,811.4 15.3 -- 20,826.7 -- -- 20,826.7 Deferred tax liabilities 3.4 40.8 (0.8 ) 43.4 -- 2.7 46.1 Other long-term liabilities 14.5 286.9 (135.0 ) 166.4 245.1 -- 411.5 Commitments and contingencies Equity: Partners' and other owners' equity 20,483.9 40,297.2 (40,266.8 ) 20,514.3 20,295.1 (20,514.3 ) 20,295.1 Noncontrolling interests -- 58.7 175.9 234.6 -- (28.6 ) 206.0 Total equity 20,483.9 40,355.9 (40,090.9 ) 20,748.9 20,295.1 (20,542.9 ) 20,501.1 Total liabilities and equity $ 45,966.0 $ 44,136.1 $ (41,150.4 ) $ 48,951.7 $ 20,540.7 $ (20,540.4 ) $ 48,952.0 Enterprise Products Partners L.P. 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. Condensed Consolidating Statement of Operations For the Year Ended December 31, 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 $ 20,104.8 $ 19,087.0 $ (12,163.9 ) $ 27,027.9 $ -- $ -- $ 27,027.9 Costs and expenses: Operating costs and expenses 19,283.7 16,549.3 (12,164.3 ) 23,668.7 -- -- 23,668.7 General and administrative costs 38.2 152.3 -- 190.5 2.1 -- 192.6 Total costs and expenses 19,321.9 16,701.6 (12,164.3 ) 23,859.2 2.1 -- 23,861.3 Equity in income of unconsolidated affiliates 2,718.4 417.5 (2,762.3 ) 373.6 2,548.7 (2,548.7 ) 373.6 Operating income 3,501.3 2,802.9 (2,761.9 ) 3,542.3 2,546.6 (2,548.7 ) 3,540.2 Other income (expense): Interest expense (952.9 ) (12.0 ) 3.1 (961.8 ) -- -- (961.8 ) Other, net 5.2 0.8 (3.1 ) 2.9 (25.4 ) -- (22.5 ) Total other expense, net (947.7 ) (11.2 ) -- (958.9 ) (25.4 ) -- (984.3 ) Income before income taxes 2,553.6 2,791.7 (2,761.9 ) 2,583.4 2,521.2 (2,548.7 ) 2,555.9 Benefit from (provision for) income taxes (8.7 ) 12.7 -- 4.0 -- (1.5 ) 2.5 Net income 2,544.9 2,804.4 (2,761.9 ) 2,587.4 2,521.2 (2,550.2 ) 2,558.4 Net loss (income) attributable to noncontrolling interests -- 0.9 (42.9 ) (42.0 ) -- 4.8 (37.2 ) Net income attributable to entity $ 2,544.9 $ 2,805.3 $ (2,804.8 ) $ 2,545.4 $ 2,521.2 $ (2,545.4 ) $ 2,521.2 Enterprise Products Partners L.P. Condensed Consolidating Statement of Operations For the Year Ended 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 Revenues $ 32,468.5 $ 32,488.2 $ (17,005.5 ) $ 47,951.2 $ -- $ -- $ 47,951.2 Costs and expenses: Operating costs and expenses 31,579.2 29,647.6 (17,006.3 ) 44,220.5 -- -- 44,220.5 General and administrative costs 39.1 173.2 -- 212.3 2.2 -- 214.5 Total costs and expenses 31,618.3 29,820.8 (17,006.3 ) 44,432.8 2.2 -- 44,435.0 Equity in income of unconsolidated affiliates 2,865.2 354.3 (2,960.0 ) 259.5 2,789.6 (2,789.6 ) 259.5 Operating income 3,715.4 3,021.7 (2,959.2 ) 3,777.9 2,787.4 (2,789.6 ) 3,775.7 Other income (expense): Interest expense (921.3 ) (2.5 ) 2.8 (921.0 ) -- -- (921.0 ) Other, net 3.4 1.3 (2.8 ) 1.9 -- -- 1.9 Total other expense, net (917.9 ) (1.2 ) -- (919.1 ) -- -- (919.1 ) Income before income taxes 2,797.5 3,020.5 (2,959.2 ) 2,858.8 2,787.4 (2,789.6 ) 2,856.6 Provision for income taxes (11.5 ) (9.8 ) 0.2 (21.1 ) -- (2.0 ) (23.1 ) Net income 2,786.0 3,010.7 (2,959.0 ) 2,837.7 2,787.4 (2,791.6 ) 2,833.5 Net loss (income) attributable to noncontrolling interests -- 0.4 (51.5 ) (51.1 ) -- 5.0 (46.1 ) Net income attributable to entity $ 2,786.0 $ 3,011.1 $ (3,010.5 ) $ 2,786.6 $ 2,787.4 $ (2,786.6 ) $ 2,787.4 Enterprise Products Partners L.P. Condensed Consolidating Statement of Operations For the Year Ended December 31, 2013 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 $ 30,007.4 $ 31,641.3 $ (13,921.7 ) $ 47,727.0 $ -- $ -- $ 47,727.0 Costs and expenses: Operating costs and expenses 29,176.7 28,983.7 (13,921.7 ) 44,238.7 -- -- 44,238.7 General and administrative costs 29.1 157.0 -- 186.1 2.2 -- 188.3 Total costs and expenses 29,205.8 29,140.7 (13,921.7 ) 44,424.8 2.2 -- 44,427.0 Equity in income of unconsolidated affiliates 2,609.0 204.8 (2,646.5 ) 167.3 2,599.1 (2,599.1 ) 167.3 Operating income 3,410.6 2,705.4 (2,646.5 ) 3,469.5 2,596.9 (2,599.1 ) 3,467.3 Other income (expense): Interest expense (800.8 ) (1.7 ) -- (802.5 ) -- -- (802.5 ) Other, net 0.3 (0.5 ) -- (0.2 ) -- -- (0.2 ) Total other expense, net (800.5 ) (2.2 ) -- (802.7 ) -- -- (802.7 ) Income before income taxes 2,610.1 2,703.2 (2,646.5 ) 2,666.8 2,596.9 (2,599.1 ) 2,664.6 Provision for income taxes (13.9 ) (42.6 ) -- (56.5 ) -- (1.0 ) (57.5 ) Net income 2,596.2 2,660.6 (2,646.5 ) 2,610.3 2,596.9 (2,600.1 ) 2,607.1 Net loss (income) attributable to noncontrolling interests -- (1.2 ) (12.9 ) (14.1 ) -- 3.9 (10.2 ) Net income attributable to entity $ 2,596.2 $ 2,659.4 $ (2,659.4 ) $ 2,596.2 $ 2,596.9 $ (2,596.2 ) $ 2,596.9
Condensed Consolidating Statement of Comprehensive Income	Enterprise Products Partners L.P. Condensed Consolidating Statement of Comprehensive Income For the Year Ended December 31, 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 $ 2,578.6 $ 2,793.1 $ (2,761.9 ) $ 2,609.8 $ 2,543.6 $ (2,572.6 ) $ 2,580.8 Comprehensive loss (income) attributable to noncontrolling interests -- 0.9 (42.9 ) (42.0 ) -- 4.8 (37.2 ) Comprehensive income attributable to entity $ 2,578.6 $ 2,794.0 $ (2,804.8 ) $ 2,567.8 $ 2,543.6 $ (2,567.8 ) $ 2,543.6 Enterprise Products Partners L.P. Condensed Consolidating Statement of Comprehensive Income For the Year Ended 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 Comprehensive income $ 2,856.4 $ 3,057.6 $ (2,958.9 ) $ 2,955.1 $ 2,904.8 $ (2,909.0 ) $ 2,950.9 Comprehensive loss (income) attributable to noncontrolling interests -- 0.4 (51.5 ) (51.1 ) -- 5.0 (46.1 ) Comprehensive income attributable to entity $ 2,856.4 $ 3,058.0 $ (3,010.4 ) $ 2,904.0 $ 2,904.8 $ (2,904.0 ) $ 2,904.8 Enterprise Products Partners L.P. Condensed Consolidating Statement of Comprehensive Income For the Year Ended December 31, 2013 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 $ 2,616.5 $ 2,651.6 $ (2,646.5 ) $ 2,621.6 $ 2,608.3 $ (2,611.4 ) $ 2,618.5 Comprehensive income attributable to noncontrolling interests -- (1.2 ) (12.9 ) (14.1 ) -- 3.9 (10.2 ) Comprehensive income attributable to entity $ 2,616.5 $ 2,650.4 $ (2,659.4 ) $ 2,607.5 $ 2,608.3 $ (2,607.5 ) $ 2,608.3
Condensed Consolidating Statement of Cash Flows	Enterprise Products Partners L.P. Condensed Consolidating Statement of Cash Flows For the Year Ended December 31, 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 $ 2,544.9 $ 2,804.4 $ (2,761.9 ) $ 2,587.4 $ 2,521.2 $ (2,550.2 ) $ 2,558.4 Reconciliation of net income to net cash flows provided by operating activities: Depreciation, amortization and accretion 144.9 1,371.5 (0.4 ) 1,516.0 -- -- 1,516.0 Equity in income of unconsolidated affiliates (2,718.4 ) (417.5 ) 2,762.3 (373.6 ) (2,548.7 ) 2,548.7 (373.6 ) Distributions received from unconsolidated affiliates 1,989.6 307.7 (1,835.2 ) 462.1 3,000.2 (3,000.2 ) 462.1 Net effect of changes in operating accounts and other operating activities 882.8 (1,031.0 ) (35.9 ) (184.1 ) 22.1 1.5 (160.5 ) Net cash flows provided by operating activities 2,843.8 3,035.1 (1,871.1 ) 4,007.8 2,994.8 (3,000.2 ) 4,002.4 Investing activities: Capital expenditures, net of contributions in aid of construction costs (1,180.0 ) (2,631.6 ) -- (3,811.6 ) -- -- (3,811.6 ) Cash used for business combinations, net of cash received (1,069.9 ) 13.4 -- (1,056.5 ) -- -- (1,056.5 ) Proceeds from asset sales and insurance recoveries 1,531.3 77.3 -- 1,608.6 -- -- 1,608.6 Other investing activities (1,513.4 ) (1,248.2 ) 2,579.3 (182.3 ) (1,179.8 ) 1,179.8 (182.3 ) Cash used in investing activities (2,232.0 ) (3,789.1 ) 2,579.3 (3,441.8 ) (1,179.8 ) 1,179.8 (3,441.8 ) Financing activities: Borrowings under debt agreements 21,081.1 133.9 (133.9 ) 21,081.1 -- -- 21,081.1 Repayments of debt (19,867.2 ) -- -- (19,867.2 ) -- -- (19,867.2 ) Cash distributions paid to partners (3,000.2 ) (1,882.4 ) 1,882.4 (3,000.2 ) (2,943.7 ) 3,000.2 (2,943.7 ) Cash payments made in connection with DERs -- -- -- -- (7.7 ) -- (7.7 ) Cash distributions paid to noncontrolling interests -- (0.8 ) (47.2 ) (48.0 ) -- -- (48.0 ) Cash contributions from noncontrolling interests -- 54.4 (0.4 ) 54.0 -- -- 54.0 Net cash proceeds from issuance of common units -- -- -- -- 1,188.6 -- 1,188.6 Cash contributions from owners 1,179.8 2,445.0 (2,445.0 ) 1,179.8 -- (1,179.8 ) -- Other financing activities (24.0 ) 3.1 -- (20.9 ) (52.2 ) -- (73.1 ) Cash provided by (used in) financing activities (630.5 ) 753.2 (744.1 ) (621.4 ) (1,815.0 ) 1,820.4 (616.0 ) Net change in cash and cash equivalents (18.7 ) (0.8 ) (35.9 ) (55.4 ) -- -- (55.4 ) Cash and cash equivalents, January 1 18.7 70.4 (14.7 ) 74.4 -- -- 74.4 Cash and cash equivalents, December 31 $ -- $ 69.6 $ (50.6 ) $ 19.0 $ -- $ -- $ 19.0 Enterprise Products Partners L.P. Condensed Consolidating Statement of Cash Flows For the Year Ended 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 Operating activities: Net income $ 2,786.0 $ 3,010.7 $ (2,959.0 ) $ 2,837.7 $ 2,787.4 $ (2,791.6 ) $ 2,833.5 Reconciliation of net income to net cash flows provided by operating activities: Depreciation, amortization and accretion 153.0 1,208.0 (0.5 ) 1,360.5 -- -- 1,360.5 Equity in income of unconsolidated affiliates (2,865.2 ) (354.3 ) 2,960.0 (259.5 ) (2,789.6 ) 2,789.6 (259.5 ) Distributions received from unconsolidated affiliates 4,539.9 327.1 (4,491.9 ) 375.1 2,702.9 (2,702.9 ) 375.1 Net effect of changes in operating accounts and other operating activities (627.0 ) 479.4 5.7 (141.9 ) (7.5 ) 2.0 (147.4 ) Net cash flows provided by operating activities 3,986.7 4,670.9 (4,485.7 ) 4,171.9 2,693.2 (2,702.9 ) 4,162.2 Investing activities: Capital expenditures, net of contributions in aid of construction costs (647.9 ) (2,216.1 ) -- (2,864.0 ) -- -- (2,864.0 ) Cash used for business combinations, net of cash received (2,437.5 ) 20.7 -- (2,416.8 ) -- -- (2,416.8 ) Proceeds from asset sales and insurance recoveries 4.3 141.0 -- 145.3 -- -- 145.3 Other investing activities (2,603.4 ) (660.0 ) 2,601.0 (662.4 ) (384.6 ) 384.6 (662.4 ) Cash used in investing activities (5,684.5 ) (2,714.4 ) 2,601.0 (5,797.9 ) (384.6 ) 384.6 (5,797.9 ) Financing activities: Borrowings under debt agreements 18,361.1 -- -- 18,361.1 -- -- 18,361.1 Repayments of debt (14,341.1 ) -- -- (14,341.1 ) -- -- (14,341.1 ) Cash distributions paid to partners (2,702.9 ) (4,537.8 ) 4,537.8 (2,702.9 ) (2,638.1 ) 2,702.9 (2,638.1 ) Cash payments made in connection with DERs -- -- -- -- (3.7 ) -- (3.7 ) Cash distributions paid to noncontrolling interests -- (2.7 ) (45.9 ) (48.6 ) -- -- (48.6 ) Cash contributions from noncontrolling interests -- -- 4.0 4.0 -- -- 4.0 Net cash proceeds from issuance of common units -- -- -- -- 388.8 -- 388.8 Cash contributions from owners 384.6 2,604.9 (2,604.9 ) 384.6 -- (384.6 ) -- Other financing activities (13.6 ) -- -- (13.6 ) (55.6 ) -- (69.2 ) Cash provided by (used in) financing activities 1,688.1 (1,935.6 ) 1,891.0 1,643.5 (2,308.6 ) 2,318.3 1,653.2 Net change in cash and cash equivalents (9.7 ) 20.9 6.3 17.5 -- -- 17.5 Cash and cash equivalents, January 1 28.4 49.5 (21.0 ) 56.9 -- -- 56.9 Cash and cash equivalents, December 31 $ 18.7 $ 70.4 $ (14.7 ) $ 74.4 $ -- $ -- $ 74.4 Enterprise Products Partners L.P. Condensed Consolidating Statement of Cash Flows For the Year Ended December 31, 2013 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 $ 2,596.2 $ 2,660.6 $ (2,646.5 ) $ 2,610.3 $ 2,596.9 $ (2,600.1 ) $ 2,607.1 Reconciliation of net income to net cash flows provided by operating activities: Depreciation, amortization and accretion 143.5 1,072.8 1.3 1,217.6 -- -- 1,217.6 Equity in income of unconsolidated affiliates (2,609.0 ) (204.8 ) 2,646.5 (167.3 ) (2,599.1 ) 2,599.1 (167.3 ) Distributions received from unconsolidated affiliates 4,523.2 233.7 (4,505.3 ) 251.6 2,454.4 (2,454.4 ) 251.6 Net effect of changes in operating accounts and other operating activities (1,351.0 ) 1,323.4 (10.1 ) (37.7 ) (7.8 ) 2.0 (43.5 ) Net cash flows provided by operating activities 3,302.9 5,085.7 (4,514.1 ) 3,874.5 2,444.4 (2,453.4 ) 3,865.5 Investing activities: Capital expenditures, net of contributions in aid of construction costs (517.8 ) (2,864.4 ) -- (3,382.2 ) -- -- (3,382.2 ) Proceeds from asset sales and insurance recoveries 59.6 221.0 -- 280.6 -- -- 280.6 Other investing activities (3,163.6 ) (769.5 ) 2,777.2 (1,155.9 ) (1,791.1 ) 1,791.1 (1,155.9 ) Cash used in investing activities (3,621.8 ) (3,412.9 ) 2,777.2 (4,257.5 ) (1,791.1 ) 1,791.1 (4,257.5 ) Financing activities: Borrowings under debt agreements 13,852.8 -- -- 13,852.8 -- -- 13,852.8 Repayments of debt (12,650.8 ) (29.8 ) -- (12,680.6 ) -- -- (12,680.6 ) Cash distributions paid to partners (2,453.4 ) (4,514.1 ) 4,514.1 (2,453.4 ) (2,400.4 ) 2,453.5 (2,400.3 ) Cash distributions paid to noncontrolling interests -- -- (8.9 ) (8.9 ) -- -- (8.9 ) Cash contributions from noncontrolling interests -- -- 115.4 115.4 -- -- 115.4 Net cash proceeds from issuance of common units -- -- -- -- 1,792.0 -- 1,792.0 Cash contributions from owners 1,791.2 2,892.6 (2,892.6 ) 1,791.2 -- (1,791.2 ) -- Other financing activities (192.5 ) -- -- (192.5 ) (45.1 ) -- (237.6 ) Cash provided by (used in) financing activities 347.3 (1,651.3 ) 1,728.0 424.0 (653.5 ) 662.3 432.8 Net change in cash and cash equivalents 28.4 21.5 (8.9 ) 41.0 (0.2 ) -- 40.8 Cash and cash equivalents, January 1 -- 28.0 (12.1 ) 15.9 0.2 -- 16.1 Cash and cash equivalents, December 31 $ 28.4 $ 49.5 $ (21.0 ) $ 56.9 $ -- $ -- $ 56.9

Partnership Operations, Organ48

Partnership Operations, Organization and Basis of Presentation (Details) bbl in Millions, ft³ in Billions	12 Months Ended
	Dec. 31, 2015Segmentmibblft³	Dec. 31, 2014
Partnership Operations, Organization and Basis of Presentation [Abstract]
Number of miles of pipelines | mi	49,000
Number of barrels of storage capacity | bbl	250
Number of cubic feet of storage capacity | ft³	14
Number of reportable segments | Segment	5
Limited partners ownership interest (in hundredths)	100.00%
EPCO and affiliates [Member]
Related Party Transaction [Line Items]
Percentage of total units outstanding (in hundredths)	33.60%
Oiltanking Partners L.P. [Member]
Business Acquisition [Line Items]
Limited partner interests acquired (in hundredths)		65.90%

Summary of Significant Accoun49

Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current Assets and Current Liabilities [Abstract]
Threshold for components of total current assets and current liabilities to be presented as an individual caption on Consolidated Balance Sheet (in hundredths)	5.00%
Environmental Costs [Abstract]
Environmental reserves - current portion	$ 5.8	$ 8.1
Restricted Cash [Abstract]
Restricted cash	$ 15.9	0
Minimum [Member]
Derivative Instruments [Abstract]
Expected offset percentage of change in fair value derivative instrument (in hundredths)	80.00%
Maximum [Member]
Derivative Instruments [Abstract]
Expected offset percentage of change in fair value derivative instrument (in hundredths)	125.00%
Allowance for Doubtful Accounts, Current [Member]
Movement in valuation allowances and reserves [Roll Forward]
Balance at beginning of period	$ 13.9	7.5	$ 13.2
Charged to costs and expenses	0.8	8.4	2.1
Deductions	(2.6)	(2)	(7.8)
Balance at end of period	12.1	13.9	7.5
Reserve for Environmental Costs [Member]
Movement in valuation allowances and reserves [Roll Forward]
Balance at beginning of period	15.6	9.9	13.7
Charged to costs and expenses	6.4	11.9	3.9
Acquisition-related additions and other	1.1	2.5	0.7
Deductions	(10.1)	(8.7)	(8.4)
Balance at end of period	$ 13	$ 15.6	$ 9.9
Minor Investment [Member] | Minimum [Member]
Consolidation Policy [Abstract]
Equity method of ownership interest (in hundredths)	3.00%
Minor Investment [Member] | Maximum [Member]
Consolidation Policy [Abstract]
Equity method of ownership interest (in hundredths)	50.00%
Major Investment [Member] | Minimum [Member]
Consolidation Policy [Abstract]
Equity method of ownership interest (in hundredths)	20.00%
Major Investment [Member] | Maximum [Member]
Consolidation Policy [Abstract]
Equity method of ownership interest (in hundredths)	50.00%

Inventories (Details)

Inventories (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Available-for-Sale Inventory by Product Type [Abstract]
NGLs		$ 639.9	$ 579.1
Petrochemicals and refined products		148	295.6
Crude oil		222.1	97.8
Natural gas		28.1	41.7
Total		1,038.1	1,014.2
Summary of cost of sales and lower of cost or market adjustments [Abstract]
Cost of sales	[1]	19,612.9	40,464.1	$ 40,770.2
Lower of cost or market adjustments within cost of sales		$ 19.8	$ 22.8	$ 18.5
[1]	Cost of sales is a component of "Operating costs and expenses," as presented on our 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 Equipment51

Property, Plant and Equipment (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property, plant and equipment and accumulated depreciation [Abstract]
Property, plant and equipment, gross		$ 40,611.9	$ 38,046.7
Less accumulated depreciation		8,577.2	8,165.1
Property, plant and equipment, net		32,034.7	29,881.6	$ 26,946.6
Summary of depreciation expense and capitalized interest [Abstract]
Depreciation expense	[1]	1,161.6	1,114.1	1,012.4
Capitalized interest	[2]	149.1	77.9	133
Asset Retirement Obligations [Roll Forward]
ARO liability beginning balance		98.3	90.2	105.2
Liabilities incurred		2.7	0.1	1.7
Liabilities settled		(6.3)	(2.7)	(14.2)
Revisions in estimated cash flows		49.7	4.6	(8.6)
Accretion expense		5.2	6.1	6.1
AROs related to Offshore Business sold in July 2015		(91.1)	0	0
ARO liability ending balance		58.5	98.3	$ 90.2
Capitalized costs, asset retirement costs		17.6	31.3
Forecasted accretion expense [Abstract]
2,016		3.7
2,017		4
2,018		4.3
2,019		4.7
2,020		5
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]
Property, plant and equipment, gross	[3]	$ 32,525	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]
Property, plant and equipment, gross	[5]	$ 3,000.5	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]
Property, plant and equipment, gross	[7]	$ 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]
Property, plant and equipment, gross	[8]	$ 159.9	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]
Property, plant and equipment, gross	[9]	$ 769.8	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]
Property, plant and equipment, gross		$ 262.7	262.6
Construction in progress [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Property, plant and equipment, gross		$ 3,894	$ 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
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
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
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 Statements of Consolidated Operations.
[2]	Capitalized interest is a component of "Interest expense" as presented on our Statements of Consolidated Operations.
[3]	Plants, pipelines and facilities include processing plants; NGL, natural gas, crude oil and petrochemical and refined products pipelines; terminal loading and unloading facilities; buildings; office furniture and equipment; 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; buildings, 20-40 years; office furniture and equipment, 3-20 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.
[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, Significant Sales (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)		Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Jun. 30, 2015USD ($)
Significant Acquisitions and Disposals [Line Items]
Proceeds from disposal of assets	$ 1,608.6		$ 145.3	$ 280.6
Net gains (losses) attributable to disposal of assets	(15.6)		102.1	83.3
Non-cash asset impairment charge	$ 67	[1]	$ 3.7	5.6
Offshore Pipelines And Services [Member]
Significant Acquisitions and Disposals [Line Items]
Percentage of segment assets (in hundredths)			0.043
Percentage of gross operating margin (in hundredths)			0.031
Offshore Business [Member]
Significant Acquisitions and Disposals [Line Items]
Description of assets sold	Our Offshore Business served drilling and development regions, including deepwater production fields, in the northern Gulf of Mexico offshore Alabama, Louisiana, Mississippi and Texas and included approximately 2,350 miles of offshore natural gas and crude oil pipelines and six offshore hub platforms.
Proceeds from disposal of assets	$ 1,527.7		$ 0	0
Net gains (losses) attributable to disposal of assets	(12.3)		$ 0	$ 0
Non-cash asset impairment charge	54.8
Total loss on sale	$ (67.1)
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 of assets sold					$ 62.2
[1]	Includes a $54.8 million charge recorded in connection with the sale of our Offshore Business.

Investments in Unconsolidated53

Investments in Unconsolidated Affiliates (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Jun. 30, 2015
Schedule of Equity Method Investments [Line Items]
Investments in unconsolidated affiliates		$ 2,628.5	$ 3,042
Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]
Equity in income (loss) of unconsolidated affiliates		373.6	259.5	$ 167.3
Unamortized excess cost amounts by business segment [Abstract]
Unamortized excess cost amounts		46.9	59.6
Equity method investment amortization of excess cost		4.9	3.3	3.3
Forecasted amortization of excess cost amounts - 2016		2.2
Forecasted amortization of excess cost amounts - 2017		2.2
Forecasted amortization of excess cost amounts - 2018		2.2
Forecasted amortization of excess cost amounts - 2019		2.2
Forecasted amortization of excess cost amounts - 2020		2.2
Equity Method Investment, Summarized Financial Information, Balance Sheet [Abstract]
Current assets		204.5	289.9
Property, plant and equipment, net		5,671.1	6,766.5
Other assets		58.9	60.4
Total assets		5,934.5	7,116.8
Current liabilities		306.7	305.9
Other liabilities		103.2	309.9
Combined equity		5,524.6	6,501
Total liabilities and combined equity		5,934.5	7,116.8
Equity Method Investment, Summarized Financial Information, Income Statement [Abstract]
Revenues		1,426.6	1,311.3	947.4
Operating income		825.8	600	423.9
Net income		814.1	587.9	382.6
NGL Pipelines & Services [Member]
Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]
Equity in income (loss) of unconsolidated affiliates		57.5	30.6	15.7
Unamortized excess cost amounts by business segment [Abstract]
Unamortized excess cost amounts		$ 25.3	26.5
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%
Investments in unconsolidated affiliates		$ 25.9	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%
Investments in unconsolidated affiliates		$ 38.3	38.5
NGL Pipelines & Services [Member] | Baton Rouge Fractionators LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership Interest (in hundredths)		32.20%
Investments in unconsolidated affiliates		$ 18.5	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%
Investments in unconsolidated affiliates		$ 39.8	40.1
NGL Pipelines & Services [Member] | Texas Express Pipeline LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership Interest (in hundredths)		35.00%
Investments in unconsolidated affiliates		$ 342	349.3
NGL Pipelines & Services [Member] | Texas Express Gathering LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership Interest (in hundredths)		45.00%
Investments in unconsolidated affiliates		$ 36.8	37.9
NGL Pipelines & Services [Member] | Front Range Pipeline LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership Interest (in hundredths)		33.30%
Investments in unconsolidated affiliates		$ 171.2	170
NGL Pipelines & Services [Member] | Delaware Basin Gas Processing LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership Interest (in hundredths)		50.00%
Investments in unconsolidated affiliates		$ 46.2	0
Crude Oil Pipelines & Services [Member]
Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]
Equity in income (loss) of unconsolidated affiliates		281.4	184.6	140.3
Unamortized excess cost amounts by business segment [Abstract]
Unamortized excess cost amounts		$ 19.3	21.7
Crude Oil Pipelines & Services [Member] | Seaway Crude Pipeline Company LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership Interest (in hundredths)		50.00%
Investments in unconsolidated affiliates		$ 1,396	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%
Investments in unconsolidated affiliates		$ 388.8	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%
Investments in unconsolidated affiliates		$ 28.6	0
Natural Gas Pipelines & Services [Member]
Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]
Equity in income (loss) of unconsolidated affiliates		$ 3.8	3.6	3.8
Natural Gas Pipelines & Services [Member] | White River Hub, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership Interest (in hundredths)		50.00%
Investments in unconsolidated affiliates		$ 22.5	23.2
Petrochemical & Refined Products Services [Member]
Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]
Equity in income (loss) of unconsolidated affiliates	[1]	(15.7)	(13.3)	(22.3)
Unamortized excess cost amounts by business segment [Abstract]
Unamortized excess cost amounts		$ 2.3	2.4
Petrochemical & Refined Products Services [Member] | Baton Rouge Propylene Concentrator, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership Interest (in hundredths)		30.00%
Investments in unconsolidated affiliates		$ 5.4	6.5
Petrochemical & Refined Products Services [Member] | Centennial Pipeline LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership Interest (in hundredths)		50.00%
Investments in unconsolidated affiliates		$ 65.6	66.1
Petrochemical & Refined Products Services [Member] | Other Unconsolidated Affiliates [Member]
Schedule of Equity Method Investments [Line Items]
Investments in unconsolidated affiliates		2.9	2.5
Offshore Pipelines & Services [Member]
Schedule of Equity Method Investments [Line Items]
Investments in unconsolidated affiliates		0	493.7		$ 482.4
Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]
Equity in income (loss) of unconsolidated affiliates		46.6	54	$ 29.8
Unamortized excess cost amounts by business segment [Abstract]
Unamortized excess cost amounts	[2]	$ 0	$ 9
[1]	Losses are primarily attributable to our investment in Centennial. As a result of a trend in declining earnings, we estimated the fair value of this equity-method investment during each of the last three fiscal years. Our estimates, based on a combination of the market and income approaches, indicate that the fair value of this investment remains substantially in excess of its carrying value.
[2]	Our investments in unconsolidated affiliates classified within the Offshore Pipelines & Services segment were sold to Genesis in July 2015.

Intangible Assets and Goodwill,

Intangible Assets and Goodwill, Intangible Assets (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Identifiable intangible assets [Abstract]
Gross Value		$ 5,273	$ 5,548.4
Accumulated Amortization		(1,235.8)	(1,246.3)
Carrying Value		4,037.2	4,302.1	$ 1,462.2
Amortization Expense		174.1	110.6	105.6
Forecasted amortization expense [Abstract]
2,016		181.6
2,017		177.4
2,018		171.6
2,019		167
2,020		166.3
Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Carrying Value		3,590
Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Carrying Value		450.2
Incentive distribution rights [Member]
Identifiable intangible assets [Abstract]
Carrying Value			1,460
NGL Pipelines & Services [Member]
Identifiable intangible assets [Abstract]
Gross Value		730.4	1,051.1
Accumulated Amortization		(350.1)	(361.9)
Carrying Value		380.3	689.2
Amortization Expense		33.6	33.1	36.4
NGL Pipelines & Services [Member] | Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value		447.4	340.8
Accumulated Amortization		(156.9)	(183.2)
Carrying Value		290.5	157.6
NGL Pipelines & Services [Member] | Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value		283	277.7
Accumulated Amortization		(193.2)	(178.7)
Carrying Value		89.8	99
NGL Pipelines & Services [Member] | Incentive distribution rights [Member]
Identifiable intangible assets [Abstract]
Gross Value	[1]	0	432.6
Accumulated Amortization	[1]	0	0
Carrying Value	[1]	0	432.6
Crude Oil Pipelines & Services [Member]
Identifiable intangible assets [Abstract]
Gross Value		2,485.8	2,244.8
Accumulated Amortization		(108.3)	(21.2)
Carrying Value		2,377.5	2,223.6
Amortization Expense		87.1	15.7	1.4
Crude Oil Pipelines & Services [Member] | Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value		2,204.4	1,108
Accumulated Amortization		(39.1)	(7.7)
Carrying Value		2,165.3	1,100.3
Crude Oil Pipelines & Services [Member] | Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value		281.4	281.4
Accumulated Amortization		(69.2)	(13.5)
Carrying Value		212.2	267.9
Crude Oil Pipelines & Services [Member] | Incentive distribution rights [Member]
Identifiable intangible assets [Abstract]
Gross Value	[1]	0	855.4
Accumulated Amortization	[1]	0	0
Carrying Value	[1]	0	855.4
Natural Gas Pipelines & Services [Member]
Identifiable intangible assets [Abstract]
Gross Value		1,815	1,629.6
Accumulated Amortization		(727.3)	(656.7)
Carrying Value		1,087.7	972.9
Amortization Expense		40	45	50.1
Natural Gas Pipelines & Services [Member] | Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value		1,350.3	1,163.6
Accumulated Amortization		(366.3)	(308.9)
Carrying Value		984	854.7
Natural Gas Pipelines & Services [Member] | Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value		464.7	466
Accumulated Amortization		(361)	(347.8)
Carrying Value		103.7	118.2
Petrochemical & Refined Products Services [Member]
Identifiable intangible assets [Abstract]
Gross Value		241.8	425.9
Accumulated Amortization		(50.1)	(51.1)
Carrying Value		191.7	374.8
Amortization Expense		8.9	6.9	6.2
Petrochemical & Refined Products Services [Member] | Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value		185.5	198.4
Accumulated Amortization		(38.3)	(43.3)
Carrying Value		147.2	155.1
Petrochemical & Refined Products Services [Member] | Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value		56.3	56.3
Accumulated Amortization		(11.8)	(7.8)
Carrying Value		44.5	48.5
Petrochemical & Refined Products Services [Member] | Incentive distribution rights [Member]
Identifiable intangible assets [Abstract]
Gross Value	[1]	0	171.2
Accumulated Amortization	[1]	0	0
Carrying Value	[1]	0	171.2
Offshore Pipelines & Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	[2]	0	197
Accumulated Amortization	[2]	0	(155.4)
Carrying Value	[2]	0	41.6
Amortization Expense		4.5	9.9	$ 11.5
Offshore Pipelines & Services [Member] | Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	[2]	0	195.8
Accumulated Amortization	[2]	0	(154.9)
Carrying Value	[2]	0	40.9
Offshore Pipelines & Services [Member] | Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	[2]	0	1.2
Accumulated Amortization	[2]	0	(0.5)
Carrying Value	[2]	$ 0	$ 0.7
[1]	We recorded intangible assets having an aggregate carrying value of $1.46 billion in connection with our October 2014 acquisition of the IDRs of Oiltanking. The IDRs represented contractual rights to future cash incentive distributions to be paid by Oiltanking. These rights were granted to Oiltanking GP under the terms of Oiltanking's partnership agreement. Oiltanking GP could separate and sell the IDRs independent of its other residual general partner interest in Oiltanking. In February 2015 (following completion of Step 2 of the Oiltanking acquisition), the Oiltanking IDRs were cancelled and the carrying value of this intangible asset was reclassified to goodwill.
[2]	Our intangible assets classified within the Offshore Pipelines & Services segment were sold to Genesis in July 2015 (see Note 5).

Intangible Assets and Goodwil55

Intangible Assets and Goodwill, Significant Intangible Assets (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Identifiable intangible assets [Abstract]
Gross Value		$ 5,273	$ 5,548.4
Accumulated Amortization		(1,235.8)	(1,246.3)
Carrying Value		4,037.2	4,302.1	$ 1,462.2
Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Carrying Value		3,590
Customer relationship intangibles [Member] | EFS Midstream [Member]
Identifiable intangible assets [Abstract]
Gross Value	[1]	1,409.8
Accumulated Amortization	[1]	(26.2)
Carrying Value	[1]	$ 1,383.6
Weighted Average Remaining Amortization Period (in years)	[1]	26 years 4 months 24 days
Cash flow projections discount rate (in hundredths)		15.00%
Customer relationship intangibles [Member] | State Line and Fairplay [Member]
Identifiable intangible assets [Abstract]
Gross Value	[2]	$ 895
Accumulated Amortization	[2]	(141.7)
Carrying Value	[2]	$ 753.3
Weighted Average Remaining Amortization Period (in years)	[2]	31 years 2 months 12 days
Customer relationship intangibles [Member] | San Juan Gathering [Member]
Identifiable intangible assets [Abstract]
Gross Value	[3]	$ 331.3
Accumulated Amortization	[3]	(196.4)
Carrying Value	[3]	$ 134.9
Weighted Average Remaining Amortization Period (in years)	[3]	23 years 9 months 18 days
Customer relationship intangibles [Member] | Encinal [Member]
Identifiable intangible assets [Abstract]
Gross Value	[4]	$ 132.9
Accumulated Amortization	[4]	(86.9)
Carrying Value	[4]	$ 46
Weighted Average Remaining Amortization Period (in years)	[4]	11 years
Customer relationship intangibles [Member] | Oiltanking Partners L.P. [Member]
Identifiable intangible assets [Abstract]
Gross Value	[5]	$ 1,192.5
Accumulated Amortization	[5]	(11.5)
Carrying Value	[5]	$ 1,181
Weighted Average Remaining Amortization Period (in years)	[5]	28 years
Cash flow projections discount rate (in hundredths)		6.50%
Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Carrying Value		$ 450.2
Contract-based intangibles [Member] | Oiltanking Partners L.P. [Member]
Identifiable intangible assets [Abstract]
Gross Value		297.4
Carrying Value		$ 225.1
Weighted Average Remaining Amortization Period (in years)		5 years 2 months 12 days
Contract-based intangibles [Member] | Jonah Gas Gathering [Member]
Identifiable intangible assets [Abstract]
Carrying Value		$ 76.1
Weighted Average Remaining Amortization Period (in years)		26 years
Incentive distribution rights [Member]
Identifiable intangible assets [Abstract]
Carrying Value			$ 1,460
[1]	We acquired these intangible assets in connection with our acquisition of EFS Midstream in July 2015 (see Note 12 for additional information).
[2]	These customer relationships are associated with our State Line and Fairplay Gathering Systems, which we acquired in 2010. The State Line system serves producers in the Haynesville and Bossier Shale supply basins and the Cotton Valley and Taylor Sand formations in Louisiana and eastern Texas. The Fairplay system serves producers in the Cotton Valley and Taylor Sand formations within Panola and Rusk counties in East Texas.
[3]	These customer relationships are associated with our San Juan Gathering System, which serves producers in the San Juan Basin of northern New Mexico and southern Colorado. We acquired this intangible asset in 2004.
[4]	These customer relationships are associated with our Encinal Gathering System, which serves producers in the Olmos and Wilcox formations in South Texas. We acquired this intangible asset in 2006.
[5]	We acquired these intangible assets in connection with our acquisition of Oiltanking in October 2014 (see Note 12 for additional information).

Intangible Assets and Goodwil56

Intangible Assets and Goodwill, Goodwill (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Changes in carrying amount of goodwill [Roll Forward]
Balance at beginning of period	$ 4,300.2	$ 2,080	$ 2,086.8
Purchase price and other adjustments	1,454.1
Reclassification of goodwill between segments		0
Reduction in goodwill related to the sale of assets	(84.1)	(0.1)	(6.8)
Addition to goodwill related to business acquisition	82.6	2,220.3
Goodwill reclassified to assets held-for-sale	(7.6)
Balance at end of period	5,745.2	4,300.2	2,080
Oiltanking Partners L.P. [Member]
Changes in carrying amount of goodwill [Roll Forward]
Purchase price and other adjustments	1,454.1
Addition to goodwill related to business acquisition		2,220.3
Balance at end of period	3,670
EFS Midstream [Member]
Changes in carrying amount of goodwill [Roll Forward]
Addition to goodwill related to business acquisition	82.6
NGL Pipelines & Services [Member]
Changes in carrying amount of goodwill [Roll Forward]
Balance at beginning of period	2,210.2	341.2	341.2
Purchase price and other adjustments	432.6
Reclassification of goodwill between segments		520
Reduction in goodwill related to the sale of assets	0	0	0
Addition to goodwill related to business acquisition	8.9	1,349
Goodwill reclassified to assets held-for-sale	0
Balance at end of period	2,651.7	2,210.2	341.2
Crude Oil Pipelines & Services [Member]
Changes in carrying amount of goodwill [Roll Forward]
Balance at beginning of period	918.7	305.1	311.2
Purchase price and other adjustments	850.7
Reclassification of goodwill between segments		0
Reduction in goodwill related to the sale of assets	(2.1)	0	(6.1)
Addition to goodwill related to business acquisition	73.7	613.6
Goodwill reclassified to assets held-for-sale	0
Balance at end of period	1,841	918.7	305.1
Natural Gas Pipelines & Services [Member]
Changes in carrying amount of goodwill [Roll Forward]
Balance at beginning of period	296.3	296.3	296.3
Purchase price and other adjustments	0
Reclassification of goodwill between segments		0
Reduction in goodwill related to the sale of assets	0	0	0
Addition to goodwill related to business acquisition	0	0
Goodwill reclassified to assets held-for-sale	0
Balance at end of period	296.3	296.3	296.3
Petrochemical & Refined Products Services [Member]
Changes in carrying amount of goodwill [Roll Forward]
Balance at beginning of period	793	1,055.3	1,056
Purchase price and other adjustments	170.8
Reclassification of goodwill between segments		(520)
Reduction in goodwill related to the sale of assets	0	0	(0.7)
Addition to goodwill related to business acquisition	0	257.7
Goodwill reclassified to assets held-for-sale	(7.6)
Balance at end of period	956.2	793	1,055.3
Offshore Pipelines & Services [Member]
Changes in carrying amount of goodwill [Roll Forward]
Balance at beginning of period	82	82.1	82.1
Purchase price and other adjustments	0
Reclassification of goodwill between segments		0
Reduction in goodwill related to the sale of assets	(82)	(0.1)	0
Addition to goodwill related to business acquisition	0	0
Goodwill reclassified to assets held-for-sale	0
Balance at end of period	$ 0	$ 82	$ 82.1

Debt Obligations (Details)

Debt Obligations (Details) - USD ($) $ in Millions		1 Months Ended	12 Months Ended
		Feb. 26, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Principal Outstanding			$ 22,738.5	$ 21,389.2
Total other, non-principal amounts			(47.9)	(25.4)
Less current maturities of debt			(1,863.9)	(2,206.4)
Total long-term debt			20,826.7	19,157.4
Debt Obligations Terms [Abstract]
Gains on early extinguishment of debt			1.6	0	$ 0
Letters of credit outstanding for facilities and motor fuel tax obligations			2.5
Unamortized debt issuance costs			159.8
Senior Debt Obligations [Member]
Debt Instrument [Line Items]
Principal Outstanding			21,264.1	19,856.5
Senior Debt Obligations [Member] | Commercial Paper Notes [Member]
Debt Instrument [Line Items]
Principal Outstanding			$ 1,114.1	906.5
Debt Obligations Terms [Abstract]
Interest Rate Terms			variable
Maximum borrowing capacity			$ 2,500
Information regarding variable interest rates paid [Abstract]
Variable Interest Rates Paid, Minimum (in hundredths)			0.35%
Variable Interest Rates Paid, Maximum (in hundredths)			0.92%
Weighted-Average Interest Rate Paid (in hundredths)			0.58%
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
Repayment of debt obligations		$ 750
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
Total maximum borrowing capacity			1,700
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
Total maximum borrowing capacity			$ 4,500
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]
Debt Obligations Terms [Abstract]
Gains on early extinguishment of debt			$ 1.6
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes A [Member]
Debt Instrument [Line Items]
Principal Outstanding	[1]		$ 521.1	550
Debt Obligations Terms [Abstract]
Interest Rate Terms			fixed/variable
Interest Rate, stated percentage (in hundredths)	[2]		8.375%
Maturity Date			Aug. 31, 2066
Repayment of debt obligations			$ 28.9
Date through which interest rate is fixed	[2]		8/1/2016
Variable annual interest rate thereafter, variable rate basis			3-month LIBOR
Variable interest rate (in hundredths)	[3]		3.708%
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes C [Member]
Debt Instrument [Line Items]
Principal Outstanding	[4]		$ 256.4	285.8
Debt Obligations Terms [Abstract]
Interest Rate Terms			fixed/variable
Interest Rate, stated percentage (in hundredths)	[5]		7.00%
Maturity Date			Jun. 1, 2067
Repayment of debt obligations			$ 29.4
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)	[6]		2.778%
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes B [Member]
Debt Instrument [Line Items]
Principal Outstanding	[7]		$ 682.7	682.7
Debt Obligations Terms [Abstract]
Interest Rate Terms			fixed/variable
Interest Rate, stated percentage (in hundredths)	[8]		7.034%
Maturity Date			Jan. 15, 2068
Date through which interest rate is fixed	[8]		1/15/2018
Variable annual interest rate thereafter, variable rate basis			3-month LIBOR
Variable interest rate (in hundredths)	[9]		2.68%
Minimum variable annual interest rate (in hundredths)	[9]		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
Senior Notes [Member]
Debt Instrument [Line Items]
Principal Outstanding			$ 20,150
Debt Obligations Terms [Abstract]
Aggregate debt principal issued			2,500	$ 4,750	$ 2,250
Junior and Senior Notes [Member]
Debt Obligations Terms [Abstract]
Unamortized debt issuance costs			149.8
Revolving Credit Facilities [Member]
Debt Obligations Terms [Abstract]
Unamortized debt issuance costs			$ 10
[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 3.708%.
[2]	Interest is payable semi-annually in arrears in February and August of each year, which commenced in February 2007.
[3]	Interest is payable quarterly in arrears in February, May, August and November of each year commencing in November 2016.
[4]	Fixed rate of 7.000% through September 1, 2017 (i.e., first call date without a make-whole redemption premium); thereafter, variable rate based on 3-month LIBOR plus 2.778%.
[5]	Interest is payable semi-annually in arrears in June and December of each year, which commenced in December 2009.
[6]	Interest is payable quarterly in arrears in March, June, September and December of each year commencing in June 2017.
[7]	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 2.680%.
[8]	Interest is payable semi-annually in arrears in January and July of each year, which commenced in January 2008.
[9]	Interest is payable quarterly in arrears in January, April, July and October of each year commencing in April 2018.

Debt Obligations, Debt Maturiti

Debt Obligations, Debt Maturities (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Scheduled Maturities of Debt [Abstract]
2,016	$ 1,864.1
2,017	800
2,018	1,100
2,019	1,500
2,020	1,500
After 2,020	15,974.4
Total	22,738.5	$ 21,389.2
Commercial Paper Notes [Member]
Scheduled Maturities of Debt [Abstract]
2,016	1,114.1
2,017	0
2,018	0
2,019	0
2,020	0
After 2,020	0
Total	1,114.1
Senior Notes [Member]
Scheduled Maturities of Debt [Abstract]
2,016	750
2,017	800
2,018	1,100
2,019	1,500
2,020	1,500
After 2,020	14,500
Total	20,150
Junior Subordinated Notes [Member]
Scheduled Maturities of Debt [Abstract]
2,016	0
2,017	0
2,018	0
2,019	0
2,020	0
After 2,020	1,474.4
Total	$ 1,474.4

Equity and Distributions, Summa

Equity and Distributions, Summary of Changes in Outstanding Units (Details) - shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Common Units (Unrestricted) [Member]
Summary of changes in outstanding units [Roll Forward]
Beginning Balance (in units)	1,933,095,027	1,864,148,802	1,789,839,702
Common units issued in connection with underwritten offerings (in units)			36,800,000
Common units issued in connection with ATM program (in units)	25,520,424	1,590,334	15,249,378
Common units issued in connection with DRIP and EUPP (in units)	12,793,913	9,754,227	10,308,254
Common units issued in connection with Oiltanking acquisition (in units)	36,827,517	54,807,352
Common units issued in connection with the vesting and exercise of unit options (in units)	396,158	1,014,108	401,764
Common units issued in connection with the vesting of phantom unit awards (in units)	618,395	23,311
Common units issued in connection with the vesting of restricted common unit awards (in units)	2,009,970	2,634,074	3,770,696
Conversion and reclassification of Class B units to common units (in units)			9,040,862
Restricted common units awards issued (in units)			0
Forfeiture of restricted common unit awards (in units)	0	0	0
Acquisition and cancellation of treasury units in connection with the vesting of equity-based awards (in units)	(683,954)	(894,383)	(1,261,854)
Other (in units)	15,054	17,202
Ending Balance (in units)	2,010,592,504	1,933,095,027	1,864,148,802
Restricted Common Units [Member]
Summary of changes in outstanding units [Roll Forward]
Beginning Balance (in units)	4,229,790	7,221,214	7,786,972
Common units issued in connection with underwritten offerings (in units)			0
Common units issued in connection with ATM program (in units)	0	0	0
Common units issued in connection with DRIP and EUPP (in units)	0	0	0
Common units issued in connection with Oiltanking acquisition (in units)	0	0
Common units issued in connection with the vesting and exercise of unit options (in units)	0	0	0
Common units issued in connection with the vesting of phantom unit awards (in units)	0	0
Common units issued in connection with the vesting of restricted common unit awards (in units)	(2,009,970)	(2,634,074)	(3,770,696)
Conversion and reclassification of Class B units to common units (in units)			0
Restricted common units awards issued (in units)			3,549,052
Forfeiture of restricted common unit awards (in units)	(259,300)	(357,350)	(344,114)
Acquisition and cancellation of treasury units in connection with the vesting of equity-based awards (in units)	0	0	0
Other (in units)	0	0
Ending Balance (in units)	1,960,520	4,229,790	7,221,214
Common units [Member]
Summary of changes in outstanding units [Roll Forward]
Beginning Balance (in units)	1,937,324,817	1,871,370,016	1,797,626,674
Common units issued in connection with underwritten offerings (in units)			36,800,000
Common units issued in connection with ATM program (in units)	25,520,424	1,590,334	15,249,378
Common units issued in connection with DRIP and EUPP (in units)	12,793,913	9,754,227	10,308,254
Common units issued in connection with Oiltanking acquisition (in units)	36,827,517	54,807,352
Common units issued in connection with the vesting and exercise of unit options (in units)	396,158	1,014,108	401,764
Common units issued in connection with the vesting of phantom unit awards (in units)	618,395	23,311
Common units issued in connection with the vesting of restricted common unit awards (in units)	0	0	0
Conversion and reclassification of Class B units to common units (in units)			9,040,862
Restricted common units awards issued (in units)			3,549,052
Forfeiture of restricted common unit awards (in units)	(259,300)	(357,350)	(344,114)
Acquisition and cancellation of treasury units in connection with the vesting of equity-based awards (in units)	(683,954)	(894,383)	(1,261,854)
Other (in units)	15,054	17,202
Ending Balance (in units)	2,012,553,024	1,937,324,817	1,871,370,016

Equity and Distributions, Issua

Equity and Distributions, Issuances of Equity (Details) $ / shares in Units, $ in Millions	1 Months Ended				12 Months Ended
	Feb. 26, 2016USD ($)shares	Jan. 31, 2016USD ($)shares	Nov. 30, 2013USD ($)$ / sharesshares	Feb. 28, 2013USD ($)$ / sharesshares	Dec. 31, 2015USD ($)shares	Dec. 31, 2014USD ($)shares	Dec. 31, 2013USD ($)shares	Dec. 31, 2009	Aug. 02, 2015USD ($)	Mar. 31, 2015$ / shares
Net Cash Proceeds from Sale of Common Units [Abstract]
Net cash proceeds from the issuance of common units | $					$ 1,188.6	$ 388.8	$ 1,792
Split of limited partner units ratio						2
Class B Units [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Common unit exchange ratio in connection with merger								1.24
Treasury Units [Member]
Treasury Units [Abstract]
Maximum common units authorized for repurchase under a buy-back program (in units)					4,000,000
Total of common units repurchased under a buy-back program (in units)					2,763,200
Remaining common units available for repurchase (in units)					1,236,800
Total cost of treasury units | $					$ 33.6
Shelf Registration 2010 [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Number of common units issued (in units)				18,400,000
Over-allotment of common units included in offering (in units)				2,400,000
Offering price of common unit (in dollars per unit) | $ / shares				$ 27.28
Net cash proceeds from the issuance of common units | $				$ 486.6
Senior notes issued under universal shelf registration | $							$ 2,250
Shelf Registration 2013 [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Number of common units issued (in units)			18,400,000
Over-allotment of common units included in offering (in units)			2,400,000
Offering price of common unit (in dollars per unit) | $ / shares			$ 31.03
Net cash proceeds from the issuance of common units | $			$ 553
Senior notes issued under universal shelf registration | $					2,500	$ 4,750
At-the-Market Registration [Member]
Registration Statements and Equity Offerings [Line Items]
Maximum common units authorized for issuance | $					1,920				$ 1,250
Remaining units available for issuance | $					$ 1,860				$ 424.6
Net Cash Proceeds from Sale of Common Units [Abstract]
Number of common units issued (in units)					25,520,424	1,590,334	15,249,378
Gross proceeds from the sale of common units | $					$ 825.4	$ 58.3	$ 460.4
Net cash proceeds from the issuance of common units | $					$ 817.4	$ 57.7	$ 456.3
At-the-Market Registration [Member] | EPCO and affiliates [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Number of common units issued (in units)		3,830,256			3,225,057
Offering price of common unit (in dollars per unit) | $ / shares										$ 31.01
Net cash proceeds from the issuance of common units | $		$ 100			$ 100
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)					15,067,998
Net Cash Proceeds from Sale of Common Units [Abstract]
Number of common units issued (in units)					12,413,351	9,480,407	10,024,828
Net cash proceeds from the issuance of common units | $					$ 359.8	$ 321.3	$ 287.6
Distribution Reinvestment Plan [Member] | EPCO and affiliates [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Number of common units issued (in units)	4,481,504
Net cash proceeds from the issuance of common units | $	$ 100				$ 100	$ 100
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)					6,772,506
Net Cash Proceeds from Sale of Common Units [Abstract]
Number of common units issued (in units)					380,562	273,820	283,426
Net cash proceeds from the issuance of common units | $					$ 11.4	$ 9.8	$ 8.5

Equity and Distributions, Accum

Equity and Distributions, Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accumulated Other Comprehensive Income (Loss) [Abstract]
Beginning Balance				$ (241.6)				$ (359)	$ (241.6)	$ (359)
Other comprehensive income before reclassifications									215.3	161.7
Amounts reclassified from accumulated other comprehensive (income) loss									(192.9)	(44.3)
Total other comprehensive income (loss)									22.4	117.4	$ 11.4
Ending Balance	$ (219.2)				$ (241.6)				(219.2)	(241.6)	(359)
Interest expense									961.8	921	802.5
Operating costs and expenses									23,668.7	44,220.5	44,238.7
Total	(693.5)	$ (657.7)	$ (556.6)	(650.6)	(681.1)	$ (699.2)	$ (646.5)	(806.7)	(2,558.4)	(2,833.5)	(2,607.1)
Gains and Losses on Cash Flow Hedges [Member] | Commodity derivatives [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Beginning Balance				69.9				(14.7)	69.9	(14.7)
Other comprehensive income before reclassifications									214.9	161.3
Amounts reclassified from accumulated other comprehensive (income) loss									(228.2)	(76.7)
Total other comprehensive income (loss)									(13.3)	84.6
Ending Balance	56.6				69.9				56.6	69.9	(14.7)
Gains and Losses on Cash Flow Hedges [Member] | Interest rate derivatives [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Beginning Balance				(314.8)				(347.2)	(314.8)	(347.2)
Other comprehensive income before reclassifications									0	0
Amounts reclassified from accumulated other comprehensive (income) loss									35.3	32.4
Total other comprehensive income (loss)									35.3	32.4
Ending Balance	(279.5)				(314.8)				(279.5)	(314.8)	(347.2)
Other [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Beginning Balance				$ 3.3				$ 2.9	3.3	2.9
Other comprehensive income before reclassifications									0.4	0.4
Amounts reclassified from accumulated other comprehensive (income) loss									0	0
Total other comprehensive income (loss)									0.4	0.4
Ending Balance	$ 3.7				$ 3.3				3.7	3.3	$ 2.9
Reclassification out of Accumulated Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Total									(192.9)	(44.3)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Commodity derivatives [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Revenue									(231.7)	(75)
Operating costs and expenses									3.5	(1.7)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Interest rate derivatives [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Interest expense									$ 35.3	$ 32.4

Equity and Distributions, Nonco

Equity and Distributions, Noncontrolling Interests (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Components of noncontrolling interests
Limited partners of Oiltanking other than EPO	$ 0	$ 1,408.9
Joint venture partners	206	220.1
Total	206	1,629
Components of net income attributable to noncontrolling interests
Limited partners of Oiltanking other than EPO	7.8	14.2	$ 0
Joint venture partners	29.4	31.9	10.2
Total	37.2	46.1	10.2
Cash distributions paid to noncontrolling interests:
Limited partners of Oiltanking other than EPO	8.1	7.7	0
Joint venture partners	39.9	40.9	8.9
Total	48	48.6	8.9
Cash contributions from noncontrolling interests:
Joint venture partners	$ 54	$ 4	$ 115.4
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%
Oiltanking Partners L.P. [Member]
Noncontrolling Interest
Noncontrolling interests acquired	$ 1,400
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, Distr

Equity and Distributions, Distributions (Details) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Distributions to Partners [Abstract]
Number of Designated Units excluded from distributions	35,380,000	45,120,000	47,400,000
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] | Fourth Quarter 2014 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)		$ 0.3700
Record Date		Jan. 30, 2015
Payment Date		Feb. 6, 2015
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
Cash Distribution [Member] | Fourth Quarter 2015 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)	$ 0.3900
Record Date	Jan. 29, 2016
Payment Date	Feb. 5, 2016

Business Segments (Details)

Business Segments (Details)	12 Months Ended
	Dec. 31, 2015SegmentFractionatorTruckmi
Segment Reporting Information [Line Items]
Number of reportable segments | Segment	5
Number of miles of pipelines	49,000
NGL Pipelines and Services [Member]
Segment Reporting Information [Line Items]
Number of miles of pipelines	19,500
Number of fractionators | Fractionator	15
Crude Oil Pipelines & Services [Member]
Segment Reporting Information [Line Items]
Number of miles of pipelines	5,400
Number of tractor-trailors | Truck	478
Natural Gas Pipelines & Services [Member]
Segment Reporting Information [Line Items]
Number of miles of pipelines	19,100
Petrochemical and Refined Products Services [Member] | Propylene Operations [Member]
Segment Reporting Information [Line Items]
Number of miles of pipelines	674
Petrochemical and Refined Products Services [Member] | Refined Products Operations [Member]
Segment Reporting Information [Line Items]
Number of miles of pipelines	4,200

Business Segments, Gross Operat

Business Segments, Gross Operating Margin (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Gross Operating Margin [Abstract]
Revenues	$ 6,155	$ 6,307.9	$ 7,092.5	$ 7,472.5	$ 10,190.3	$ 12,330.2	$ 12,520.8	$ 12,909.9	$ 27,027.9	$ 47,951.2	$ 47,727
Subtract operating costs and expenses									(23,668.7)	(44,220.5)	(44,238.7)
Add equity in income of unconsolidated affiliates									373.6	259.5	167.3
Add depreciation, amortization and accretion expense amounts not reflected in gross operating margin									1,428.2	1,282.7	1,148.9
Add impairment charges not reflected in gross operating margin									162.6	34	92.6
Add net losses or subtract net gains attributable to asset sales and insurance recoveries not reflected in gross operating margin									15.6	(102.1)	(83.4)
Add non-refundable deferred revenues attributable to shipper make-up rights on major new pipeline projects reflected in gross operating margin									53.6	84.6	4.4
Subtract subsequent recognition of deferred revenues attributable to make-up rights not reflected in gross operating margin									(60.7)	(2.9)	0
Total segment gross operating margin									5,332.1	5,286.5	4,818.1
Reconciliation of Total Segment Gross Operating Margin [Abstract]
Total segment gross operating margin									5,332.1	5,286.5	4,818.1
Adjustments to reconcile total segment gross operating margin to operating income:
Subtract depreciation, amortization and accretion expense amounts not reflected in gross operating margin									(1,428.2)	(1,282.7)	(1,148.9)
Subtract impairment charges not reflected in gross operating margin									(162.6)	(34)	(92.6)
Add net gains or subtract net losses attributable to asset sales and insurance recoveries not reflected in gross operating margin									(15.6)	102.1	83.4
Subtract non-refundable deferred revenues attributable to shipper make-up rights on major new pipeline projects reflected in gross operating margin									(53.6)	(84.6)	(4.4)
Add subsequent recognition of deferred revenues attributable to make-up rights not reflected in gross operating margin									60.7	2.9	0
Subtract general and administrative costs not reflected in gross operating margin									(192.6)	(214.5)	(188.3)
Operating income	$ 934.5	$ 909.4	$ 800.3	$ 896	$ 921	$ 937.7	$ 884.3	$ 1,032.7	3,540.2	3,775.7	3,467.3
Other expense, net									(984.3)	(919.1)	(802.7)
Income before income taxes									$ 2,555.9	$ 2,856.6	$ 2,664.6

Business Segments, Segment Repo

Business Segments, Segment Reporting Information (Details) - USD ($) $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Information by business segment [Abstract]
Revenues from third parties										$ 26,955.6	$ 47,879.7	$ 47,661.1
Revenues from related parties										72.3	71.5	65.9
Intersegment and intrasegment revenues										0	0	0
Total revenues		$ 6,155	$ 6,307.9	$ 7,092.5	$ 7,472.5	$ 10,190.3	$ 12,330.2	$ 12,520.8	$ 12,909.9	27,027.9	47,951.2	47,727
Equity in income (loss) of unconsolidated affiliates										373.6	259.5	167.3
Gross operating margin										5,332.1	5,286.5	4,818.1
Property, plant and equipment, net		32,034.7				29,881.6				32,034.7	29,881.6	26,946.6
Investments in unconsolidated affiliates		2,628.5				3,042				2,628.5	3,042	2,437.1
Intangible assets, net		4,037.2				4,302.1				4,037.2	4,302.1	1,462.2
Goodwill		5,745.2				4,300.2				5,745.2	4,300.2	2,080	$ 2,086.8
Segment assets		44,445.6				41,525.9				44,445.6	41,525.9	32,925.9
NGL Pipelines and Services [Member]
Information by business segment [Abstract]
Total revenues										9,788	17,089.8	17,120.2
Equity in income (loss) of unconsolidated affiliates										57.5	30.6	15.7
Intangible assets, net		380.3				689.2				380.3	689.2
Goodwill		2,651.7				2,210.2				2,651.7	2,210.2	341.2	341.2
Crude Oil Pipelines & Services [Member]
Information by business segment [Abstract]
Total revenues										10,305.9	20,184.3	20,650.4
Equity in income (loss) of unconsolidated affiliates										281.4	184.6	140.3
Intangible assets, net		2,377.5				2,223.6				2,377.5	2,223.6
Goodwill		1,841				918.7				1,841	918.7	305.1	311.2
Natural Gas Pipelines & Services [Member]
Information by business segment [Abstract]
Total revenues										2,743.3	4,203.8	3,538.5
Equity in income (loss) of unconsolidated affiliates										3.8	3.6	3.8
Intangible assets, net		1,087.7				972.9				1,087.7	972.9
Goodwill		296.3				296.3				296.3	296.3	296.3	296.3
Petrochemical & Refined Products Services [Member]
Information by business segment [Abstract]
Total revenues										4,111.9	6,316.5	6,258.5
Equity in income (loss) of unconsolidated affiliates	[1]									(15.7)	(13.3)	(22.3)
Intangible assets, net		191.7				374.8				191.7	374.8
Goodwill		956.2				793				956.2	793	1,055.3	1,056
Offshore Pipelines And Services [Member]
Information by business segment [Abstract]
Total revenues										78.8	156.8	159.4
Equity in income (loss) of unconsolidated affiliates										46.6	54	29.8
Intangible assets, net	[2]	0				41.6				0	41.6
Goodwill		0				82				0	82	82.1	$ 82.1
Reportable Business Segments [Member] | NGL Pipelines and Services [Member]
Information by business segment [Abstract]
Revenues from third parties										9,779	17,078.4	17,119.1
Revenues from related parties										9	11.4	1.1
Intersegment and intrasegment revenues										10,217.9	13,716.5	11,096.6
Total revenues										20,005.9	30,806.3	28,216.8
Equity in income (loss) of unconsolidated affiliates										57.5	30.6	15.7
Gross operating margin										2,771.6	2,877.7	2,514.4
Property, plant and equipment, net		12,909.7				11,766.9				12,909.7	11,766.9	9,957.8
Investments in unconsolidated affiliates		718.7				682.3				718.7	682.3	645.5
Intangible assets, net		380.3				689.2				380.3	689.2	285.2
Goodwill		2,651.7				2,210.2				2,651.7	2,210.2	341.2
Segment assets		16,660.4				15,348.6				16,660.4	15,348.6	11,229.7
Reportable Business Segments [Member] | Crude Oil Pipelines & Services [Member]
Information by business segment [Abstract]
Revenues from third parties										10,258.3	20,151.9	20,609.1
Revenues from related parties										47.6	32.4	41.3
Intersegment and intrasegment revenues										5,162	12,678.7	10,222.3
Total revenues										15,467.9	32,863	30,872.7
Equity in income (loss) of unconsolidated affiliates										281.4	184.6	140.3
Gross operating margin										961.9	762.5	742.7
Property, plant and equipment, net		3,550.3				2,332.2				3,550.3	2,332.2	1,479.9
Investments in unconsolidated affiliates		1,813.4				1,767.7				1,813.4	1,767.7	1,165.2
Intangible assets, net		2,377.5				2,223.6				2,377.5	2,223.6	4.5
Goodwill		1,841				918.7				1,841	918.7	305.1
Segment assets		9,582.2				7,242.2				9,582.2	7,242.2	2,954.7
Reportable Business Segments [Member] | Natural Gas Pipelines & Services [Member]
Information by business segment [Abstract]
Revenues from third parties										2,729.5	4,182.6	3,522.7
Revenues from related parties										13.8	21.2	15.8
Intersegment and intrasegment revenues										662.1	1,106.7	959.7
Total revenues										3,405.4	5,310.5	4,498.2
Equity in income (loss) of unconsolidated affiliates										3.8	3.6	3.8
Gross operating margin										782.6	803.3	789
Property, plant and equipment, net		8,620				8,835.5				8,620	8,835.5	8,917.3
Investments in unconsolidated affiliates		22.5				23.2				22.5	23.2	24.2
Intangible assets, net		1,087.7				972.9				1,087.7	972.9	1,017.8
Goodwill		296.3				296.3				296.3	296.3	296.3
Segment assets		10,026.5				10,127.9				10,026.5	10,127.9	10,255.6
Reportable Business Segments [Member] | Petrochemical & Refined Products Services [Member]
Information by business segment [Abstract]
Revenues from third parties										4,111.9	6,316.5	6,258.5
Revenues from related parties										0	0	0
Intersegment and intrasegment revenues										1,126	1,779.6	1,764
Total revenues										5,237.9	8,096.1	8,022.5
Equity in income (loss) of unconsolidated affiliates										(15.7)	(13.3)	(22.3)
Gross operating margin										718.5	681	625.9
Property, plant and equipment, net		3,060.7				3,047.2				3,060.7	3,047.2	2,712.4
Investments in unconsolidated affiliates		73.9				75.1				73.9	75.1	70.4
Intangible assets, net		191.7				374.8				191.7	374.8	100
Goodwill		956.2				793				956.2	793	1,055.3
Segment assets		4,282.5				4,290.1				4,282.5	4,290.1	3,938.1
Reportable Business Segments [Member] | Offshore Pipelines And Services [Member]
Information by business segment [Abstract]
Revenues from third parties										76.9	150.3	151.7
Revenues from related parties										1.9	6.5	7.7
Intersegment and intrasegment revenues										0.6	6.5	9.6
Total revenues										79.4	163.3	169
Equity in income (loss) of unconsolidated affiliates										46.6	54	29.8
Gross operating margin										97.5	162	146.1
Property, plant and equipment, net		0				1,145.1				0	1,145.1	1,223.7
Investments in unconsolidated affiliates		0				493.7				0	493.7	531.8
Intangible assets, net		0				41.6				0	41.6	54.7
Goodwill		0				82				0	82	82.1
Segment assets		0				1,762.4				0	1,762.4	1,892.3
Adjustments [Member]
Information by business segment [Abstract]
Revenues from third parties										0	0	0
Revenues from related parties										0	0	0
Intersegment and intrasegment revenues										(17,168.6)	(29,288)	(24,052.2)
Total revenues										(17,168.6)	(29,288)	(24,052.2)
Equity in income (loss) of unconsolidated affiliates										0	0	0
Gross operating margin										0	0	0
Property, plant and equipment, net		3,894				2,754.7				3,894	2,754.7	2,655.5
Investments in unconsolidated affiliates		0				0				0	0	0
Intangible assets, net		0				0				0	0	0
Goodwill		0				0				0	0	0
Segment assets		$ 3,894				$ 2,754.7				$ 3,894	$ 2,754.7	$ 2,655.5
[1]	Losses are primarily attributable to our investment in Centennial. As a result of a trend in declining earnings, we estimated the fair value of this equity-method investment during each of the last three fiscal years. Our estimates, based on a combination of the market and income approaches, indicate that the fair value of this investment remains substantially in excess of its carrying value.
[2]	Our intangible assets classified within the Offshore Pipelines & Services segment were sold to Genesis in July 2015 (see Note 5).

Business Segments, Consolidated

Business Segments, Consolidated Revenues and Expenses (Details) - USD ($) $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Consolidated Revenues [Abstract]
Total consolidated revenues		$ 6,155	$ 6,307.9	$ 7,092.5	$ 7,472.5	$ 10,190.3	$ 12,330.2	$ 12,520.8	$ 12,909.9	$ 27,027.9	$ 47,951.2	$ 47,727
Operating costs and expenses:
Cost of sales	[1]									19,612.9	40,464.1	40,770.2
Other operating costs and expenses	[2]									2,449.4	2,541.8	2,310.4
Depreciation, amortization and accretion										1,428.2	1,282.7	1,148.9
Net losses (gains) attributable to asset sales and insurance recoveries										15.6	(102.1)	(83.4)
Non-cash asset impairment charges										162.6	34	92.6
General and administrative costs										192.6	214.5	188.3
Total costs and expenses										23,861.3	$ 44,435	$ 44,427
Shell Oil Company [Member]
Consolidated Revenues [Abstract]
Total consolidated revenues										$ 1,999.3
Shell Oil Company [Member] | Revenues [Member]
Consolidated Revenues [Abstract]
Largest non-affiliated customer percentage (in hundredths)										7.40%	8.50%
BP p.l.c. [Member] | Revenues [Member]
Consolidated Revenues [Abstract]
Largest non-affiliated customer percentage (in hundredths)												9.00%
NGL Pipelines and Services [Member]
Consolidated Revenues [Abstract]
Sales of NGLs and related products										$ 8,044.8	$ 15,460.1	$ 15,916
Midstream services										1,743.2	1,629.7	1,204.2
Total consolidated revenues										9,788	17,089.8	17,120.2
NGL Pipelines and Services [Member] | Shell Oil Company [Member]
Consolidated Revenues [Abstract]
Total consolidated revenues										400.4
Crude Oil Pipelines & Services [Member]
Consolidated Revenues [Abstract]
Sales of crude oil										9,732.9	19,783.9	20,371.3
Midstream services										573	400.4	279.1
Total consolidated revenues										10,305.9	20,184.3	20,650.4
Crude Oil Pipelines & Services [Member] | Shell Oil Company [Member]
Consolidated Revenues [Abstract]
Total consolidated revenues										1,335.8
Natural Gas Pipelines & Services [Member]
Consolidated Revenues [Abstract]
Sales of natural gas										1,722.6	3,181.7	2,571.6
Midstream services										1,020.7	1,022.1	966.9
Total consolidated revenues										2,743.3	4,203.8	3,538.5
Natural Gas Pipelines & Services [Member] | Shell Oil Company [Member]
Consolidated Revenues [Abstract]
Total consolidated revenues										48.6
Petrochemical and Refined Products Services [Member]
Consolidated Revenues [Abstract]
Sales of petrochemicals and refined products										3,333.5	5,575.5	5,568.8
Midstream services										778.4	741	689.7
Total consolidated revenues										4,111.9	6,316.5	6,258.5
Petrochemical and Refined Products Services [Member] | Shell Oil Company [Member]
Consolidated Revenues [Abstract]
Total consolidated revenues										206.5
Offshore Pipelines And Services [Member]
Consolidated Revenues [Abstract]
Sales of natural gas										0	0.3	0.5
Sales of crude oil										3.2	8.6	5.7
Midstream services										75.6	147.9	153.2
Total consolidated revenues										78.8	$ 156.8	$ 159.4
Offshore Pipelines And Services [Member] | Shell Oil Company [Member]
Consolidated Revenues [Abstract]
Total consolidated revenues										$ 8
[1]	Cost of sales is a component of "Operating costs and expenses," as presented on our 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.

Earnings Per Unit (Details)

Earnings Per Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
BASIC EARNINGS PER UNIT
Net income attributable to limited partners		$ 684.8	$ 649.3	$ 551	$ 636.1	$ 659.8	$ 691.1	$ 637.7	$ 798.8	$ 2,521.2	$ 2,787.4	$ 2,596.9
Undistributed earnings allocated and cash payments on phantom unit awards	[1]									(8.7)	(5.2)	0
Net income available to common unitholders										$ 2,512.5	$ 2,782.2	$ 2,596.9
Basic weighted-average number of common units outstanding (in units)										1,966.6	1,848.7	1,788
Basic earnings per unit (in dollars per unit)		$ 0.34	$ 0.33	$ 0.28	$ 0.33	$ 0.35	$ 0.38	$ 0.35	$ 0.44	$ 1.28	$ 1.51	$ 1.45
DILUTED EARNINGS PER UNIT
Net income attributable to limited partners		$ 684.8	$ 649.3	$ 551	$ 636.1	$ 659.8	$ 691.1	$ 637.7	$ 798.8	$ 2,521.2	$ 2,787.4	$ 2,596.9
Distribution-bearing common units (in units)										1,966.6	1,848.7	1,788
Designated Units (in units)										26.5	42.7	46.8
Class B units (in units)	[2]									0	0	5.4
Phantom units (in units)	[1]									5.4	2.9	0
Incremental option units (in units)										0.1	0.9	2.4
Total (in units)										1,998.6	1,895.2	1,842.6
Diluted earnings per unit (in dollars per unit)		$ 0.34	$ 0.32	$ 0.28	$ 0.32	$ 0.34	$ 0.37	$ 0.34	$ 0.43	$ 1.26	$ 1.47	$ 1.41
[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.
[2]	The Class B units automatically converted into an equal number of distribution-bearing common units in August 2013.

Business Combinations (Details)

Business Combinations (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended	6 Months Ended	12 Months Ended			14 Months Ended
	Feb. 28, 2015	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Feb. 13, 2015
Description of Business Combinations:
Cash paid to acquire business				$ 1,056.5	$ 2,416.8	$ 0
Intangible assets reclassified to goodwill				1,454.1
EFS Midstream Contract with Producers [Member]
Description of Business Combinations:
Contractual obligation			$ 270	$ 270
Contract term (in years)				10 years
Eagle Ford Midstream Assets [Member]
Description of Business Combinations:
Business Acquisition, Description				The EFS Midstream System includes approximately 460 miles of gathering pipelines, ten central gathering plants, 119 thousand barrels per day of condensate stabilization capacity and 780 million cubic feet per day of associated natural gas treating capacity.
Total consideration for acquisition				$ 2,056.5
Revenues from acquired assets			117.8
Net income from acquired assets			$ 59.9
Oiltanking Partners L.P. [Member]
Description of Business Combinations:
Business Acquisition, Description				Oiltanking owned marine terminals located on the Houston Ship Channel and at the Port of Beaumont with a total of 12 ship and barge docks and approximately 26 MMBbls of crude oil and petroleum products storage capacity. Oiltanking’s marine terminal on the Houston Ship Channel is connected by pipeline to our Mont Belvieu, Texas complex and is integral to our growing LPG export, crude oil storage and octane enhancement and propylene businesses. Our ECHO facility is also connected to Oiltanking’s system.
Total consideration for acquisition					$ 4,400		$ 6,020
Number of common units issued for each subordinated unit converted (in units)					1
Noncontrolling interests acquired				$ 1,400
Number of units owned upon conversion (in units)					54,799,604
Limited partner interests acquired (in hundredths)		65.90%			65.90%
Intangible assets reclassified to goodwill				$ 1,454.1
Revenues from acquired assets		$ 57.5
Net income from acquired assets		$ 8.1
Oiltanking Partners L.P. - Step 1 [Member]
Description of Business Combinations:
Common units acquired (in units)					15,899,802
Subordinated units acquired (in units)					38,899,802
Total consideration for acquisition					$ 4,609.8
Cash paid to acquire business					$ 2,210
Common units issued in connection with acquisition (in units)					54,807,352
Intangible assets reclassified to goodwill					$ 100.3
Cash paid to assume notes receivable					$ 228.3
Taxable income, goodwill amortization period (in years)					15 years
Acquisition related costs					$ 3.8
Oiltanking Partners L.P. - Step 2 [Member]
Description of Business Combinations:
Common units issued in connection with acquisition (in units)	36,827,517
Common units exchanged for each Oiltanking unit (in units)	1.3
Intangible assets reclassified to goodwill	$ 1,460

Business Combinations, Purchase

Business Combinations, Purchase Price Allocation (Details) - USD ($) $ / shares in Units, $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Jul. 02, 2015	Oct. 02, 2014	Dec. 31, 2013	Dec. 31, 2012
Liabilities assumed in business combination:
Goodwill		$ 5,745.2	$ 4,300.2			$ 2,080	$ 2,086.8
Eagle Ford Midstream Assets [Member]
Consideration:
Cash		1,069.9
Accrued liability related to EFS Midstream acquisition		986.6
Fair value of total consideration transferred		2,056.5
Indentifiable assets acquired in business combination:
Current assets, including cash				$ 64
Property, plant, and equipment				636
Identifiable intangible assets:
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 and noncontrolling interest				1,973.9
Total consideration for acquisition		$ 2,056.5
Goodwill				82.6
Business Combinations:
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
Oiltanking Partners L.P. - Step 1 [Member]
Consideration:
Cash			2,438.3
Equity instruments (54,807,352 common units of Enterprise)	[1]		2,171.5
Fair value of total consideration transferred			4,609.8
Indentifiable assets acquired in business combination:
Current assets, including cash					$ 68
Property, plant, and equipment					1,080.1
Identifiable intangible assets:
Intangible assets					2,949.1
Other assets					227.6
Total assets acquired					4,324.8
Liabilities assumed in business combination:
Current liabilities					(84.8)
Long-term debt					(223.3)
Other long-term liabilities	[2]				(230)
Total liabilities assumed					(538.1)
Noncontrolling interest in Oiltanking	[3]				(1,397.2)
Total assets acquired less liabilities assumed and noncontrolling interest					2,389.5
Total consideration for acquisition			$ 4,609.8
Goodwill					2,220.3
Business Combinations:
Cash acquired					$ 21.5
Common units issued in connection with acquisition of Oiltanking (in units)			54,807,352
Common unit price (in dollars per share)					$ 39.62
Liquidity Option Agreement					$ 219.7
Noncontrolling interests:
Inputs to calculate noncontrolling interests		28,328,890 Oiltanking common units at $49.32 per unit
Oiltanking Partners L.P. - Step 1 [Member] | Customer relationship intangibles [Member]
Identifiable intangible assets:
Intangible assets					1,192.4
Oiltanking Partners L.P. - Step 1 [Member] | Contract-based intangibles [Member]
Identifiable intangible assets:
Intangible assets					297.5
Oiltanking Partners L.P. - Step 1 [Member] | Incentive distribution rights [Member]
Identifiable intangible assets:
Intangible assets	[4]				$ 1,459.2
[1]	The fair value of the equity-based consideration paid in connection with Step 1 of the Oiltanking acquisition was based on the closing market price of our common units of $39.62 per unit on the acquisition date.
[2]	In connection with Step 1, we entered into the Liquidity Option Agreement with OTA and Marquard & Bahls ("M&B", a German corporation and ultimate parent company of OTA). Other long-term liabilities includes $219.7 million for the Liquidity Option Agreement (see Note 17).
[3]	From an accounting perspective, Enterprise acquired control of Oiltanking as a result of completing Step 1. The estimated fair value of Oiltanking's common units held by parties other than Enterprise following Step 1 (i.e., the "noncontrolling interest") is based on 28,328,890 common units held by third parties on October 1, 2014 multiplied by the closing unit price for Oiltanking common units of $49.32 per unit on that date.
[4]	The IDRs represented contractual rights to future cash incentive distributions to be paid by Oiltanking. These rights were granted to Oiltanking GP under the terms of Oiltanking's partnership agreement. Oiltanking GP could separate and sell the IDRs independent of its other residual general partner interest in Oiltanking. In February 2015 (following completion of Step 2 of the Oiltanking acquisition), the Oiltanking IDRs were cancelled and the carrying value of this intangible asset was reclassified to goodwill.

Business Combinations, Pro Form

Business Combinations, Pro Forma Earnings Data (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Basic earnings per unit [Abstract]
As reported basic units outstanding (in units)									1,966.6	1,848.7	1,788
As reported basic earnings per unit (in dollars per unit)	$ 0.34	$ 0.33	$ 0.28	$ 0.33	$ 0.35	$ 0.38	$ 0.35	$ 0.44	$ 1.28	$ 1.51	$ 1.45
Diluted earnings per unit [Abstract]
As reported diluted units outstanding (in units)									1,998.6	1,895.2	1,842.6
As reported diluted earnings per unit (in dollars per unit)	$ 0.34	$ 0.32	$ 0.28	$ 0.32	$ 0.34	$ 0.37	$ 0.34	$ 0.43	$ 1.26	$ 1.47	$ 1.41
Eagle Ford Midstream Assets [Member]
Pro forma earnings data [Abstract]
Revenues									$ 27,148.5	$ 48,180.4
Costs and expenses									23,937.1	44,583.6
Operating income									3,585	3,856.3
Net income									2,594.4	2,896.1
Net income attributable to noncontrolling interests									37.2	46.1
Net income attributable to limited partners									$ 2,557.2	$ 2,850
Basic earnings per unit [Abstract]
Pro forma basic earnings per unit (in dollars per unit)									$ 1.30	$ 1.54
Diluted earnings per unit [Abstract]
Pro forma diluted earnings per unit (in dollars per unit)									$ 1.28	$ 1.50
Oiltanking Partners L.P. [Member]
Pro forma earnings data [Abstract]
Revenues										$ 48,087.5
Costs and expenses										44,509
Operating income										3,838
Net income										2,877.5
Net income attributable to noncontrolling interests										75
Net income attributable to limited partners										$ 2,802.5
Basic earnings per unit [Abstract]
Pro forma basic units outstanding (in units)										1,903.5
Pro forma basic earnings per unit (in dollars per unit)										$ 1.47
Diluted earnings per unit [Abstract]
Pro forma diluted units outstanding (in units)										1,950
Pro forma diluted earnings per unit (in dollars per unit)										$ 1.44

Equity-Based Awards (Details)

Equity-Based Awards (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Equity-based compensation expense [Abstract]
Total compensation expense	$ 93.2	$ 87.5	$ 72.8
Equity-classified awards [Member] | Restricted Common Unit Awards [Member]
Equity-based compensation expense [Abstract]
Total compensation expense	14.7	42.1	71.5
Equity-classified awards [Member] | Phantom Unit Awards [Member]
Equity-based compensation expense [Abstract]
Total compensation expense	78.3	45.1	0
Equity-classified awards [Member] | Unit Option Awards [Member]
Equity-based compensation expense [Abstract]
Total compensation expense	0	0	0.8
Liability-classified awards [Member]
Equity-based compensation expense [Abstract]
Total compensation expense	$ 0.2	$ 0.3	$ 0.5
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
Remaining number of common units available to be issued as awards (in units)	3,073,703
Long-Term Incentive Plan (2008) [Member]
Equity-based compensation expense [Abstract]
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
Maximum number of common units that may be issued as awards (in units)	30,000,000
Remaining number of common units available to be issued as awards (in units)	16,669,007

Equity-Based Awards, Phantom Un

Equity-Based Awards, Phantom Unit Awards (Details) - USD ($) $ / shares in Units, $ in Millions		12 Months Ended
		Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Summary of awards activity, equity instruments other than options, additional disclosures [Abstract]
Cash payments made in connection with DERs		$ 7.7		$ 3.7		$ 0
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%
Summary of awards activity, equity instruments other than options [Roll Forward]
Beginning of period (in units)		3,342,390		0
Granted (in units)		3,496,140	[1]	3,530,710	[2]
Vested (in units)		(940,415)		(38,200)
Forfeited (in units)		(471,166)		(150,120)
End of period (in units)		5,426,949		3,342,390		0
Common units issued in connection with the vesting of phantom unit awards (in units)		618,395		23,311
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)	[3]	$ 33.13		$ 0
Granted weighted-average grant date fair value per unit (in dollars per unit)	[3]	33.96	[1]	33.12	[2]
Vested weighted-average grant date fair value per unit (in dollars per unit)	[3]	33.14		33.04
Forfeited weighted-average grant date fair value per unit (in dollars per unit)	[3]	33.51		33.12
Weighted-average grant date fair value per unit, at end of period (in dollars per unit)	[3]	$ 33.63		$ 33.13		$ 0
Summary of awards activity, equity instruments other than options, additional disclosures [Abstract]
Aggregate grant date fair value		$ 118.7		$ 117
Estimated forfeiture rate (in hundredths)		3.50%		3.40%
Cash payments made in connection with DERs		$ 7.7		$ 3.7		$ 0
Total intrinsic value of phantom unit awards that vested during period		31.2		$ 1.4		$ 0
Unrecognized Compensation Expense [Abstract]
Unrecognized compensation cost		$ 77
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		$ 33.04
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		$ 37.59
Phantom Unit Awards [Member] | Enterprise [Member]
Unrecognized Compensation Expense [Abstract]
Unrecognized compensation cost		$ 69.2
[1]	The aggregate grant date fair value of phantom unit awards issued during 2015 was $118.7 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]	The aggregate grant date fair value of phantom unit awards issued during 2014 was $117.0 million based on a grant date market price of our common units ranging from $33.04 to $37.59 per unit. An estimated annual forfeiture rate of 3.4% was applied to these awards.
[3]	Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued.

Equity-Based Awards, Restricted

Equity-Based Awards, Restricted Unit Awards (Details) - Restricted Common Unit Awards [Member] - USD ($) $ / shares in Units, $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting rate of restricted common unit awards (in hundredths)		25.00%
Summary of awards activity, equity instruments other than options [Roll Forward]
Beginning of period (in units)		4,229,790	7,221,214	7,786,972
Granted (in units)	[1]			3,549,052
Vested (in units)		(2,009,970)	(2,634,074)	(3,770,696)
Forfeited (in units)		(259,300)	(357,350)	(344,114)
End of period (in units)		1,960,520	4,229,790	7,221,214
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)	[2]	$ 26.96	$ 25.83	$ 20.43
Granted weighted-average grant date fair value per unit (in dollars per unit)	[1],[2]			28.61
Vested weighted-average grant date fair value per unit (in dollars per unit)	[2]	26	23.94	17.48
Forfeited weighted-average grant date fair value per unit (in dollars per unit)	[2]	27.53	26.38	23.82
Weighted-average grant date fair value per unit, at end of period (in dollars per unit)	[2]	$ 27.88	$ 26.96	$ 25.83
Summary of awards activity, equity instruments other than options, additional disclosures [Abstract]
Aggregate grant date fair value				$ 101.5
Estimated forfeiture rate (in hundredths)				3.90%
Cash distributions paid to restricted common unitholders		$ 4	$ 7.3	$ 10.6
Total intrinsic value of restricted common unit awards that vested during period		67.3	$ 87.1	$ 109.9
Unrecognized Compensation Expense [Abstract]
Unrecognized compensation cost		$ 7.2
Recognition period for total unrecognized compensation cost		1 year
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)				$ 28.56
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)				$ 31.74
Enterprise [Member]
Unrecognized Compensation Expense [Abstract]
Unrecognized compensation cost		$ 5.7
[1]	The aggregate grant date fair value of restricted common unit awards issued during 2013 was $101.5 million based on a grant date market price of our common units ranging from $28.56 to $31.74 per unit. An estimated annual forfeiture rate of 3.9% 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	12 Months Ended
	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
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)	1,270,000	[1]	4,050,000		5,522,280
Exercised (in units)	(1,270,000)		(2,720,000)		(1,472,280)
Forfeited (in units)			(60,000)
End of period (in units)	0		1,270,000	[1]	4,050,000
Options outstanding, weighted-average strike price [Roll Forward]
Weighted average strike price, beginning of period (in dollars per unit)	$ 16.14		$ 13.24		$ 13.71
Weighted average strike price, exercised (in dollars per unit)	16.14		11.83		14.98
Weighted average strike price, forfeited (in dollars per unit)			16.14
Weighted average strike price, end of period (in dollars per unit)	$ 0		$ 16.14		$ 13.24
Total intrinsic value of unit option awards exercised during period	$ 21.7		$ 57.5		$ 19.8
Cash received from EPCO in connection with the exercise of unit option awards	13.1		33.4		11.5
Unit option award-related cash reimbursements to EPCO	$ 21.7		$ 57.5		$ 19.8
[1]	All of the unit option awards outstanding at December 31, 2014 vested during 2014 and were exercised during 2015.

Derivative Instruments, Hedgi76

Derivative Instruments, Hedging Activities and Fair Value Measurements (Details) bbl in Millions, $ in Millions, ft³ in Billions		12 Months Ended
		Dec. 31, 2015USD ($)Contractbblft³	Dec. 31, 2013USD ($)Contract	Oct. 14, 2014USD ($)
Interest rate derivatives [Member] | Derivatives in cash flow hedging relationships [Member] | Forward Starting Swaps [Member]
Derivative [Line Items]
Number of derivative instruments settled | Contract			16
Notional amount of settled derivative instruments | $			$ 1,000
Accumulated other comprehensive income (loss) related to interest rate derivative instruments | $			$ (168.8)
Date through which gain or loss is amortized		March23
Interest rate derivatives [Member] | Derivatives in fair value hedging relationships [Member]
Derivative [Line Items]
Loss (gain) recognized due to settlement of derivative instruments | $				$ (27.6)
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)		0.82%
Interest rate derivatives [Member] | Derivatives in fair value hedging relationships [Member] | Senior Notes AA [Member]
Derivative [Line Items]
Loss (gain) recognized due to settlement of derivative instruments | $				(17.6)
Date through which gain or loss is amortized		Jan16
Interest rate derivatives [Member] | Derivatives in fair value hedging relationships [Member] | Senior Notes LL [Member]
Derivative [Line Items]
Loss (gain) recognized due to settlement of derivative instruments | $				$ (10)
Date through which gain or loss is amortized		Oct19
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	[1],[2]	9.1
Commodity derivatives [Member] | Derivatives in cash flow hedging relationships [Member] | Natural gas processing: Forecasted sales of NGLs [Member]
Derivative [Line Items]
Current Volume	[1],[2]	2.1
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	[1],[2]	2.4
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	[1],[2]	28.7
Long Term Volume	[1],[2]	0.4
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	[1],[2]	42.2
Long Term Volume	[1],[2]	0.1
Commodity derivatives [Member] | Derivatives in cash flow hedging relationships [Member] | Refined products marketing: Forecasted purchases of refined products [Member]
Derivative [Line Items]
Current Volume	[1],[2]	2.7
Commodity derivatives [Member] | Derivatives in cash flow hedging relationships [Member] | Refined products marketing: Forecasted sales of refined products [Member]
Derivative [Line Items]
Current Volume	[1],[2]	0.8
Long Term Volume	[1],[2]	0.1
Commodity derivatives [Member] | Derivatives in cash flow hedging relationships [Member] | Crude oil marketing: Forecasted purchases of crude oil [Member]
Derivative [Line Items]
Current Volume	[1],[2]	15
Commodity derivatives [Member] | Derivatives in cash flow hedging relationships [Member] | Crude oil marketing: Forecasted sales of crude oil [Member]
Derivative [Line Items]
Current Volume	[1],[2]	17.6
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	[1],[2]	10.7
Commodity derivatives [Member] | Derivatives in fair value hedging relationships [Member] | Refined products marketing: Refined products inventory management activities [Member]
Derivative [Line Items]
Current Volume	[1],[2]	1.3
Commodity derivatives [Member] | Derivatives in fair value hedging relationships [Member] | Crude oil marketing: Crude oil inventory management activities [Member]
Derivative [Line Items]
Current Volume	[1],[2]	0.7
Commodity derivatives [Member] | Derivatives in mark-to-market relationships [Member] | Natural gas risk management activities [Member]
Derivative [Line Items]
Current Volume | ft³	[1],[2],[3],[4]	48.2
Long Term Volume | ft³	[1],[2],[3],[4]	8.2
Current natural gas hedging volumes designated as an index plus or minus a discount | ft³		24.3
Long-term natural gas hedging volumes designated as an index plus or minus a discount | ft³		2.1
Commodity derivatives [Member] | Derivatives in mark-to-market relationships [Member] | NGL risk management activities [Member]
Derivative [Line Items]
Current Volume	[1],[2],[4]	1.8
Commodity derivatives [Member] | Derivatives in mark-to-market relationships [Member] | Crude oil risk management activities [Member]
Derivative [Line Items]
Current Volume	[1],[2],[4]	11.8
[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, January 2017 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]	Current and long-term volumes include 24.3 Bcf and 2.1 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.
[4]	Reflects the use of derivative instruments to manage risks associated with transportation, processing and storage assets.

Derivative Instruments, Hedgi77

Derivative Instruments, Hedging Activities and Fair Value Measurements, Derivative Fair Value Amounts (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Interest rate derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	$ 3.2
Liability Derivatives	3.7
Commodity derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	255.6	$ 226.6
Liability Derivatives	143	147.4
Derivatives designated as hedging instruments [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	257.2	217.9
Liability Derivatives	142.6	145.3
Derivatives designated as hedging instruments [Member] | Interest rate derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	3.2	0
Liability Derivatives	3.7	0
Derivatives designated as hedging instruments [Member] | Interest rate derivatives [Member] | Current assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	3.2	0
Derivatives designated as hedging instruments [Member] | Interest rate derivatives [Member] | Other assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	0	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	3.7	0
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	254	217.9
Liability Derivatives	138.9	145.3
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member] | Current assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	253.8	217.9
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member] | Other assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	0.2	0
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member] | Other current liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	137.5	145.3
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member] | Other liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	1.4	0
Derivatives not designated as hedging instruments [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	1.6	8.7
Liability Derivatives	4.1	2.1
Derivatives not designated as hedging instruments [Member] | Interest rate derivatives [Member] | Current assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	0	0
Derivatives not designated as hedging instruments [Member] | Interest rate derivatives [Member] | Other current liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	0	0
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	1.6	8.7
Liability Derivatives	4.1	2.1
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Current assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	1.6	8.1
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Other assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	0	0.6
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Other current liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	3.1	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, Hedgi78

Derivative Instruments, Hedging Activities and Fair Value Measurements, Asset Balance Sheet Offsetting (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Interest rate derivatives [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	$ 3.2
Gross Amounts Offset in the Balance Sheet	0
Amounts of Assets Presented in the Balance Sheet	3.2
Financial Instruments	(3.2)
Cash Collateral Paid	0
Cash Collateral Received	0
Amounts That Would Have Been Presented On Net Basis	0
Commodity derivatives [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	255.6	$ 226.6
Gross Amounts Offset in the Balance Sheet	0	0
Amounts of Assets Presented in the Balance Sheet	255.6	226.6
Financial Instruments	(143)	(147.3)
Cash Collateral Paid	(40.1)	0
Cash Collateral Received	(72.2)	(23.9)
Amounts That Would Have Been Presented On Net Basis	$ 0.3	$ 55.4

Derivative Instruments, Hedgi79

Derivative Instruments, Hedging Activities and Fair Value Measurements, Liability Balance Sheet Offsetting (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Interest rate derivatives [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	$ 3.7
Gross Amounts Offset in the Balance Sheet	0
Amounts of Liabilities Presented in the Balance Sheet	3.7
Financial Instruments	(3.2)
Cash Collateral Paid	0
Amounts That Would Have Been Presented On Net Basis	0.5
Commodity derivatives [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	143	$ 147.4
Gross Amounts Offset in the Balance Sheet	0	0
Amounts of Liabilities Presented in the Balance Sheet	143	147.4
Financial Instruments	(143)	(147.3)
Cash Collateral Paid	0	0
Amounts That Would Have Been Presented On Net Basis	$ 0	$ 0.1

Derivative Instruments, Hedgi80

Derivative Instruments, Hedging Activities and Fair Value Measurements, Gains and Losses on Derivative Instruments and Related Hedged Items (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivatives in fair value hedging relationships [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Derivative		$ 17.7	$ (14.6)	$ (13.2)
Gain (Loss) Recognized in Income on Hedged Item		1.6	14.6	7.1
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		(1.4)	(26.5)	(13.1)
Gain (Loss) Recognized in Income on Hedged Item		1.4	26.4	12.8
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		19.1	11.9	(0.1)
Gain (Loss) Recognized in Income on Hedged Item		0.2	(11.8)	(5.7)
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)		214.9	161.3	(40.3)
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income (Effective Portion)		192.9	44.3	(51.3)
Gain (Loss) Recognized in Income on Derivative (Ineffective Portion)		4.8	(0.3)	0.2
Derivatives in cash flow hedging relationships [Member] | Interest rate derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Change in Value Recognized in Other Comprehensive Income (Loss) on Derivative (Effective Portion)		0	0	6.6
Accumulated other comprehensive loss related to interest rate derivative instruments expected to be reclassified to earnings in interest expense over the next twelve months		(37.4)
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)		(35.3)	(32.4)	(29.2)
Derivatives in cash flow hedging relationships [Member] | Commodity derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Accumulated other comprehensive income (loss) related to commodity derivative instruments expected to be reclassified to earnings over the next twelve months		57.6
Accumulated other comprehensive income (loss) related to commodity derivative instruments expected to be reclassified to revenue over the next twelve months		57.3
Accumulated other comprehensive income (loss) related to commodity derivative instruments expected to be reclassified to operating costs and expenses over the next twelve months		0.3
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]	217.6	161.3	(47.9)
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income (Effective Portion)		231.7	75	(22.4)
Gain (Loss) Recognized in Income on Derivative (Ineffective Portion)		4.7	(0.3)	0.2
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]	(2.7)	0	1
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income (Effective Portion)		(3.5)	1.7	0.3
Gain (Loss) Recognized in Income on Derivative (Ineffective Portion)		0.1	0	0
Derivatives not designated as hedging instruments [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Derivative		1.1	(23.1)	6.6
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	(0.1)	(0.7)
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		1	(23)	7.3
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		$ 0.1	$ 0	$ 0
[1]	The fair value of these derivative instruments will be reclassified to their respective locations on the Statement of Consolidated Operations upon settlement of the underlying derivative transactions, as appropriate.

Derivative Instruments, Hedgi81

Derivative Instruments, Hedging Activities and Fair Value Measurements, Recurring Fair Value Measurements (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Financial liabilities [Abstract]
Liquidity Option Agreement		$ 245.1		$ 219.7
Total gains (losses) included in:
Unrealized gain (loss) recognized as a component of net income related to financial assets and liabilities		18.4		(30.6)		$ (1.4)
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Financial assets [Abstract]
Financial assets		0.9		1
Financial liabilities [Abstract]
Financial liabilities		2.5		0.6
Reconciliation of changes in the fair value of Level 3 financial assets and liabilities [Roll Forward]
Financial asset (liability) balance, net, beginning of period		(219.3)	[1]	3.2
Total gains (losses) included in:
Other comprehensive income (loss)		(19.2)		(2.6)
Settlements		0.1		(3.4)
Acquisition of Liquidity Option Agreement		0		(219.7)
Transfers out of Level 3	[1]	18		2.3
Financial asset (liability) balance, net, end of period		(246.7)	[1]	(219.3)	[1]	$ 3.2
Unrealized gain (loss) recognized as a component of net income related to financial assets and liabilities		(0.9)		(2.6)
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Location - Revenue [Member]
Total gains (losses) included in:
Net income	[2]	(0.9)		0.9
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Location - Other expense, net [Member]
Total gains (losses) included in:
Net income		(25.4)		0
Fair Value, Measurements, Recurring [Member] | Fair Value [Member]
Financial assets [Abstract]
Interest rate derivatives		3.2
Commodity derivatives		255.6		226.6
Financial assets		258.8
Financial liabilities [Abstract]
Liquidity Option Agreement		245.1		219.7
Interest rate derivatives		3.7
Commodity derivatives		143		147.4
Financial liabilities		391.8		367.1
Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 1 [Member]
Financial assets [Abstract]
Interest rate derivatives		0
Commodity derivatives		109.5		37.8
Financial assets		109.5
Financial liabilities [Abstract]
Liquidity Option Agreement		0		0
Interest rate derivatives		0
Commodity derivatives		31.3		13.8
Financial liabilities		31.3		13.8
Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 2 [Member]
Financial assets [Abstract]
Interest rate derivatives		3.2
Commodity derivatives		145.2		187.8
Financial assets		148.4
Financial liabilities [Abstract]
Liquidity Option Agreement		0		0
Interest rate derivatives		3.7
Commodity derivatives		109.2		133
Financial liabilities		112.9		133
Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 3 [Member]
Financial assets [Abstract]
Interest rate derivatives		0
Commodity derivatives		0.9		1
Financial assets		0.9
Financial liabilities [Abstract]
Liquidity Option Agreement		245.1		219.7
Interest rate derivatives		0
Commodity derivatives		2.5		0.6
Financial liabilities		$ 247.6		$ 220.3
[1]	Transfers out of Level 3 into Level 2 were due to shorter remaining transaction maturities falling inside of the Level 2 range at December 31, 2015 and 2014.
[2]	There were $0.9 million and $2.6 million of unrealized losses included in these amounts for the years ended December 31, 2015 and 2014, respectively.

Derivative Instruments, Hedgi82

Derivative Instruments, Hedging Activities and Fair Value Measurements, Level 3 Recurring Valuation Techniques (Details) - Level 3 [Member] $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)$ / bbl$ / gal	Dec. 31, 2014USD ($)$ / bbl$ / MMBTU
Asset commodity derivatives - Crude oil [Member] | Liability commodity derivatives - Crude oil [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] | Minimum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, forward commodity price (in dollars per unit) | $ / bbl	35.63	49.26
Asset commodity derivatives - Crude oil [Member] | Liability commodity derivatives - Crude oil [Member] | Maximum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, forward commodity price (in dollars per unit) | $ / bbl	43.84	53.27
Asset commodity derivatives - Propane [Member] | Liability commodity derivatives - Propane [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] | Minimum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, forward commodity price (in dollars per unit) | $ / gal	0.42
Asset commodity derivatives - Propane [Member] | Liability commodity derivatives - Propane [Member] | Maximum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, forward commodity price (in dollars per unit) | $ / gal	0.44
Assets commodity derivatives - Natural gas [Member] | Liability commodity derivatives - Natural gas [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair Value Measurements, Valuation Techniques	Discounted cash flow
Input description	Forward commodity prices
Assets commodity derivatives - Natural gas [Member] | Liability commodity derivatives - Natural gas [Member] | Minimum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, forward commodity price (in dollars per unit) | $ / MMBTU		3.05
Assets commodity derivatives - Natural gas [Member] | Liability commodity derivatives - Natural gas [Member] | Maximum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, forward commodity price (in dollars per unit) | $ / MMBTU		4.09
Fair Value, Measurements, Recurring [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Financial assets	$ 0.9	$ 1
Financial liabilities	2.5	0.6
Fair Value, Measurements, Recurring [Member] | Liability commodity derivatives - Crude oil [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Financial liabilities	1.2	0.4
Fair Value, Measurements, Recurring [Member] | Liability commodity derivatives - Natural gas [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Financial liabilities		0.2
Fair Value, Measurements, Recurring [Member] | Liability commodity derivatives - Propane [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Financial liabilities	1.3
Fair Value, Measurements, Recurring [Member] | Asset commodity derivatives - Crude oil [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Financial assets	0.9	1
Fair Value, Measurements, Recurring [Member] | Asset commodity derivatives - Propane [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Financial assets	$ 0
Fair Value, Measurements, Recurring [Member] | Assets commodity derivatives - Natural gas [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Financial assets		$ 0

Derivative Instruments, Hedgi83

Derivative Instruments, Hedging Activities and Fair Value Measurements, Nonrecurring Fair Value Measurements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015		Dec. 31, 2014	Dec. 31, 2013
Assets, Fair Value Disclosure [Abstract]
Impairment of long-lived assets disposed of other than by sale	$ 81.4		$ 26.7	$ 79.4
Impairment of long-lived assets held and used				9
Impairment of long-lived assets held for sale	14.2		3.6	3.4
Impairment of long-lived assets disposed of by sale	67	[1]	3.7	5.6
Non-cash asset impairment charges	162.6		34	97.4
Non-cash asset impairment charges in costs and expenses	162.6		34	92.6
Non-cash asset impairment charges of unconsolidated affiliate				4.8
Offshore Business [Member]
Assets, Fair Value Disclosure [Abstract]
Impairment of long-lived assets disposed of by sale	54.8
NGL Pipelines and Services [Member]
Assets, Fair Value Disclosure [Abstract]
Non-cash asset impairment charges	20.8		16.2	30.6
Crude Oil Pipelines & Services [Member]
Assets, Fair Value Disclosure [Abstract]
Non-cash asset impairment charges	33.5		2.9	30.1
Natural Gas Pipelines & Services [Member]
Assets, Fair Value Disclosure [Abstract]
Non-cash asset impairment charges	21.6		0.7	0
Petrochemical and Refined Products Services [Member]
Assets, Fair Value Disclosure [Abstract]
Non-cash asset impairment charges	28.2		9.1	18.7
Offshore Pipelines And Services [Member]
Assets, Fair Value Disclosure [Abstract]
Non-cash asset impairment charges	58.5		5.1	18
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
Fair Value, Measurements, Nonrecurring [Member] | Long-lived Assets Held and Used [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value				44.6
Fair Value, Measurements, Nonrecurring [Member] | Long-lived Assets Held For Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value	18		1.5	0.6
Fair Value, Measurements, Nonrecurring [Member] | Long-lived Assets Disposed of By Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value	0		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
Fair Value, Measurements, Nonrecurring [Member] | Level 1 [Member] | Long-lived Assets Held and Used [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value				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
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	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
Fair Value, Measurements, Nonrecurring [Member] | Level 2 [Member] | Long-lived Assets Held and Used [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value				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
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	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
Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Long-lived Assets Held and Used [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value				44.6
Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Long-lived Assets Held For Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value	18		1.5	0.6
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	$ 0
[1]	Includes a $54.8 million charge recorded in connection with the sale of our Offshore Business.

Derivative Instruments, Hedgi84

Derivative Instruments, Hedging Activities and Fair Value Measurements, Other Fair Value Measurements (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Carrying Value [Member]
Financial Liabilities: [Abstract]
Fixed Rate Debt Principal Amount Fair Value Disclosure	$ 20,870	$ 20,480
Level 2 [Member] | Fair Value [Member]
Financial Liabilities: [Abstract]
Fixed Rate Debt Principal Amount Fair Value Disclosure	$ 19,510	$ 22,160

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended		12 Months Ended
	Feb. 26, 2016	Jan. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Mar. 31, 2015
Revenues - related parties:
Total revenue - related parties			$ 72.3	$ 71.5	$ 65.9
Costs and expenses - related parties:
Total costs and expenses - related parties			1,194.6	1,122.9	1,052.2
Accounts receivable - related parties:
Total accounts receivable - related parties			1.2	2.8
Accounts payable - related parties:
Total accounts payable - related parties			84.1	118.9
Related Party Transactions [Abstract]
Operating costs and expenses			1,080.5	992.1	937.9
General and administrative expenses			114.1	130.8	114.3
Relationship with Affiliates [Abstract]
Net cash proceeds from the issuance of common units			$ 1,188.6	$ 388.8	$ 1,792
At-the-Market Registration [Member]
Relationship with Affiliates [Abstract]
Number of common units issued (in units)			25,520,424	1,590,334	15,249,378
Net cash proceeds from the issuance of common units			$ 817.4	$ 57.7	$ 456.3
Distribution Reinvestment Plan [Member]
Relationship with Affiliates [Abstract]
Number of common units issued (in units)			12,413,351	9,480,407	10,024,828
Net cash proceeds from the issuance of common units			$ 359.8	$ 321.3	$ 287.6
EPCO and affiliates [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties			949.3	939.9	892.2
Accounts payable - related parties:
Total accounts payable - related parties			75.6	98.1
Distributions:
Total cash distributions			$ 948.3	$ 877	$ 811.4
Number of Designated Units excluded from distributions (in units)			35,380,000	45,120,000	47,400,000
Relationship with Affiliates [Abstract]
Number of Units (in units)			677,159,667
Percentage of total units outstanding (in hundredths)			33.60%
Enterprise common units pledged as security (in units)			118,000,000
EPCO and affiliates [Member] | At-the-Market Registration [Member]
Relationship with Affiliates [Abstract]
Number of common units issued (in units)		3,830,256	3,225,057
Offering price of common unit (in dollars per unit)						$ 31.01
Net cash proceeds from the issuance of common units		$ 100	$ 100
EPCO and affiliates [Member] | Distribution Reinvestment Plan [Member]
Relationship with Affiliates [Abstract]
Number of common units issued (in units)	4,481,504
Net cash proceeds from the issuance of common units	$ 100		100	$ 100
EPCO and affiliates [Member] | Administrative Services Agreement [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties			931.6	923.3	$ 875.8
Related Party Transactions [Abstract]
Operating costs and expenses			826.4	801.6	770.6
General and administrative expenses			105.2	121.7	105.2
Unconsolidated affiliates [Member]
Revenues - related parties:
Total revenue - related parties			72.3	71.5	65.9
Costs and expenses - related parties:
Total costs and expenses - related parties			245.3	183	160
Accounts receivable - related parties:
Total accounts receivable - related parties			1.2	2.8
Accounts payable - related parties:
Total accounts payable - related parties			8.5	20.8
Unconsolidated affiliates [Member] | Seaway Crude Pipeline Company [Member]
Revenues - related parties:
Total revenue - related parties			47.7	29.4	41.3
Costs and expenses - related parties:
Total costs and expenses - related parties			175.8	130.8	132.4
Unconsolidated affiliates [Member] | K/D/S Promix, L.L.C. [Member]
Revenues - related parties:
Total revenue - related parties			8.8	11.1	9.8
Costs and expenses - related parties:
Total costs and expenses - related parties			24.9	25.8	28.1
Unconsolidated affiliates [Member] | Eagle Ford Pipeline LLC [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties			39.4	25.8	5.4
Unconsolidated affiliates [Member] | Other investments in unconsolidated subsidiaries [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties			$ 19.1	$ 24.5	$ 21.8

Provision for Income Taxes (Det

Provision for Income Taxes (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current:
Federal		$ 0.9	$ 2.2	$ (0.5)
State		15.5	13.4	19.3
Foreign		1.7	1.4	0.8
Total current		18.1	17	19.6
Deferred:
Federal		(1.4)	2.2	(0.5)
State		(19.2)	3.5	38.9
Foreign		0	0.4	(0.5)
Total deferred		(20.6)	6.1	37.9
Total provision for (benefit from) income taxes		(2.5)	23.1	57.5
Reconciliation of the provision for (benefit from) income taxes [Abstract]
Pre-Tax Net Book Income ("NBI")		2,555.9	2,856.6	2,664.6
Texas Margin Tax	[1]	(3.7)	17.5	58.3
State income taxes (net of federal benefit)		0.7	0.2	(0.1)
Federal income taxes computed by applying the federal statutory rate to NBI of corporate entities		1.1	1.5	(1.4)
Expiration of tax net operating loss		0	0	0.1
Other permanent differences		(0.6)	3.9	0.6
Total provision for (benefit from) income taxes		$ (2.5)	$ 23.1	$ 57.5
Effective income tax rate (in hundredths)		(0.10%)	0.80%	2.20%
Deferred tax assets:
Net operating loss carryovers	[2]	$ 0.2	$ 0.3
Accruals		1.6	1.8
Total deferred tax assets		1.8	2.1
Less: Deferred tax liabilities:
Property, plant and equipment		44.9	64.4
Equity investment in partnerships		2.7	4.1
Total deferred tax liabilities		47.6	68.5
Total net deferred tax liabilities		45.8	66.4
Current portion of total net deferred tax assets		0.3	0.2
Long-term portion of total net deferred tax liabilities		$ 46.1	$ 66.6
[1]	Although the Texas Margin Tax is not considered a state income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers our Texas-sourced revenues and expenses. During 2015, certain legislative changes were enacted to the Texas Margin Tax, which reduced the tax rate for business entities that operate within the state.
[2]	These losses expire in various years between 2016 and 2033 and are subject to limitations on their utilization.

Commitments and Contingencies87

Commitments and Contingencies (Details) bbl in Millions, $ in Millions, BTU in Trillions	12 Months Ended
	Dec. 31, 2015USD ($)BTUbbl	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Redelivery commitments [Abstract]
Redelivery commitments of natural gas (in TBtus) | BTU	10.2
Redelivery commitments of crude oil (in MMBbls) | bbl	18.7
Redelivery commitments of NGL and petrochemical products (in MMBbls) | bbl	37.5
Operating lease obligations [Abstract]
Minimum term of material lease agreements (in years)	5 years
Maximum term of material lease agreements (in years)	30 years
Renewal option years for certain leases (in years)	20 years
Lease and rental expense included in costs and expenses	$ 104.3	$ 94.2	$ 87.6
Liabilities, Other than Long-term Debt, Noncurrent [Abstract]
Noncurrent portion of AROs	52.9	83.2
Deferred revenues - non-current portion	78.3	73
Liquidity Option Agreement	245.1	219.7
Centennial guarantees	6.1	7
Other	29.1	28.2
Total	411.5	411.1
Junior Subordinated Note [Member]
Debt Instrument [Line Items]
Debt obligations	1,470
Centennial Pipeline LLC [Member]
Debt Instrument [Line Items]
Debt obligations	67.2
Litigation matters [Member]
Loss Contingencies [Line Items]
Litigation accruals on an undiscounted basis	4.6	$ 2.4
Litigation matters [Member] | ETP Lawsuit [Member]
Loss Contingencies [Line Items]
Loss contingency, total damages sought	535.8
Loss contingency, damages awarded	319.4
Loss contingency, disgorgement damages sought	150
Prejudgment interest	$ 66.4
Post-judgment interest rate (in hundredths)	5.00%
Centennial debt guarantee [Member]
Guarantor Obligations [Line Items]
Percentage of debt obligations guaranteed (in hundredths)	50.00%
Guarantee of debt obligations	$ 33.6
Fair value of debt guarantee	4.9
Centennial cash call guarantee [Member]
Guarantor Obligations [Line Items]
Cash call guarantee	50
Fair value of cash call guarantee	$ 2.1

Commitments and Contingencies,

Commitments and Contingencies, Contractual Obligations (Details) bbl in Millions, $ in Millions, BTU in Trillions	12 Months Ended
	Dec. 31, 2015USD ($)bblBTU	Dec. 31, 2014USD ($)
Scheduled maturities of debt obligations [Abstract]
2,016	$ 1,864.1
2,017	800
2,018	1,100
2,019	1,500
2,020	1,500
Thereafter	15,974.4
Total	22,738.5	$ 21,389.2
Estimated cash interest payments [Abstract]
2,016	1,053
2,017	1,036.1
2,018	975.6
2,019	917.5
2,020	859.7
Thereafter	16,892.2
Total	21,734.1
Operating lease obligations [Abstract]
2,016	64.2
2,017	58.4
2,018	50.3
2,019	44.7
2,020	41
Thereafter	235.4
Total	494
Natural Gas [Member]
Estimated payment obligations:
2,016	451.3
2,017	215.6
2,018	215.6
2,019	143.8
2,020	73.5
Thereafter	61
Total	$ 1,160.8
Underlying major volume commitments:
2016 | BTU	243
2017 | BTU	128
2018 | BTU	128
2019 | BTU	81
2020 | BTU	37
Thereafter | BTU	30
Total | BTU	647
NGLs [Member]
Estimated payment obligations:
2,016	$ 319.3
2,017	21.8
2,018	23.9
2,019	11.9
2,020	0
Thereafter	0
Total	$ 376.9
Underlying major volume commitments:
2016 | bbl	30
2017 | bbl	3
2018 | bbl	4
2019 | bbl	2
2020 | bbl	0
Thereafter | bbl	0
Total | bbl	39
Crude Oil [Member]
Estimated payment obligations:
2,016	$ 389.4
2,017	17.9
2,018	17.9
2,019	16.3
2,020	0
Thereafter	0
Total	$ 441.5
Underlying major volume commitments:
2016 | bbl	11
2017 | bbl	1
2018 | bbl	1
2019 | bbl	1
2020 | bbl	0
Thereafter | bbl	0
Total | bbl	14
Petrochemicals And Refined Products [Member]
Estimated payment obligations:
2,016	$ 1,868.6
2,017	52.8
2,018	0
2,019	0
2,020	0
Thereafter	0
Total	$ 1,921.4
Underlying major volume commitments:
2016 | bbl	126
2017 | bbl	20
2018 | bbl	0
2019 | bbl	0
2020 | bbl	0
Thereafter | bbl	0
Total | bbl	146
Estimated Payment Obligations Other [Member]
Estimated payment obligations:
2,016	$ 8.7
2,017	6.9
2,018	4.1
2,019	4.1
2,020	2.7
Thereafter	6.7
Total	33.2
Service Payment Commitments [Member]
Estimated payment obligations:
2,016	184.5
2,017	160.1
2,018	91.8
2,019	71.1
2,020	43.7
Thereafter	134.7
Total	685.9
Capital Expenditure Commitments [Member]
Estimated payment obligations:
2,016	113.9
2,017	0
2,018	0
2,019	0
2,020	0
Thereafter	0
Total	113.9
EFS Midstream Contract with Producers [Member]
Contractual obligation [Line Items]
Contractual obligation	$ 270
Contract term (in years)	10 years

Commitments and Contingencies89

Commitments and Contingencies, Liquidity Option Agreement (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Oct. 02, 2014
Liquidity Option Agreement [Abstract]
Purchase price adjustment to goodwill	$ 1,454.1
Change in fair value of Liquidity Option Agreement	$ 25.4	$ 0	$ 0
Liquidity Option Agreement [Member]
Liquidity Option Agreement [Abstract]
Other Commitments, Description	In connection with Step 1 of the Oiltanking acquisition, we entered into the Liquidity Option Agreement (“Liquidity Option”) with OTA and M&B, whereby 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. The aggregate consideration to be paid by us for OTA’s capital stock would equal 100% of the then-current fair market value of the Enterprise common units owned by OTA at the exercise date. If a Trigger Event occurs (as defined in the underlying agreements), the Liquidity Option may be exercised earlier within a 135-day period following notice of such event.
Level 3 [Member] | Liquidity Option Agreement [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, assumed long-term debt	$ 2,200
Fair value inputs, Interest rate on assumed debt of OTA following option exercise	6.4% over 30 years
Fair value inputs, federal and state tax rate (in hundredths)	38.00%
Cash flow projections discount rate (in hundredths)	7.50%
Fair value inputs, weighted-average expected ownership percentage of contributed units at beginning of option period (in hundredths)	0.789
Liquidity Option Agreement [Abstract]
Liquidity Option Agreement	$ 245.1	$ 219.7
Level 3 [Member] | 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
Fair value inputs, Estimated growth rates in Enterprise earnings before interest, taxes, depreciation and amortization (in hundredths)	2.00%
Fair value inputs, OTA ownership interest in Enterprise common units (in hundredths)	1.90%
Fair value inputs, Forecasted yield on Enterprise common units (in hundredths)	5.80%
Level 3 [Member] | 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
Fair value inputs, Estimated growth rates in Enterprise earnings before interest, taxes, depreciation and amortization (in hundredths)	15.00%
Fair value inputs, OTA ownership interest in Enterprise common units (in hundredths)	2.70%
Fair value inputs, Forecasted yield on Enterprise common units (in hundredths)	6.60%
Oiltanking Partners L.P. - Step 1 [Member]
Business Acquisition [Line Items]
Common units issued in connection with acquisition (in units)		54,807,352
Liquidity Option Agreement [Abstract]
Liquidity Option Agreement				$ 219.7
Liquidity Option Agreement valuation adjustment		$ 100.3
Purchase price adjustment to goodwill		$ 100.3

Significant Risks and Uncerta90

Significant Risks and Uncertainties (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Insurance Matters [Abstract]
Insurance deductible per incident	$ 55
Minimum business interruption period (in days)	60 days
February 2011 West Storage Incident [Member]
Loss Contingencies [Line Items]
Gains related to property damage proceeds		$ 95	$ 15
Proceeds from property damage insurance recoveries		$ 95	$ 15

Supplemental Cash Flow Inform91

Supplemental Cash Flow Information (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Decrease (increase) in:
Accounts receivable - trade		$ 1,279.3	$ 1,685.4	$ (1,136.2)
Accounts receivable - related parties		1.3	3.8	(3.6)
Inventories		(72.7)	(105.6)	38.6
Prepaid and other current assets		(59.1)	(74.6)	(6.3)
Other assets		(5.8)	18.7	2.4
Increase (decrease) in:
Accounts payable - trade		(52.9)	(141)	(10.1)
Accounts payable - related parties		(34.8)	(31.6)	23.6
Accrued product payables		(1,342.4)	(1,647.8)	1,043.8
Accrued interest		16.5	31.3	3.5
Other current liabilities		(67.1)	141.3	(35.1)
Other liabilities		14.4	11.9	(18.2)
Net effect of changes in operating accounts		(323.3)	(108.2)	(97.6)
Cash payments for interest, net of $149.1, $77.9 and $133.0 capitalized in 2015, 2014 and 2013, respectively		911.6	832.1	781.5
Capitalized interest	[1]	149.1	77.9	133
Cash payments for federal and state income taxes		17.5	16.1	35
Liability for construction in progress expenditures		472.8	372.8	205.3
Accrued liability related to EFS Midstream acquisition		993.2	0
Significant Acquisitions and Disposals [Line Items]
Proceeds from asset sales and insurance recoveries		1,608.6	145.3	280.6
Net gains (losses) attributable to asset sales and insurance recoveries		(15.6)	102.1	83.3
Offshore Business [Member]
Significant Acquisitions and Disposals [Line Items]
Proceeds from asset sales and insurance recoveries		1,527.7	0	0
Net gains (losses) attributable to asset sales and insurance recoveries		(12.3)	0	0
West Storage Facilities [Member]
Significant Acquisitions and Disposals [Line Items]
Proceeds from asset sales and insurance recoveries		0	95	15
Net gains (losses) attributable to asset sales and insurance recoveries		0	95	15
Other Disposal of Assets [Member]
Significant Acquisitions and Disposals [Line Items]
Proceeds from asset sales and insurance recoveries		80.9	50.3	265.6
Net gains (losses) attributable to asset sales and insurance recoveries		$ (3.3)	$ 7.1	$ 68.3
[1]	Capitalized interest is a component of "Interest expense" as presented on our Statements of Consolidated Operations.

Quarterly Financial Informati92

Quarterly Financial Information (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information (Unaudited) [Abstract]
Revenues	$ 6,155	$ 6,307.9	$ 7,092.5	$ 7,472.5	$ 10,190.3	$ 12,330.2	$ 12,520.8	$ 12,909.9	$ 27,027.9	$ 47,951.2	$ 47,727
Operating income	934.5	909.4	800.3	896	921	937.7	884.3	1,032.7	3,540.2	3,775.7	3,467.3
Net income	693.5	657.7	556.6	650.6	681.1	699.2	646.5	806.7	2,558.4	2,833.5	2,607.1
Net income attributable to limited partners	$ 684.8	$ 649.3	$ 551	$ 636.1	$ 659.8	$ 691.1	$ 637.7	$ 798.8	$ 2,521.2	$ 2,787.4	$ 2,596.9
Earnings per unit:
Basic earnings per unit (in dollars per unit)	$ 0.34	$ 0.33	$ 0.28	$ 0.33	$ 0.35	$ 0.38	$ 0.35	$ 0.44	$ 1.28	$ 1.51	$ 1.45
Diluted earnings per unit (in dollars per unit)	$ 0.34	$ 0.32	$ 0.28	$ 0.32	$ 0.34	$ 0.37	$ 0.34	$ 0.43	$ 1.26	$ 1.47	$ 1.41

Condensed Consolidating Finan93

Condensed Consolidating Financial Information, Balance Sheets (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents and restricted cash	$ 34.9	$ 74.4
Accounts receivable - trade, net	2,569.9	3,823
Accounts receivable - related parties	1.2	2.8
Inventories	1,038.1	1,014.2
Derivative assets	258.6	226
Prepaid and other current assets	410.3	350.3
Total current assets	4,313	5,490.7
Property, plant and equipment, net	32,034.7	29,881.6	$ 26,946.6
Investments in unconsolidated affiliates	2,628.5	3,042
Intangible assets, net	4,037.2	4,302.1	1,462.2
Goodwill	5,745.2	4,300.2	2,080	$ 2,086.8
Other assets	193.4	184.4
Total assets	48,952	47,201
Current liabilities:
Current maturities of debt	1,863.9	2,206.4
Accounts payable - trade	860.1	773.8
Accounts payable - related parties	84.1	118.9
Accrued product payables	2,484.4	3,853.3
Accrued liability related to EFS Midstream acquisition	993.2	0
Accrued interest	352.1	335.5
Other current liabilities	528.8	585.8
Total current liabilities	7,166.6	7,873.7
Long-term debt	20,826.7	19,157.4
Deferred tax liabilities	46.1	66.6
Other long-term liabilities	$ 411.5	$ 411.1
Commitments and contingencies
Equity:
Partners' and other owners' equity	$ 20,295.1	$ 18,063.2
Noncontrolling interests	206	1,629
Total equity	20,501.1	19,692.2	$ 15,440.4	$ 13,296
Total liabilities and equity	48,952	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	(0.2)	(4)
Inventories	0	0
Derivative assets	0	0
Prepaid and other current assets	0	0.8
Total current assets	(0.2)	(3.2)
Property, plant and equipment, net	0	0
Investments in unconsolidated affiliates	(20,540.2)	(18,287.5)
Intangible assets, net	0	0
Goodwill	0	0
Other assets	0	0
Total assets	(20,540.4)	(18,290.7)
Current liabilities:
Current maturities of debt	0	0
Accounts payable - trade	0	0
Accounts payable - related parties	(0.2)	(4)
Accrued product payables	0	0
Accrued liability related to EFS Midstream acquisition	0
Accrued interest	0	0
Other current liabilities	0	0
Total current liabilities	(0.2)	(4)
Long-term debt	0	0
Deferred tax liabilities	2.7	4.1
Other long-term liabilities	$ 0	$ 0
Commitments and contingencies
Equity:
Partners' and other owners' equity	$ (20,514.3)	$ (18,263.7)
Noncontrolling interests	(28.6)	(27.1)
Total equity	(20,542.9)	(18,290.8)
Total liabilities and equity	(20,540.4)	(18,290.7)
Subsidiary Issuer (EPO) [Member]
Current assets:
Cash and cash equivalents and restricted cash	14.4	18.7
Accounts receivable - trade, net	811.3	1,128.5
Accounts receivable - related parties	59	158.8
Inventories	786.9	831.8
Derivative assets	150.4	102
Prepaid and other current assets	168.3	435.7
Total current assets	1,990.3	2,675.5
Property, plant and equipment, net	3,859.8	2,871.7
Investments in unconsolidated affiliates	38,655	36,937.5
Intangible assets, net	721.2	2,527.3
Goodwill	459.5	1,956.1
Other assets	280.2	139.3
Total assets	45,966	47,107.4
Current liabilities:
Current maturities of debt	1,863.8	2,206.4
Accounts payable - trade	375.3	216.6
Accounts payable - related parties	885.3	1,226.5
Accrued product payables	997.7	1,570
Accrued liability related to EFS Midstream acquisition	0
Accrued interest	352	335.4
Other current liabilities	178.7	130.8
Total current liabilities	4,652.8	5,685.7
Long-term debt	20,811.4	19,142.5
Deferred tax liabilities	3.4	4.9
Other long-term liabilities	$ 14.5	$ 10.9
Commitments and contingencies
Equity:
Partners' and other owners' equity	$ 20,483.9	$ 22,263.4
Noncontrolling interests	0	0
Total equity	20,483.9	22,263.4
Total liabilities and equity	45,966	47,107.4
Other Subsidiaries (Non-guarantor) [Member]
Current assets:
Cash and cash equivalents and restricted cash	71.1	70.4
Accounts receivable - trade, net	1,755.8	2,698.2
Accounts receivable - related parties	795.4	1,114.6
Inventories	251.4	182.8
Derivative assets	108.2	124
Prepaid and other current assets	249.1	222.3
Total current assets	3,231	4,412.3
Property, plant and equipment, net	28,173.5	26,912
Investments in unconsolidated affiliates	4,067.3	3,556.4
Intangible assets, net	3,330.7	1,292.4
Goodwill	5,285.7	1,721.4
Other assets	47.9	45.8
Total assets	44,136.1	37,940.3
Current liabilities:
Current maturities of debt	0.1	0
Accounts payable - trade	535.1	571.4
Accounts payable - related parties	62.3	173.3
Accrued product payables	1,489.3	2,287.9
Accrued liability related to EFS Midstream acquisition	993.2
Accrued interest	0.1	0.7
Other current liabilities	357.1	763.7
Total current liabilities	3,437.2	3,797
Long-term debt	15.3	14.9
Deferred tax liabilities	40.8	58.5
Other long-term liabilities	$ 286.9	$ 180.8
Commitments and contingencies
Equity:
Partners' and other owners' equity	$ 40,297.2	$ 33,820.9
Noncontrolling interests	58.7	68.2
Total equity	40,355.9	33,889.1
Total liabilities and equity	44,136.1	37,940.3
Consolidated EPO and Subsidiaries [Member]
Current assets:
Cash and cash equivalents and restricted cash	34.9	74.4
Accounts receivable - trade, net	2,569.9	3,823
Accounts receivable - related parties	1.4	6.8
Inventories	1,038.1	1,014.2
Derivative assets	258.6	226
Prepaid and other current assets	410.3	349.5
Total current assets	4,313.2	5,493.9
Property, plant and equipment, net	32,034.7	29,881.6
Investments in unconsolidated affiliates	2,628.5	3,042
Intangible assets, net	4,037.2	4,302.1
Goodwill	5,745.2	4,300.2
Other assets	192.9	184.4
Total assets	48,951.7	47,204.2
Current liabilities:
Current maturities of debt	1,863.9	2,206.4
Accounts payable - trade	859.8	773.2
Accounts payable - related parties	84.1	118.9
Accrued product payables	2,484.4	3,853.3
Accrued liability related to EFS Midstream acquisition	993.2
Accrued interest	352.1	335.5
Other current liabilities	528.8	585.8
Total current liabilities	7,166.3	7,873.1
Long-term debt	20,826.7	19,157.4
Deferred tax liabilities	43.4	62.5
Other long-term liabilities	$ 166.4	$ 191.4
Commitments and contingencies
Equity:
Partners' and other owners' equity	$ 20,514.3	$ 18,263.7
Noncontrolling interests	234.6	1,656.1
Total equity	20,748.9	19,919.8
Total liabilities and equity	48,951.7	47,204.2
Consolidated EPO and Subsidiaries [Member] | Eliminations and Adjustments [Member]
Current assets:
Cash and cash equivalents and restricted cash	(50.6)	(14.7)
Accounts receivable - trade, net	2.8	(3.7)
Accounts receivable - related parties	(853)	(1,266.6)
Inventories	(0.2)	(0.4)
Derivative assets	0	0
Prepaid and other current assets	(7.1)	(308.5)
Total current assets	(908.1)	(1,593.9)
Property, plant and equipment, net	1.4	97.9
Investments in unconsolidated affiliates	(40,093.8)	(37,451.9)
Intangible assets, net	(14.7)	482.4
Goodwill	0	622.7
Other assets	(135.2)	(0.7)
Total assets	(41,150.4)	(37,843.5)
Current liabilities:
Current maturities of debt	0	0
Accounts payable - trade	(50.6)	(14.8)
Accounts payable - related parties	(863.5)	(1,280.9)
Accrued product payables	(2.6)	(4.6)
Accrued liability related to EFS Midstream acquisition	0
Accrued interest	0	(0.6)
Other current liabilities	(7)	(308.7)
Total current liabilities	(923.7)	(1,609.6)
Long-term debt	0	0
Deferred tax liabilities	(0.8)	(0.9)
Other long-term liabilities	$ (135)	$ (0.3)
Commitments and contingencies
Equity:
Partners' and other owners' equity	$ (40,266.8)	$ (37,820.6)
Noncontrolling interests	175.9	1,587.9
Total equity	(40,090.9)	(36,232.7)
Total liabilities and equity	(41,150.4)	(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	0
Total current assets	0	0
Property, plant and equipment, net	0	0
Investments in unconsolidated affiliates	20,540.2	18,287.5
Intangible assets, net	0	0
Goodwill	0	0
Other assets	0.5	0
Total assets	20,540.7	18,287.5
Current liabilities:
Current maturities of debt	0	0
Accounts payable - trade	0.3	0.6
Accounts payable - related parties	0.2	4
Accrued product payables	0	0
Accrued liability related to EFS Midstream acquisition	0
Accrued interest	0	0
Other current liabilities	0	0
Total current liabilities	0.5	4.6
Long-term debt	0	0
Deferred tax liabilities	0	0
Other long-term liabilities	$ 245.1	$ 219.7
Commitments and contingencies
Equity:
Partners' and other owners' equity	$ 20,295.1	$ 18,063.2
Noncontrolling interests	0	0
Total equity	20,295.1	18,063.2
Total liabilities and equity	$ 20,540.7	$ 18,287.5

Condensed Consolidating Finan94

Condensed Consolidating Financial Information, Statements of Operations (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Condensed Consolidating Statement of Operations
Revenues	$ 6,155	$ 6,307.9	$ 7,092.5	$ 7,472.5	$ 10,190.3	$ 12,330.2	$ 12,520.8	$ 12,909.9	$ 27,027.9	$ 47,951.2	$ 47,727
Costs and expenses:
Operating costs and expenses									23,668.7	44,220.5	44,238.7
General and administrative costs									192.6	214.5	188.3
Total costs and expenses									23,861.3	44,435	44,427
Equity in income of unconsolidated affiliates									373.6	259.5	167.3
Operating income	934.5	909.4	800.3	896	921	937.7	884.3	1,032.7	3,540.2	3,775.7	3,467.3
Other income (expense):
Interest expense									(961.8)	(921)	(802.5)
Other, net									(22.5)	1.9	(0.2)
Total other expense, net									(984.3)	(919.1)	(802.7)
Income before income taxes									2,555.9	2,856.6	2,664.6
Benefit from (provision for) income taxes									2.5	(23.1)	(57.5)
Net income	693.5	657.7	556.6	650.6	681.1	699.2	646.5	806.7	2,558.4	2,833.5	2,607.1
Net loss (income) attributable to noncontrolling interests									(37.2)	(46.1)	(10.2)
Net income attributable to entity	$ 684.8	$ 649.3	$ 551	$ 636.1	$ 659.8	$ 691.1	$ 637.7	$ 798.8	2,521.2	2,787.4	2,596.9
Eliminations and Adjustments [Member]
Condensed Consolidating Statement of Operations
Revenues									0	0	0
Costs and expenses:
Operating costs and expenses									0	0	0
General and administrative costs									0	0	0
Total costs and expenses									0	0	0
Equity in income of unconsolidated affiliates									(2,548.7)	(2,789.6)	(2,599.1)
Operating income									(2,548.7)	(2,789.6)	(2,599.1)
Other income (expense):
Interest expense									0	0	0
Other, net									0	0	0
Total other expense, net									0	0	0
Income before income taxes									(2,548.7)	(2,789.6)	(2,599.1)
Benefit from (provision for) income taxes									(1.5)	(2)	(1)
Net income									(2,550.2)	(2,791.6)	(2,600.1)
Net loss (income) attributable to noncontrolling interests									4.8	5	3.9
Net income attributable to entity									(2,545.4)	(2,786.6)	(2,596.2)
Subsidiary Issuer (EPO) [Member]
Condensed Consolidating Statement of Operations
Revenues									20,104.8	32,468.5	30,007.4
Costs and expenses:
Operating costs and expenses									19,283.7	31,579.2	29,176.7
General and administrative costs									38.2	39.1	29.1
Total costs and expenses									19,321.9	31,618.3	29,205.8
Equity in income of unconsolidated affiliates									2,718.4	2,865.2	2,609
Operating income									3,501.3	3,715.4	3,410.6
Other income (expense):
Interest expense									(952.9)	(921.3)	(800.8)
Other, net									5.2	3.4	0.3
Total other expense, net									(947.7)	(917.9)	(800.5)
Income before income taxes									2,553.6	2,797.5	2,610.1
Benefit from (provision for) income taxes									(8.7)	(11.5)	(13.9)
Net income									2,544.9	2,786	2,596.2
Net loss (income) attributable to noncontrolling interests									0	0	0
Net income attributable to entity									2,544.9	2,786	2,596.2
Other Subsidiaries (Non-guarantor) [Member]
Condensed Consolidating Statement of Operations
Revenues									19,087	32,488.2	31,641.3
Costs and expenses:
Operating costs and expenses									16,549.3	29,647.6	28,983.7
General and administrative costs									152.3	173.2	157
Total costs and expenses									16,701.6	29,820.8	29,140.7
Equity in income of unconsolidated affiliates									417.5	354.3	204.8
Operating income									2,802.9	3,021.7	2,705.4
Other income (expense):
Interest expense									(12)	(2.5)	(1.7)
Other, net									0.8	1.3	(0.5)
Total other expense, net									(11.2)	(1.2)	(2.2)
Income before income taxes									2,791.7	3,020.5	2,703.2
Benefit from (provision for) income taxes									12.7	(9.8)	(42.6)
Net income									2,804.4	3,010.7	2,660.6
Net loss (income) attributable to noncontrolling interests									0.9	0.4	(1.2)
Net income attributable to entity									2,805.3	3,011.1	2,659.4
Consolidated EPO and Subsidiaries [Member]
Condensed Consolidating Statement of Operations
Revenues									27,027.9	47,951.2	47,727
Costs and expenses:
Operating costs and expenses									23,668.7	44,220.5	44,238.7
General and administrative costs									190.5	212.3	186.1
Total costs and expenses									23,859.2	44,432.8	44,424.8
Equity in income of unconsolidated affiliates									373.6	259.5	167.3
Operating income									3,542.3	3,777.9	3,469.5
Other income (expense):
Interest expense									(961.8)	(921)	(802.5)
Other, net									2.9	1.9	(0.2)
Total other expense, net									(958.9)	(919.1)	(802.7)
Income before income taxes									2,583.4	2,858.8	2,666.8
Benefit from (provision for) income taxes									4	(21.1)	(56.5)
Net income									2,587.4	2,837.7	2,610.3
Net loss (income) attributable to noncontrolling interests									(42)	(51.1)	(14.1)
Net income attributable to entity									2,545.4	2,786.6	2,596.2
Consolidated EPO and Subsidiaries [Member] | Eliminations and Adjustments [Member]
Condensed Consolidating Statement of Operations
Revenues									(12,163.9)	(17,005.5)	(13,921.7)
Costs and expenses:
Operating costs and expenses									(12,164.3)	(17,006.3)	(13,921.7)
General and administrative costs									0	0	0
Total costs and expenses									(12,164.3)	(17,006.3)	(13,921.7)
Equity in income of unconsolidated affiliates									(2,762.3)	(2,960)	(2,646.5)
Operating income									(2,761.9)	(2,959.2)	(2,646.5)
Other income (expense):
Interest expense									3.1	2.8	0
Other, net									(3.1)	(2.8)	0
Total other expense, net									0	0	0
Income before income taxes									(2,761.9)	(2,959.2)	(2,646.5)
Benefit from (provision for) income taxes									0	0.2	0
Net income									(2,761.9)	(2,959)	(2,646.5)
Net loss (income) attributable to noncontrolling interests									(42.9)	(51.5)	(12.9)
Net income attributable to entity									(2,804.8)	(3,010.5)	(2,659.4)
Enterprise Products Partners L.P. (Guarantor) [Member]
Condensed Consolidating Statement of Operations
Revenues									0	0	0
Costs and expenses:
Operating costs and expenses									0	0	0
General and administrative costs									2.1	2.2	2.2
Total costs and expenses									2.1	2.2	2.2
Equity in income of unconsolidated affiliates									2,548.7	2,789.6	2,599.1
Operating income									2,546.6	2,787.4	2,596.9
Other income (expense):
Interest expense									0	0	0
Other, net									(25.4)	0	0
Total other expense, net									(25.4)	0	0
Income before income taxes									2,521.2	2,787.4	2,596.9
Benefit from (provision for) income taxes									0	0	0
Net income									2,521.2	2,787.4	2,596.9
Net loss (income) attributable to noncontrolling interests									0	0	0
Net income attributable to entity									$ 2,521.2	$ 2,787.4	$ 2,596.9

Condensed Consolidating Finan95

Condensed Consolidating Financial Information, Statements of Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Condensed Consolidating Statement of Comprehensive Income
Comprehensive income	$ 2,580.8	$ 2,950.9	$ 2,618.5
Comprehensive loss (income) attributable to noncontrolling interests	(37.2)	(46.1)	(10.2)
Comprehensive income attributable to entity	2,543.6	2,904.8	2,608.3
Eliminations and Adjustments [Member]
Condensed Consolidating Statement of Comprehensive Income
Comprehensive income	(2,572.6)	(2,909)	(2,611.4)
Comprehensive loss (income) attributable to noncontrolling interests	4.8	5	3.9
Comprehensive income attributable to entity	(2,567.8)	(2,904)	(2,607.5)
Subsidiary Issuer (EPO) [Member]
Condensed Consolidating Statement of Comprehensive Income
Comprehensive income	2,578.6	2,856.4	2,616.5
Comprehensive loss (income) attributable to noncontrolling interests	0	0	0
Comprehensive income attributable to entity	2,578.6	2,856.4	2,616.5
Other Subsidiaries (Non-guarantor) [Member]
Condensed Consolidating Statement of Comprehensive Income
Comprehensive income	2,793.1	3,057.6	2,651.6
Comprehensive loss (income) attributable to noncontrolling interests	0.9	0.4	(1.2)
Comprehensive income attributable to entity	2,794	3,058	2,650.4
Consolidated EPO and Subsidiaries [Member]
Condensed Consolidating Statement of Comprehensive Income
Comprehensive income	2,609.8	2,955.1	2,621.6
Comprehensive loss (income) attributable to noncontrolling interests	(42)	(51.1)	(14.1)
Comprehensive income attributable to entity	2,567.8	2,904	2,607.5
Consolidated EPO and Subsidiaries [Member] | Eliminations and Adjustments [Member]
Condensed Consolidating Statement of Comprehensive Income
Comprehensive income	(2,761.9)	(2,958.9)	(2,646.5)
Comprehensive loss (income) attributable to noncontrolling interests	(42.9)	(51.5)	(12.9)
Comprehensive income attributable to entity	(2,804.8)	(3,010.4)	(2,659.4)
Enterprise Products Partners L.P. (Guarantor) [Member]
Condensed Consolidating Statement of Comprehensive Income
Comprehensive income	2,543.6	2,904.8	2,608.3
Comprehensive loss (income) attributable to noncontrolling interests	0	0	0
Comprehensive income attributable to entity	$ 2,543.6	$ 2,904.8	$ 2,608.3

Condensed Consolidating Finan96

Condensed Consolidating Financial Information, Statements of Cash Flows (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating activities:
Net income	$ 693,500	$ 657,700	$ 556,600	$ 650,600	$ 681,100	$ 699,200	$ 646,500	$ 806,700	$ 2,558,400	$ 2,833,500	$ 2,607,100
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion									1,516,000	1,360,500	1,217,600
Equity in income of unconsolidated affiliates									(373,600)	(259,500)	(167,300)
Distributions received from unconsolidated affiliates									462,100	375,100	251,600
Net effect of changes in operating accounts and other operating activities									(160,500)	(147,400)	(43,500)
Net cash flows provided by operating activities									4,002,400	4,162,200	3,865,500
Investing activities:
Capital expenditures, net of contributions in aid of construction costs									(3,811,600)	(2,864,000)	(3,382,200)
Cash used for business combinations, net of cash received									(1,056,500)	(2,416,800)	0
Proceeds from asset sales and insurance recoveries									1,608,600	145,300	280,600
Other investing activities									(182,300)	(662,400)	(1,155,900)
Cash used in investing activities									(3,441,800)	(5,797,900)	(4,257,500)
Financing activities:
Borrowings under debt agreements									21,081,100	18,361,100	13,852,800
Repayments of debt									(19,867,200)	(14,341,100)	(12,680,600)
Cash distributions paid to partners									(2,943,700)	(2,638,100)	(2,400,300)
Cash payments made in connection with DERs									(7,700)	(3,700)	0
Cash distributions paid to noncontrolling interests									(48,000)	(48,600)	(8,900)
Cash contributions from noncontrolling interests									54,000	4,000	115,400
Net cash proceeds from the issuance of common units									1,188,600	388,800	1,792,000
Cash contributions from owners									0	0	0
Other financing activities									(73,100)	(69,200)	(237,600)
Cash provided by (used in) financing activities									(616,000)	1,653,200	432,800
Net change in cash and cash equivalents									(55,400)	17,500	40,800
Cash and cash equivalents, January 1				74,400				56,900	74,400	56,900	16,100
Cash and cash equivalents, December 31	19,000				74,400				19,000	74,400	56,900
Eliminations and Adjustments [Member]
Operating activities:
Net income									(2,550,200)	(2,791,600)	(2,600,100)
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion									0	0	0
Equity in income of unconsolidated affiliates									2,548,700	2,789,600	2,599,100
Distributions received from unconsolidated affiliates									(3,000,200)	(2,702,900)	(2,454,400)
Net effect of changes in operating accounts and other operating activities									1,500	2,000	2,000
Net cash flows provided by operating activities									(3,000,200)	(2,702,900)	(2,453,400)
Investing activities:
Capital expenditures, net of contributions in aid of construction costs									0	0	0
Cash used for business combinations, net of cash received									0	0
Proceeds from asset sales and insurance recoveries									0	0	0
Other investing activities									1,179,800	384,600	1,791,100
Cash used in investing activities									1,179,800	384,600	1,791,100
Financing activities:
Borrowings under debt agreements									0	0	0
Repayments of debt									0	0	0
Cash distributions paid to partners									3,000,200	2,702,900	2,453,500
Cash payments made in connection with DERs									0	0
Cash distributions paid to noncontrolling interests									0	0	0
Cash contributions from noncontrolling interests									0	0	0
Net cash proceeds from the issuance of common units									0	0	0
Cash contributions from owners									(1,179,800)	(384,600)	(1,791,200)
Other financing activities									0	0	0
Cash provided by (used in) financing activities									1,820,400	2,318,300	662,300
Net change in cash and cash equivalents									0	0	0
Cash and cash equivalents, January 1				0				0	0	0	0
Cash and cash equivalents, December 31	0				0				0	0	0
Subsidiary Issuer (EPO) [Member]
Operating activities:
Net income									2,544,900	2,786,000	2,596,200
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion									144,900	153,000	143,500
Equity in income of unconsolidated affiliates									(2,718,400)	(2,865,200)	(2,609,000)
Distributions received from unconsolidated affiliates									1,989,600	4,539,900	4,523,200
Net effect of changes in operating accounts and other operating activities									882,800	(627,000)	(1,351,000)
Net cash flows provided by operating activities									2,843,800	3,986,700	3,302,900
Investing activities:
Capital expenditures, net of contributions in aid of construction costs									(1,180,000)	(647,900)	(517,800)
Cash used for business combinations, net of cash received									(1,069,900)	(2,437,500)
Proceeds from asset sales and insurance recoveries									1,531,300	4,300	59,600
Other investing activities									(1,513,400)	(2,603,400)	(3,163,600)
Cash used in investing activities									(2,232,000)	(5,684,500)	(3,621,800)
Financing activities:
Borrowings under debt agreements									21,081,100	18,361,100	13,852,800
Repayments of debt									(19,867,200)	(14,341,100)	(12,650,800)
Cash distributions paid to partners									(3,000,200)	(2,702,900)	(2,453,400)
Cash payments made in connection with DERs									0	0
Cash distributions paid to noncontrolling interests									0	0	0
Cash contributions from noncontrolling interests									0	0	0
Net cash proceeds from the issuance of common units									0	0	0
Cash contributions from owners									1,179,800	384,600	1,791,200
Other financing activities									(24,000)	(13,600)	(192,500)
Cash provided by (used in) financing activities									(630,500)	1,688,100	347,300
Net change in cash and cash equivalents									(18,700)	(9,700)	28,400
Cash and cash equivalents, January 1				18,700				28,400	18,700	28,400	0
Cash and cash equivalents, December 31	0				18,700				0	18,700	28,400
Other Subsidiaries (Non-guarantor) [Member]
Operating activities:
Net income									2,804,400	3,010,700	2,660,600
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion									1,371,500	1,208,000	1,072,800
Equity in income of unconsolidated affiliates									(417,500)	(354,300)	(204,800)
Distributions received from unconsolidated affiliates									307,700	327,100	233,700
Net effect of changes in operating accounts and other operating activities									(1,031,000)	479,400	1,323,400
Net cash flows provided by operating activities									3,035,100	4,670,900	5,085,700
Investing activities:
Capital expenditures, net of contributions in aid of construction costs									(2,631,600)	(2,216,100)	(2,864,400)
Cash used for business combinations, net of cash received									13,400	20,700
Proceeds from asset sales and insurance recoveries									77,300	141,000	221,000
Other investing activities									(1,248,200)	(660,000)	(769,500)
Cash used in investing activities									(3,789,100)	(2,714,400)	(3,412,900)
Financing activities:
Borrowings under debt agreements									133,900	0	0
Repayments of debt									0	0	(29,800)
Cash distributions paid to partners									(1,882,400)	(4,537,800)	(4,514,100)
Cash payments made in connection with DERs									0	0
Cash distributions paid to noncontrolling interests									(800)	(2,700)	0
Cash contributions from noncontrolling interests									54,400	0	0
Net cash proceeds from the issuance of common units									0	0	0
Cash contributions from owners									2,445,000	2,604,900	2,892,600
Other financing activities									3,100	0	0
Cash provided by (used in) financing activities									753,200	(1,935,600)	(1,651,300)
Net change in cash and cash equivalents									(800)	20,900	21,500
Cash and cash equivalents, January 1				70,400				49,500	70,400	49,500	28,000
Cash and cash equivalents, December 31	69,600				70,400				69,600	70,400	49,500
Consolidated EPO and Subsidiaries [Member]
Operating activities:
Net income									2,587,400	2,837,700	2,610,300
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion									1,516,000	1,360,500	1,217,600
Equity in income of unconsolidated affiliates									(373,600)	(259,500)	(167,300)
Distributions received from unconsolidated affiliates									462,100	375,100	251,600
Net effect of changes in operating accounts and other operating activities									(184,100)	(141,900)	(37,700)
Net cash flows provided by operating activities									4,007,800	4,171,900	3,874,500
Investing activities:
Capital expenditures, net of contributions in aid of construction costs									(3,811,600)	(2,864,000)	(3,382,200)
Cash used for business combinations, net of cash received									(1,056,500)	(2,416,800)
Proceeds from asset sales and insurance recoveries									1,608,600	145,300	280,600
Other investing activities									(182,300)	(662,400)	(1,155,900)
Cash used in investing activities									(3,441,800)	(5,797,900)	(4,257,500)
Financing activities:
Borrowings under debt agreements									21,081,100	18,361,100	13,852,800
Repayments of debt									(19,867,200)	(14,341,100)	(12,680,600)
Cash distributions paid to partners									(3,000,200)	(2,702,900)	(2,453,400)
Cash payments made in connection with DERs									0	0
Cash distributions paid to noncontrolling interests									(48,000)	(48,600)	(8,900)
Cash contributions from noncontrolling interests									54,000	4,000	115,400
Net cash proceeds from the issuance of common units									0	0	0
Cash contributions from owners									1,179,800	384,600	1,791,200
Other financing activities									(20,900)	(13,600)	(192,500)
Cash provided by (used in) financing activities									(621,400)	1,643,500	424,000
Net change in cash and cash equivalents									(55,400)	17,500	41,000
Cash and cash equivalents, January 1				74,400				56,900	74,400	56,900	15,900
Cash and cash equivalents, December 31	19,000				74,400				19,000	74,400	56,900
Consolidated EPO and Subsidiaries [Member] | Eliminations and Adjustments [Member]
Operating activities:
Net income									(2,761,900)	(2,959,000)	(2,646,500)
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion									(400)	(500)	1,300
Equity in income of unconsolidated affiliates									2,762,300	2,960,000	2,646,500
Distributions received from unconsolidated affiliates									(1,835,200)	(4,491,900)	(4,505,300)
Net effect of changes in operating accounts and other operating activities									(35,900)	5,700	(10,100)
Net cash flows provided by operating activities									(1,871,100)	(4,485,700)	(4,514,100)
Investing activities:
Capital expenditures, net of contributions in aid of construction costs									0	0	0
Cash used for business combinations, net of cash received									0	0
Proceeds from asset sales and insurance recoveries									0	0	0
Other investing activities									2,579,300	2,601,000	2,777,200
Cash used in investing activities									2,579,300	2,601,000	2,777,200
Financing activities:
Borrowings under debt agreements									(133,900)	0	0
Repayments of debt									0	0	0
Cash distributions paid to partners									1,882,400	4,537,800	4,514,100
Cash payments made in connection with DERs									0	0
Cash distributions paid to noncontrolling interests									(47,200)	(45,900)	(8,900)
Cash contributions from noncontrolling interests									(400)	4,000	115,400
Net cash proceeds from the issuance of common units									0	0	0
Cash contributions from owners									(2,445,000)	(2,604,900)	(2,892,600)
Other financing activities									0	0	0
Cash provided by (used in) financing activities									(744,100)	1,891,000	1,728,000
Net change in cash and cash equivalents									(35,900)	6,300	(8,900)
Cash and cash equivalents, January 1				(14,700)				(21,000)	(14,700)	(21,000)	(12,100)
Cash and cash equivalents, December 31	(50,600)				(14,700)				(50,600)	(14,700)	(21,000)
Enterprise Products Partners L.P. (Guarantor) [Member]
Operating activities:
Net income									2,521,200	2,787,400	2,596,900
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion									0	0	0
Equity in income of unconsolidated affiliates									(2,548,700)	(2,789,600)	(2,599,100)
Distributions received from unconsolidated affiliates									3,000,200	2,702,900	2,454,400
Net effect of changes in operating accounts and other operating activities									22,100	(7,500)	(7,800)
Net cash flows provided by operating activities									2,994,800	2,693,200	2,444,400
Investing activities:
Capital expenditures, net of contributions in aid of construction costs									0	0	0
Cash used for business combinations, net of cash received									0	0
Proceeds from asset sales and insurance recoveries									0	0	0
Other investing activities									(1,179,800)	(384,600)	(1,791,100)
Cash used in investing activities									(1,179,800)	(384,600)	(1,791,100)
Financing activities:
Borrowings under debt agreements									0	0	0
Repayments of debt									0	0	0
Cash distributions paid to partners									(2,943,700)	(2,638,100)	(2,400,400)
Cash payments made in connection with DERs									(7,700)	(3,700)
Cash distributions paid to noncontrolling interests									0	0	0
Cash contributions from noncontrolling interests									0	0	0
Net cash proceeds from the issuance of common units									1,188,600	388,800	1,792,000
Cash contributions from owners									0	0	0
Other financing activities									(52,200)	(55,600)	(45,100)
Cash provided by (used in) financing activities									(1,815,000)	(2,308,600)	(653,500)
Net change in cash and cash equivalents									0	0	(200)
Cash and cash equivalents, January 1				$ 0				$ 0	0	0	200
Cash and cash equivalents, December 31	$ 0				$ 0				$ 0	$ 0	$ 0