Enterprise Products Partners (EPD) 10-K 28 Feb 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Jan. 31, 2018	Jun. 30, 2017
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			$ 39,610
Entity Common Stock, Shares Outstanding		2,161,094,920
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 5.1	$ 63.1
Restricted cash	65.2	354.5
Accounts receivable - trade, net of allowance for doubtful accounts of $12.1 at December 31, 2017 and $11.3 at December 31, 2016	4,358.4	3,329.5
Accounts receivable - related parties	1.8	1.1
Inventories	1,609.8	1,770.5
Derivative assets	153.4	541.4
Prepaid and other current assets	312.7	468.1
Total current assets	6,506.4	6,528.2
Property, plant and equipment, net	35,620.4	33,292.5
Investments in unconsolidated affiliates	2,659.4	2,677.3
Intangible assets, net of accumulated amortization of $1,564.8 at December 31, 2017 and $1,403.1 at December 31, 2016	3,690.3	3,864.1
Goodwill	5,745.2	5,745.2
Other assets	196.4	86.7
Total assets	54,418.1	52,194
Current liabilities:
Current maturities of debt	2,855	2,576.8
Accounts payable - trade	801.7	397.7
Accounts payable - related parties	127.3	105.1
Accrued product payables	4,566.3	3,613.7
Accrued interest	358	340.8
Derivative liabilities	168.2	737.7
Other current liabilities	418.6	478.7
Total current liabilities	9,295.1	8,250.5
Long-term debt	21,713.7	21,120.9
Deferred tax liabilities	58.5	52.7
Other long-term liabilities	578.4	503.9
Commitments and contingencies
Limited partners:
Common units (2,161,089,479 units outstanding at December 31, 2017 and 2,117,588,414 units outstanding at December 31, 2016)	22,718.9	22,327
Accumulated other comprehensive loss	(171.7)	(280)
Total partners' equity	22,547.2	22,047
Noncontrolling interests	225.2	219
Total equity	22,772.4	22,266
Total liabilities and equity	$ 54,418.1	$ 52,194

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
ASSETS
Accounts receivable, allowance for doubtful accounts	$ 12.1	$ 11.3
Intangible assets, accumulated amortization	$ 1,564.8	$ 1,403.1
Limited partners:
Common units outstanding (in units)	2,161,089,479	2,117,588,414

STATEMENTS OF CONSOLIDATED OPER

STATEMENTS OF CONSOLIDATED OPERATIONS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues:
Third parties	$ 29,196.5	$ 22,965.6	$ 26,955.6
Related parties	45	56.7	72.3
Total revenues	29,241.5	23,022.3	27,027.9
Operating costs and expenses:
Third parties	24,444.7	18,539.5	22,588.2
Related parties	1,112.8	1,104	1,080.5
Total operating costs and expenses	25,557.5	19,643.5	23,668.7
General and administrative costs:
Third parties	59.6	47	78.5
Related parties	121.5	113.1	114.1
Total general and administrative costs	181.1	160.1	192.6
Total costs and expenses	25,738.6	19,803.6	23,861.3
Equity in income of unconsolidated affiliates	426	362	373.6
Operating income	3,928.9	3,580.7	3,540.2
Other income (expense):
Interest expense	(984.6)	(982.6)	(961.8)
Change in fair market value of Liquidity Option Agreement	(64.3)	(24.5)	(25.4)
Other, net	1.3	2.8	2.9
Total other expense, net	(1,047.6)	(1,004.3)	(984.3)
Income before income taxes	2,881.3	2,576.4	2,555.9
Benefit from (provision for) income taxes	(25.7)	(23.4)	2.5
Net income	2,855.6	2,553	2,558.4
Net income attributable to noncontrolling interests	(56.3)	(39.9)	(37.2)
Net income attributable to limited partners	$ 2,799.3	$ 2,513.1	$ 2,521.2
Earnings per unit:
Basic earnings per unit (in dollars per unit)	$ 1.30	$ 1.20	$ 1.28
Diluted earnings per unit (in dollars per unit)	$ 1.30	$ 1.20	$ 1.26

STATEMENTS OF CONSOLIDATED COMP

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
Net income	$ 2,855.6	$ 2,553	$ 2,558.4
Commodity derivative instruments:
Changes in fair value of cash flow hedges	(38.5)	(193.8)	214.9
Reclassification of losses (gains) to net income	112.2	53.4	(228.2)
Interest rate derivative instruments:
Changes in fair value of cash flow hedges	(5.7)	42.3	0
Reclassification of losses to net income	40.4	37.4	35.3
Total cash flow hedges	108.4	(60.7)	22
Other	(0.1)	(0.1)	0.4
Total other comprehensive income (loss)	108.3	(60.8)	22.4
Comprehensive income	2,963.9	2,492.2	2,580.8
Comprehensive income attributable to noncontrolling interests	(56.3)	(39.9)	(37.2)
Comprehensive income attributable to limited partners	$ 2,907.6	$ 2,452.3	$ 2,543.6

STATEMENTS OF CONSOLIDATED CASH

STATEMENTS OF CONSOLIDATED CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating activities:
Net income	$ 2,855.6	$ 2,553	$ 2,558.4
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion	1,644	1,552	1,516
Asset impairment and related charges	49.8	53.5	162.6
Equity in income of unconsolidated affiliates	(426)	(362)	(373.6)
Distributions received on earnings from unconsolidated affiliates	433.7	380.5	462.1
Net losses (gains) attributable to asset sales	(10.7)	(2.5)	15.6
Deferred income tax expense (benefit)	6.1	6.6	(20.6)
Change in fair market value of derivative instruments	22.8	45	(18.4)
Change in fair market value of Liquidity Option Agreement	64.3	24.5	25.4
Net effect of changes in operating accounts	32.2	(180.9)	(323.3)
Other operating activities	(5.5)	(2.9)	(1.8)
Net cash flows provided by operating activities	4,666.3	4,066.8	4,002.4
Investing activities:
Capital expenditures	(3,147.9)	(3,025.1)	(3,830.7)
Contributions in aid of construction costs	46.1	41	19.1
Cash used for business combinations, net of cash received	(198.7)	(1,000)	(1,056.5)
Investments in unconsolidated affiliates	(50.5)	(138.8)	(162.6)
Distributions received for return of capital from unconsolidated affiliates	49.3	71	0
Proceeds from asset sales	40.1	46.5	1,608.6
Other investing activities	(24.5)	(0.4)	(3.8)
Cash used in investing activities	(3,286.1)	(4,005.8)	(3,425.9)
Financing activities:
Borrowings under debt agreements	69,315.3	62,813.9	21,081.1
Repayments of debt	(68,459.6)	(61,672.6)	(19,867.2)
Debt issuance costs	(24.1)	(10.6)	(24)
Monetization of interest rate derivative instruments	30.6	6.1	0
Cash distributions paid to limited partners	(3,569.9)	(3,300.5)	(2,943.7)
Cash payments made in connection with distribution equivalent rights	(15.1)	(11.7)	(7.7)
Cash distributions paid to noncontrolling interests	(49.2)	(47.4)	(48)
Cash contributions from noncontrolling interests	0.4	20.4	54
Net cash proceeds from the issuance of common units	1,073.4	2,542.8	1,188.6
Other financing activities	(29.3)	(18.7)	(49.1)
Cash provided by (used in) financing activities	(1,727.5)	321.7	(616)
Net change in cash and cash equivalents	(347.3)	382.7	(39.5)
Cash, cash equivalents and restricted cash, January 1	417.6	34.9	74.4
Cash, cash equivalents and restricted cash, December 31	$ 70.3	$ 417.6	$ 34.9

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, 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 and noncontrolling interests acquired 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
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	2,553	0	39.9	2,513.1
Cash distributions paid to limited partners	(3,300.5)	0	0	(3,300.5)
Cash payments made in connection with distribution equivalent rights	(11.7)	0	0	(11.7)
Cash distributions paid to noncontrolling interests	(47.4)	0	(47.4)	0
Cash contributions from noncontrolling interests	20.4	0	20.4	0
Net cash proceeds from the issuance of common units	2,542.8	0	0	2,542.8
Amortization of fair value of equity-based awards	90.2	0	0	90.2
Cash flow hedges	(60.7)	(60.7)	0	0
Other	(21.2)	(0.1)	0.1	(21.2)
Balance at Dec. 31, 2016	22,266	(280)	219	22,327
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	2,855.6	0	56.3	2,799.3
Cash distributions paid to limited partners	(3,569.9)	0	0	(3,569.9)
Cash payments made in connection with distribution equivalent rights	(15.1)	0	0	(15.1)
Cash distributions paid to noncontrolling interests	(49.2)	0	(49.2)	0
Cash contributions from noncontrolling interests	0.4	0	0.4	0
Net cash proceeds from the issuance of common units	1,073.4	0	0	1,073.4
Common units issued in connection with employee compensation	33.7	0	0	33.7
Amortization of fair value of equity-based awards	99	0	0	99
Cash flow hedges	108.4	108.4	0	0
Other	(29.9)	(0.1)	(1.3)	(28.5)
Balance at Dec. 31, 2017	$ 22,772.4	$ (171.7)	$ 225.2	$ 22,718.9

Partnership Operations, Organiz

Partnership Operations, Organization and Basis of Presentation	12 Months Ended
	Dec. 31, 2017
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. 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 32% of our limited partner interests at December 31, 2017. References to “EFS Midstream” mean EFS Midstream LLC, which we acquired in July 2015 from affiliates of Pioneer Natural Resources Company (“PXD”) and Reliance Industries Limited (“Reliance”). See Note 12 for additional information regarding this acquisition. References to “Offshore Business” refer to the Gulf of Mexico operations we sold to Genesis Energy, L.P. (“Genesis”) in July 2015. See Note 10 for additional information regarding this sale. 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 United States (“U.S.”) corporation, as the first step of a two-step acquisition of Oiltanking. In February 2015, we completed the second step of this transaction consisting of the acquisition of the noncontrolling interests in Oiltanking. 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. We are a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.” We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO and are 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 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 export and import terminals (including those used to export liquefied petroleum gases, or “LPG,” and ethane); crude oil gathering, transportation, storage, and export and import terminals; petrochemical and refined products transportation, storage, export and import terminals, and related services; and a marine transportation business that operates primarily on the U.S. inland and Intracoastal Waterway systems. Our assets currently include approximately 50,000 miles of pipelines; 260 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. 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. Our operations are reported under four business segments: (i) NGL Pipelines & Services, (ii) Crude Oil Pipelines & Services, (iii) Natural Gas Pipelines & Services and (iv) Petrochemical & Refined Products Services. See Note 10 for additional information regarding our business segments.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 2015 Balance at beginning of period $ 11.3 $ 12.1 $ 13.9 Charged to costs and expenses 2.7 2.3 0.8 Deductions (1.9 ) (3.1 ) (2.6 ) Balance at end of period $ 12.1 $ 11.3 $ 12.1 See “Credit Risk” in Note 18 for additional information. Cash, Cash Equivalents and Restricted Cash 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. 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 margin requirements change. In November 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash, which standardizes the presentation of transfers to and from restricted cash within the cash flow statement. As a result, the cash flow statement will present changes in total cash amounts, regardless of whether the cash balances are restricted or unrestricted. We adopted this guidance in the fourth quarter of 2017 and applied this ASU retrospectively to the periods presented in our Statements of Consolidated Cash Flows. As a result, the decrease in restricted cash of $338.6 million and $15.9 million was excluded from net cash used in investing activities for the years ended December 31, 2016 and 2015, respectively. The following table provides a reconciliation of cash and cash equivalents, and restricted cash reported within the Consolidated Balance Sheets that sum to the total of the amounts shown in the Statements of Consolidated Cash Flows. December 31, 2017 2016 Cash and cash equivalents $ 5.1 $ 63.1 Restricted cash 65.2 354.5 Total cash, cash equivalents and restricted cash shown in the Statements of Consolidated Cash Flows $ 70.3 $ 417.6 The balance of restricted cash at December 31, 2017 consisted of initial margin requirements of $33.4 million and variation margin requirements of $31.8 million. The initial margin requirements will be returned to us as the related derivative instruments are settled. See Note 14 for information regarding our derivative instruments and hedging activities. 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, 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, 2017, 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, 2017 2016 2015 Balance at beginning of period $ 11.9 $ 13.0 $ 15.6 Charged to costs and expenses 12.1 7.0 6.4 Acquisition-related additions and other 1.7 0.5 1.1 Deductions (14.1 ) (8.6 ) (10.1 ) Balance at end of period $ 11.6 $ 11.9 $ 13.0 At December 31, 2017 and 2016, $5.6 million 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, 2017 and 2016. 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 non-cash impairment 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 in their fair value estimation process. Based on our most recent goodwill impairment test at December 31, 2017, 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 non-cash impairment charges related to long-lived assets. Impairment Testing for Unconsolidated Affiliates We evaluate our equity method investments for impairment to determine whether there are events or changes in circumstances that indicate 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 non-cash impairment charge to equity earnings to adjust the carrying value of the investment to its estimated fair value. There were not any non-cash impairment charges related to our equity method investments during the years ended 2017, 2016 and 2015. See Note 6 for information regarding our equity method investments. Inventories Inventories primarily consist of NGLs, petrochemicals, refined products, crude oil and natural gas volumes that are valued at the lower of cost or net realizable value. 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 on a straight-line basis 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 . Revenues from Contracts with Customers 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. Our implementation activities related to ASC 606 are nearly complete. For the vast majority of our businesses, we will not have any material differences in the amount or timing of revenues once we adopt ASC 606. However, based on guidance in ASC 606 applicable to non-cash consideration, we will start recognizing revenue in connection with equity NGL volumes we receive as consideration for providing processing services under percent of liquids and similar arrangements. The value assigned to this non-cash consideration and related inventory will be based on the fair value of NGLs we are entitled to at the time the processing services are performed. An additional revenue stream, along with the related cost of sales, would be recognized in connection with the ultimate sale of the NGL products derived from the NGLs acquired as a fee for service. Under current accounting practice, we only recognize revenue from the downstream sale of NGL products and do not record service revenue. Based on our estimates, if the changes required by ASC 606 had been adopted at January 1, 2017, our total consolidated revenues for the year ended December 31, 2017 would have increased by approximately 1%. Given the rapid turnover of our inventories of NGL products each month, we do not expect a significant change in our gross operating margin from natural gas processing and related NGL marketing activities as a result of the changes required by ASC 606. The additional revenue stream recognized in connection with receipt of the equity NGLs will be offset by an equal cost of sales amount when the associated NGL products are sold, which is expected to typically be completed in the same accounting period. As a result of adopting the new standard, there will be significant changes to our disclosures based on the additional requirements prescribed by ASC 606. These new disclosures include information regarding the significant judgments used in evaluating when and how revenue is (or will be) recognized and data related to contract assets and liabilities. Additionally, we have revised our business processes, systems and controls to ensure the accuracy and timeliness of the recognition and disclosure requirements under the new revenue guidance. Leases Leases The new standard introduces two lease accounting models, which result in a lease being classified as either a “finance” or “operating” lease on the basis of whether the lessee effectively obtains control of the underlying asset during the lease term. A lease would be classified as a finance lease if it meets o

Revenue Recognition

Revenue Recognition	12 Months Ended
	Dec. 31, 2017
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 2 for information regarding recent accounting guidance related to revenue recognition. See Note 10 for general information regarding our business segments. The following table information regarding our consolidated revenues by business segment for the periods indicated: For the Year Ended December 31, 2017 2016 2015 NGL Pipelines & Services: Sales of NGLs and related products $ 10,521.3 $ 8,380.5 $ 8,044.8 Midstream services 1,946.7 1,862.0 1,743.2 Total 12,468.0 10,242.5 9,788.0 Crude Oil Pipelines & Services: Sales of crude oil 7,365.2 5,802.5 9,732.9 Midstream services 791.6 712.5 573.0 Total 8,156.8 6,515.0 10,305.9 Natural Gas Pipelines & Services: Sales of natural gas 2,238.5 1,591.9 1,722.6 Midstream services 907.1 951.1 1,020.7 Total 3,145.6 2,543.0 2,743.3 Petrochemical & Refined Products Services: Sales of petrochemicals and refined products 4,696.3 2,921.9 3,333.5 Midstream services 774.8 799.9 778.4 Total 5,471.1 3,721.8 4,111.9 Offshore Pipelines & Services: Sales of crude oil -- -- 3.2 Midstream services -- -- 75.6 Total -- -- 78.8 Total consolidated revenues $ 29,241.5 $ 23,022.3 $ 27,027.9 NGL Pipelines & Services Sales of NGLs and related products  NGL marketing activities generate revenues from merchant activities such as spot and term sales of NGLs and related products, which we take title to through our natural gas processing activities (i.e., our equity NGL production), and open market and long-term contract purchases. Revenue from these sales contracts is recognized when the NGLs are sold and delivered to customers at market-based prices. Midstream services  Natural gas processing utilizes contracts that are either fee-based, commodity-based or a combination of the two. Our commodity-based contracts include keepwhole, margin-band, percent-of-liquids, percent-of-proceeds and contracts featuring a combination of commodity and fee-based terms. We recognize revenue when the extracted NGLs are delivered and sold to customers under NGL marketing sales contracts. 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.  NGL pipeline transportation contracts and tariffs generally generate revenue based upon a fixed fee per gallon of liquids multiplied by the volume transported and delivered (or capacity reserved). Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies or contractual arrangements. Under certain agreements customers are required to ship a minimum volume over an agreed-upon period with a provision that allows the shipper to make-up any volume shortfalls over an agreed-upon period (referred to as shipper “make-up rights”). Revenue pursuant to such agreements 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, or when the pipeline is otherwise released from its performance obligation.  NGL fractionation primarily generates revenue under fee-based arrangements. These fees are contractually subject to adjustment for changes in certain fractionation expenses (e.g., natural gas fuel costs) and are recognized in the period services are provided.  NGL and related product storage contracts generate revenue from capacity reservation where we collect a fee for reserving storage capacity for customers in our underground storage wells. Under these agreements, revenue is recognized on a straight-line basis over the specified reservation period. 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.  NGL import and export terminaling activities generate revenue in the period services are provided. Customers are typically billed a fee per unit of volume loaded or unloaded. Crude Oil Pipelines & Services Sales of crude oil  Crude oil marketing activities generate revenues from the sale and delivery of crude oil purchased either directly from producers or on the open market. Revenue from these sales contracts is recognized when crude oil is sold and delivered to customers at market-based prices. Midstream services  Crude oil transportation contracts and tariffs generally generate revenue based upon a fixed fee per barrel multiplied by the volume transported and delivered (or capacity reserved). Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies or contractual arrangements. Under certain agreements, customers are required to ship a minimum volume over an agreed-upon period, with make-up rights. Revenue pursuant to such agreements 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, or when the pipeline is otherwise released from its performance obligation.  Condensate gathering, processing and stabilization services as well as crude oil gathering, treating and pumping services generate revenue based upon the higher of actual volumes handled or minimum volume commitments multiplied by predominantly fixed fees charged for the underlying services. The producer pays a deficiency fee when its volumes do not meet contractually defined minimum volume thresholds (these agreements have no make-up rights).  Crude oil storage and terminaling agreements generate revenue based on capacity reservation where we collect a fee for reserving storage capacity for customers at our terminals. Under these agreements, revenue is recognized on a straight-line basis over the specified reservation period. In addition, customers are typically billed a fee per unit of volume loaded or unloaded at our terminals. Natural Gas Pipelines & Services Sales of natural gas  Natural gas marketing activities generate revenue from the sale and delivery of natural gas purchased from producers, regional natural gas processing plants and on the open market. Revenue from these sales contracts is recognized when natural gas is sold and delivered to customers at market-based prices. Midstream services  Natural gas transportation contracts generate revenues based on 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 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.  Natural gas storage contracts generate revenue typically by 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. Petrochemical & Refined Products Services Sales of petrochemicals and refined products  Our petrochemical marketing activities include the purchase and fractionation of refinery grade propylene obtained on the open market and generate revenues from the sale and delivery of polymer grade propylene to customers at market-based prices. Revenues from our propane dehydrogenation (“PDH”) facility are dependent on the level of minimum volume commitments by customers and the associated contractual fees paid by them for polymer grade propylene during a given period.  Revenue from the production and sale of octane additives and high purity isobutylene is dependent on the volume of such commodities sold and delivered to customers at market-based prices.  Revenue from refined products marketing is dependent on the volume of such commodities purchased on the open market and sold and delivered to customers at market-based prices. Midstream services  Propylene fractionation, butane isomerization and deisobutanizer facilities generate revenue through fee-based toll arrangements with customers, with such arrangements typically including a base-processing fee subject to adjustment for changes in power, fuel and labor costs. Revenue resulting from such agreements is recognized in the period the services are provided.  Petrochemical and refined products transportation contracts generate revenue based upon a fixed fee per volume multiplied by the volume transported and delivered. Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies or contractual arrangements.  Refined products storage contracts generate revenue based on capacity reservation where we collect a fee for reserving a defined storage capacity for customers at our facilities. Under these contracts, revenue is recognized on a straight-line basis over the length of the storage period.  Refined product terminaling contracts generate revenue based on a fee per unit of volume loaded or unloaded and are recognized in the period such services are provided.  Marine transportation contracts generate revenue based on set day rates or a set fee per cargo movement recognized over the transit time of individual tows. Additionally, we record revenue for costs of fuel and other specified operational fees that are directly reimbursed by the customer under most of these contracts. Offshore Pipelines & Services In July 2015, we sold our Offshore Business, which comprised our Offshore Pipelines & Services segment. See Note 10 for additional information related to this sale.

Inventories

Inventories	12 Months Ended
	Dec. 31, 2017
Inventories [Abstract]
Inventories	Our inventory amounts by product type were as follows at the dates indicated: December 31, 2017 2016 NGLs $ 917.4 $ 1,156.1 Petrochemicals and refined products 161.5 220.7 Crude oil 516.3 360.0 Natural gas 14.6 33.7 Total $ 1,609.8 $ 1,770.5 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 net realizable value adjustments for the periods indicated: For the Year Ended December 31, 2017 2016 2015 Cost of sales (1) $ 21,487.0 $ 15,710.9 $ 19,612.9 Lower of cost or net realizable value adjustments within cost of sales 9.1 11.5 19.8 (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. Due to fluctuating commodity prices, we recognize lower of cost or net realizable value 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, 2017
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 2017 2016 Plants, pipelines and facilities (1) 3-45 (5) $ 37,132.2 $ 35,124.6 Underground and other storage facilities (2) 5-40 (6) 3,460.9 3,326.9 Transportation equipment (3) 3-10 177.1 165.8 Marine vessels (4) 15-30 803.8 800.7 Land 273.1 264.6 Construction in progress 4,698.1 3,320.7 Total 46,545.2 43,003.3 Less accumulated depreciation 10,924.8 9,710.8 Property, plant and equipment, net $ 35,620.4 $ 33,292.5 (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) Transportation equipment includes tractor-trailer tank trucks and other vehicles and similar assets used in our operations. (4) Marine vessels include tow boats, barges and related equipment used in our marine transportation business. (5) 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. (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. The following table summarizes our depreciation expense and capitalized interest amounts for the periods indicated: For the Year Ended December 31, 2017 2016 2015 Depreciation expense (1) $ 1,296.1 $ 1,215.7 $ 1,161.6 Capitalized interest (2) 192.1 168.2 149.1 (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. 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, 2017 and 2016 includes $39.9 million and $44.9 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, 2017 2016 2015 ARO liability beginning balance $ 85.4 $ 58.5 $ 98.3 Liabilities incurred 4.7 4.2 2.7 Liabilities settled (2.2 ) (5.7 ) (6.3 ) Revisions in estimated cash flows (6.7 ) 24.6 49.7 Accretion expense 5.5 3.8 5.2 AROs related to Offshore Business sold in July 2015 -- -- (91.1 ) ARO liability ending balance $ 86.7 $ 85.4 $ 58.5 The following table presents our forecast of accretion expense for the periods indicated: 2018 2019 2020 2021 2022 $ 5.8 $ 6.2 $ 6.5 $ 6.9 $ 7.3

Investments in Unconsolidated A

Investments in Unconsolidated Affiliates	12 Months Ended
	Dec. 31, 2017
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, 2017 December 31, 2017 2016 NGL Pipelines & Services: Venice Energy Service Company, L.L.C. (“VESCO”) 13.1% $ 25.7 $ 24.8 K/D/S Promix, L.L.C. (“Promix”) 50% 30.9 33.7 Baton Rouge Fractionators LLC (“BRF”) 32.2% 17.0 17.3 Skelly-Belvieu Pipeline Company, L.L.C. (“Skelly-Belvieu”) 50% 37.0 38.9 Texas Express Pipeline LLC (“Texas Express”) 35% 314.4 331.9 Texas Express Gathering LLC (“TEG”) 45% 35.9 35.8 Front Range Pipeline LLC (“Front Range”) 33.3% 165.7 165.4 Delaware Basin Gas Processing LLC (“Delaware Processing”) 50% 107.3 102.6 Crude Oil Pipelines & Services: Seaway Crude Pipeline Company LLC (“Seaway”) 50% 1,378.9 1,393.8 Eagle Ford Pipeline LLC (“Eagle Ford Crude Oil Pipeline”) 50% 385.2 377.9 Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Corpus Christi”) 50% 75.1 52.9 Natural Gas Pipelines & Services: White River Hub, LLC (“White River Hub”) 50% 20.8 21.7 Petrochemical & Refined Products Services: Centennial Pipeline LLC (“Centennial”) 50% 60.8 62.3 Other Various 4.7 18.3 Total investments in unconsolidated affiliates $ 2,659.4 $ 2,677.3 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 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. In addition, BRF leases an NGL storage cavern.  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. 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 mixed NGLs to the Texas Express Pipeline. 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 and other third party facilities in Skellytown.  Delaware Processing, which commenced operations in August 2016, 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, which consists of two pipelines, provides north-to-south transportation of crude oil from the Cushing hub to Seaway’s Jones Creek terminal near Freeport, Texas and a terminal that we own located near Katy, Texas. The second of these two pipelines is referred to as the “Seaway Loop.” The Freeport System consists of a marine import and export dock, three pipelines and other related facilities that transport crude oil to and from Freeport and the Jones Creek terminal. The Texas City System consists of a marine import and export dock, storage tanks, various pipelines and other related facilities that transport crude oil to refineries in the Texas City, Texas area and to and from terminals in the Galena Park area, our Enterprise Crude Houston (“ECHO”) terminal and locations along the Houston Ship Channel. The Texas City System also receives production from certain offshore Gulf of Mexico developments.  Eagle Ford Crude Oil Pipeline owns a crude oil pipeline that transports crude oil and condensate for producers in South Texas. The system consists of a crude oil and condensate pipeline system originating in Gardendale, Texas in LaSalle County to Three Rivers, Texas in Live Oak County and extending to Corpus Christi, Texas. The system also includes a pipeline segment that interconnects 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.  Eagle Ford Corpus Christi is a joint venture formed in March 2015 to construct and operate a new deep-water marine crude oil terminal that is designed to handle a variety of ocean-going vessels. The new terminal is expected to be placed into service during the third quarter of 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 Beaumont, Texas, to Bourbon, Illinois. Centennial also owns a refined products storage terminal located near Creal Springs, Illinois. 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, 2017 2016 2015 NGL Pipelines & Services $ 73.4 $ 61.4 $ 57.5 Crude Oil Pipelines & Services 358.4 311.9 281.4 Natural Gas Pipelines & Services 3.8 3.8 3.8 Petrochemical & Refined Products Services (1) (9.6 ) (15.1 ) (15.7 ) Offshore Pipelines & Services (2) -- -- 46.6 Total $ 426.0 $ 362.0 $ 373.6 (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 market and income approaches, indicate that the fair value of this investment remains in excess of its carrying value. (2) Our investments in unconsolidated affiliates classified within the Offshore Pipelines & Services segment were sold in July 2015 (see Note 10). 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, 2017 2016 NGL Pipelines & Services $ 22.9 $ 24.1 Crude Oil Pipelines & Services 18.2 19.0 Petrochemical & Refined Products Services 1.8 2.1 Total $ 42.9 $ 45.2 In total, amortization of excess cost amounts were $2.1 million, $2.1 million and $4.9 million for the years ended December 31, 2017, 2016 and 2015, 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, 2017 2016 Balance Sheet Data: Current assets $ 288.8 $ 199.5 Property, plant and equipment, net 5,509.7 5,644.4 Other assets 71.2 61.5 Total assets $ 5,869.7 $ 5,905.4 Current liabilities $ 233.5 $ 208.5 Other liabilities 84.8 112.3 Combined equity 5,551.4 5,584.6 Total liabilities and combined equity $ 5,869.7 $ 5,905.4 For the Year Ended December 31, 2017 2016 2015 Income Statement Data: Revenues $ 1,509.0 $ 1,342.0 $ 1,426.6 Operating income 925.9 786.7 825.8 Net income 929.5 781.7 814.1

Intangible Assets and Goodwill

Intangible Assets and Goodwill	12 Months Ended
	Dec. 31, 2017
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, 2017 December 31, 2016 Gross Value Accumulated Amortization Carrying Value Gross Value Accumulated Amortization Carrying Value NGL Pipelines & Services: Customer relationship intangibles $ 447.4 $ (187.5 ) $ 259.9 $ 447.4 $ (172.7 ) $ 274.7 Contract-based intangibles 280.8 (218.4 ) 62.4 279.9 (204.4 ) 75.5 Segment total 728.2 (405.9 ) 322.3 727.3 (377.1 ) 350.2 Crude Oil Pipelines & Services: Customer relationship intangibles 2,203.5 (127.0 ) 2,076.5 2,204.4 (84.5 ) 2,119.9 Contract-based intangibles 281.0 (171.0 ) 110.0 281.0 (121.9 ) 159.1 Segment total 2,484.5 (298.0 ) 2,186.5 2,485.4 (206.4 ) 2,279.0 Natural Gas Pipelines & Services: Customer relationship intangibles 1,350.3 (417.1 ) 933.2 1,350.3 (390.0 ) 960.3 Contract-based intangibles 464.7 (379.5 ) 85.2 464.7 (370.5 ) 94.2 Segment total 1,815.0 (796.6 ) 1,018.4 1,815.0 (760.5 ) 1,054.5 Petrochemical & Refined Products Services: Customer relationship intangibles 181.4 (45.9 ) 135.5 185.5 (43.9 ) 141.6 Contract-based intangibles 46.0 (18.4 ) 27.6 54.0 (15.2 ) 38.8 Segment total 227.4 (64.3 ) 163.1 239.5 (59.1 ) 180.4 Total intangible assets $ 5,255.1 $ (1,564.8 ) $ 3,690.3 $ 5,267.2 $ (1,403.1 ) $ 3,864.1 The following table presents the amortization expense of our intangible assets by business segment for the periods indicated: For the Year Ended December 31, 2017 2016 2015 NGL Pipelines & Services $ 28.9 $ 30.6 $ 33.6 Crude Oil Pipelines & Services 92.5 98.4 87.1 Natural Gas Pipelines & Services 36.2 33.2 40.0 Petrochemical & Refined Products Services 9.3 9.1 8.9 Offshore Pipelines & Services -- -- 4.5 Total $ 166.9 $ 171.3 $ 174.1 The following table presents our forecast of amortization expense associated with existing intangible assets for the years indicated: 2018 2019 2020 2021 2022 $ 174.5 $ 165.8 $ 150.7 $ 145.6 $ 141.6 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 . 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, 2017, the carrying value of our portfolio of customer relationship intangible assets was $3.4 billion, the principal components of which are as follows: Weighted Average Remaining Amortization Period December 31, 2017 Gross Value Accumulated Amortization Carrying Value Basin-specific customer relationships: EFS Midstream (1) 24.4 years $ 1,409.8 $ (88.8 ) $ 1,321.0 State Line and Fairplay (2) 29.2 years 895.0 (164.7 ) 730.3 San Juan Gathering (3) 21.8 years 331.3 (218.0 ) 113.3 Encinal (4) 9.0 years 132.9 (98.4 ) 34.5 General customer relationships: Oiltanking (5) 26.0 years 1,192.5 (57.1 ) 1,135.4 (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 formation in Louisiana and eastern Texas. The Fairplay system serves producers in the Cotton Valley formation 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 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., PXD 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 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 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, 2017, the carrying value of this group of intangible assets was $118.7 million and the weighted average remaining amortization period for the group was 4.2 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, 2017, the carrying value of this group of intangible assets was $63.9 million and the weighted average remaining amortization period for the group was 24 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 January 1, 2015 $ 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 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 Balance at December 31, 2016 2,651.7 1,841.0 296.3 956.2 -- 5,745.2 Balance at December 31, 2017 $ 2,651.7 $ 1,841.0 $ 296.3 $ 956.2 $ -- $ 5,745.2 We did not record any goodwill impairment charges during the years ended December 31, 2017, 2016 or 2015. Based on our most recent goodwill impairment test at December 31, 2017, each reporting unit’s fair value was substantially in excess of its carrying value (i.e., by at least 10%). 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 10).

Debt Obligations

Debt Obligations	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 EPO senior debt obligations: Commercial Paper Notes, variable-rates $ 1,755.7 $ 1,777.2 Senior Notes L, 6.30% fixed-rate, due September 2017 -- 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 750.0 750.0 364-Day Revolving Credit Agreement, variable-rate, due September 2018 -- -- 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 Senior Notes RR, 2.85% fixed-rate, due April 2021 575.0 575.0 Senior Notes CC, 4.05% fixed-rate, due February 2022 650.0 650.0 Multi-Year Revolving Credit Facility, variable-rate, due September 2022 -- -- 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 875.0 875.0 Senior Notes SS, 3.95% fixed-rate, due February 2027 575.0 575.0 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 975.0 975.0 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 21,605.7 22,427.2 EPO Junior Subordinated Notes A, fixed/variable-rate, due August 2066 521.1 521.1 EPO Junior Subordinated Notes C, fixed/variable-rate, due June 2067 256.4 256.4 EPO Junior Subordinated Notes B, fixed/variable-rate, due January 2068 682.7 682.7 EPO Junior Subordinated Notes D, fixed/variable-rate, due August 2077 700.0 -- EPO Junior Subordinated Notes E, fixed/variable-rate, due August 2077 1,000.0 -- TEPPCO Junior Subordinated Notes, fixed/variable-rate, due June 2067 14.2 14.2 Total principal amount of senior and junior debt obligations 24,780.1 23,901.6 Other, non-principal amounts (211.4 ) (203.9 ) Less current maturities of debt (2,855.0 ) (2,576.8 ) Total long-term debt $ $ 21,713.7 $ $ 21,120.9 (1) Variable rate is reset quarterly and based on 3-month LIBOR plus 3.708%. (2) Fixed rate of 7.000% through May 31, 2017; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 2.778%. (3) Fixed rate of 7.034% through January 14, 2018; thereafter, the rate will be the greater of 7.034% or a variable rate reset quarterly and based on 3-month LIBOR plus 2.680%. These notes are expected to be redeemed in March 2018 (see Note 22). (4) Fixed rate of 4.875% through August 15, 2022; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 2.986%. (5) Fixed rate of 5.250% through August 15, 2027; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 3.033%. See Note 22, Subsequent Events 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, 2017: Range of Interest Rates Paid Weighted-Average Interest Rate Paid Commercial Paper Notes 0.90% to 1.80% 1.34% Multi-Year Revolving Credit Facility 2.23% to 2.23% 2.23% EPO Junior Subordinated Notes A 4.59% to 5.08% 4.89% EPO Junior Subordinated Notes C 3.98% to 4.26% 4.07% The following table presents contractually scheduled maturities of our consolidated debt obligations outstanding at December 31, 2017 for the next five years, and in total thereafter: Scheduled Maturities of Debt Total 2018 2019 2020 2021 2022 Thereafter Commercial Paper Notes $ 1,755.7 $ 1,755.7 $ -- $ -- $ -- $ -- $ -- Senior Notes 19,850.0 1,100.0 1,500.0 1,500.0 575.0 650.0 14,525.0 Junior Subordinated Notes 3,174.4 -- -- -- -- -- 3,174.4 Total $ 24,780.1 $ 2,855.7 $ 1,500.0 $ 1,500.0 $ 575.0 $ 650.0 $ 17,699.4 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 . Under the terms of the new 364-Day Revolving Credit Agreement, EPO may borrow up to $1.5 billion (which may be increased by up to $200 million to $1.7 billion at EPO’s election, provided certain conditions are met) at a variable interest rate for a term of 364 days, subject to the terms and conditions set forth therein. To the extent that principal amounts are outstanding at the maturity date, EPO may elect to have the entire principal balance then outstanding continued as a non-revolving term loan for a period of one additional year, payable in September 2019. Borrowings under this revolving credit agreement may be used for working capital, capital expenditures, acquisitions and general company purposes. The 364-Day Revolving 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 this credit agreement. The credit agreement also restricts EPO’s ability to pay cash distributions to its parent, Enterprise Products Partners L.P., if 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 or would result therefrom. EPO’s obligations under the 364-Day Revolving Credit Agreement are not secured by any collateral; however, they are guaranteed by Enterprise Products Partners L.P. Multi-Year Revolving Credit Facility . Under the terms of the new Multi-Year Revolving Credit Facility, EPO may borrow up to $4.0 billion (which may be increased by up to $500 million to $4.5 billion at EPO’s election, provided certain conditions are met) at a variable interest rate for a term of five years, subject to the terms and conditions set forth therein. Borrowings under this revolving credit facility may be used as a backstop for commercial paper and for working capital, capital expenditures, acquisitions and general company purposes. The Multi-Year Revolving Credit Facility 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 this credit facility. The credit facility also restricts EPO’s ability to pay cash distributions to its parent, Enterprise Products Partners L.P., if an event of default (as defined in the credit facility) has occurred and is continuing at the time such distribution is scheduled to be paid or would result therefrom. EPO’s obligations under the Multi-Year Revolving Credit Facility are not secured by any collateral; however, they are guaranteed by Enterprise Products Partners L.P. Senior Notes See Note 22, Subsequent Events EPO Junior Subordinated Notes . In connection with the issuance of each series of junior notes, other than Junior Notes D and Junior Notes E (in each case, as defined below), 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. In August 2017, EPO issued a combined $1.7 billion in principal amount of junior subordinated notes. The EPO Junior Subordinated Notes D (“Junior Notes D”), which were issued at $700 million principal amount in the aggregate, are redeemable at EPO’s option, in whole or in part, on one or more occasions, on or after August 16, 2022 (the non-call 5 notes) at 100% of their principal amount, plus any accrued and unpaid interest. Junior Notes D bear interest at a fixed rate of 4.875% per year through August 15, 2022. Beginning August 16, 2022, Junior Notes D will bear interest at a floating rate based on a three-month LIBOR rate plus 2.986%, reset quarterly. Junior Notes D mature in August 2077. The EPO Junior Subordinated Notes E (“Junior Notes E”), which were issued at $1.0 billion principal amount in the aggregate, are redeemable at EPO’s option, in whole or in part, on one or more occasions, on or after August 16, 2027 (the non-call 10 notes) at 100% of their principal amount, plus any accrued and unpaid interest. Junior Notes E bear interest at a fixed rate of 5.25% per year through August 15, 2027. Beginning August 16, 2027, Junior Notes E will bear interest at a floating rate based on a three-month LIBOR rate plus 3.033%, reset quarterly. Junior Notes E also mature in August 2077. Net proceeds from the issuance of Junior Notes D and E were used for (i) the temporary repayment of approximately $900 million of amounts then outstanding under EPO’s commercial paper program and (ii) the repayment of $800 million in principal amount of Senior Notes L that matured in September 2017. The following table summarizes the interest rate terms of our junior subordinated notes: Series Fixed Annual Interest Rate Variable Annual Interest Rate Thereafter EPO Junior Subordinated Notes A 8.375% through July 31, 2016 3-month LIBOR rate + 3.708% (6) EPO Junior Subordinated Notes B 7.034% through January 14, 2018 (2) Greater of: (i) 3-month LIBOR rate + 2.680% or (ii) 7.034% (7) EPO Junior Subordinated Notes C 7.000% through May 31, 2017 (3) 3-month LIBOR rate + 2.778% EPO Junior Subordinated Notes D 4.875% through August 15, 2022 (4) 3-month LIBOR rate + 2.986% EPO Junior Subordinated Notes E 5.250% through August 15, 2027 (5) 3-month LIBOR rate + 3.033% (1) Interest is payable semi-annually in arrears in February and August of each year, which commenced in February 2007. (2) Interest was 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 semi-annually in arrears in February and August of each year, which commenced in February 2018. (5) Interest is payable semi-annually in arrears in February and August of each year, which commenced in February 2018. (6) Interest is payable quarterly in arrears in February, May, August and November of each, which commenced in November 2016. (7) Interest was payable quarterly in arrears in January, April, July and October of each year commencing in April 2018. (8) Interest is payable quarterly in arrears in March, June, September and December of each year, which commenced in September 2017. (9) Interest is payable quarterly in arrears in February, May, August and November of each year commencing in November 2022. (10) Interest is payable quarterly in arrears in February, May, August and November of each year commencing in November 2027. See Note 22, Subsequent Events Letters of Credit At December 31, 2017, EPO had $66.4 million of letters of credit outstanding primarily related to our commodity hedging activities. Lender Financial Covenants We were in compliance with the financial covenants of our consolidated debt agreements at December 31, 2017.

Equity and Distributions

Equity and Distributions	12 Months Ended
	Dec. 31, 2017
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) outstanding. The following table summarizes changes in the number of our outstanding units since January 1, 2015: Common Units (Unrestricted) Restricted Common Units Total Common Units Number of units outstanding at January 1, 2015 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 ) Cancellation of treasury units acquired 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 Common units issued in connection with ATM program 87,867,037 -- 87,867,037 Common units issued in connection with DRIP and EUPP 16,316,534 -- 16,316,534 Common units issued in connection with the vesting of phantom unit awards 1,761,455 -- 1,761,455 Common units issued in connection with the vesting of restricted common unit awards 1,234,502 (1,234,502 ) -- Forfeiture of restricted common unit awards -- (43,724 ) (43,724 ) Cancellation of treasury units acquired in connection with the vesting of equity-based awards (1,000,619 ) -- (1,000,619 ) Other 134,707 -- 134,707 Number of units outstanding at December 31, 2016 2,116,906,120 682,294 2,117,588,414 Common units issued in connection with ATM program 21,807,726 -- 21,807,726 Common units issued in connection with DRIP and EUPP 19,046,019 -- 19,046,019 Common units issued in connection with the vesting of phantom unit awards 2,485,580 -- 2,485,580 Common units issued in connection with the vesting of restricted common unit awards 681,044 (681,044 ) -- Forfeiture of restricted common unit awards -- (1,250 ) (1,250 ) Cancellation of treasury units acquired in connection with the vesting of equity-based awards (1,027,798 ) -- (1,027,798 ) Common units issued in connection with employee compensation 1,176,103 -- 1,176,103 Other 14,685 -- 14,685 Number of units outstanding at December 31, 2017 2,161,089,479 -- 2,161,089,479 Our common units represent limited partner interests, which give the holders thereof the right to participate in distributions and to exercise the other rights or privileges available to them under our 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. The net cash proceeds we received from the issuance of common units during the year ended December 31, 2017 were used to temporarily reduce amounts outstanding under EPO’s commercial paper program and revolving credit facilities and for general partnership purposes. Universal shelf registration statement . See Note 22, Subsequent Events, for information regarding the issuance of senior notes and junior subordinated notes in February 2018 using the 2016 Shelf. At-the-Market (“ATM”) Program . During 2017, we issued 21,807,726 common units under the ATM program for aggregate gross cash proceeds of $603.1 million, resulting in total net cash proceeds of $597.0 million. During 2016, we issued 87,867,037 common units under the ATM program for aggregate gross cash proceeds of $2.17 billion, resulting in total net cash proceeds of $2.16 billion. This includes 3,830,256 common units sold in January 2016 to privately held affiliates of EPCO, which generated gross proceeds of $100 million. During 2015, we issued 25,520,424 common units under the ATM 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. Following the effectiveness of the new registration statement and after taking into account the aggregate sales price of common units sold under the ATM program through December 31, 2017, we have the capacity to issue additional common units under the ATM program up to an aggregate sales price of $2.54 billion. Distribution reinvestment plan Activity under our DRIP for the last three years was as follows: 18,541,355 common units issued during 2017, which generated net cash proceeds of $462.9 million; 15,809,503 common units issued during 2016, which generated net cash proceeds of $374.0 million; and 12,413,351 common units issued during 2015, which generated net cash proceeds of $359.8 million. Privately held affiliates of EPCO reinvested $100 million through the DRIP in each of the years ended December 31, 2017, 2016 and 2015 (this amount being a component of the net cash proceeds presented for each period). After taking into account the number of common units issued under the DRIP through December 31, 2017, we have the capacity to issue an additional 80,717,140 common units under this plan. Employee unit purchase plan . After taking into account the number of common units issued under the EUPP through December 31, 2017, we may issue an additional 5,760,811 common units under this plan. 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 Registration Rights Agreement Common units issued in connection with employee compensation Treasury Units A total of 681,044 restricted common unit awards granted to employees of EPCO vested and converted to common units during the year ended December 31, 2017. Of this amount, 229,910 were sold back to us by employees to cover related withholding tax requirements. In addition, 797,888 units were sold back to us by employees to cover withholding tax requirements related to the vesting of phantom unit awards. The total cost of these treasury unit purchases was approximately $29.5 million. We cancelled such treasury units immediately upon acquisition. See Note 13 for additional information regarding our equity-based awards. 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, 2015 $ 56.6 $ (279.5 ) $ 3.7 $ (219.2 ) Other comprehensive income (loss) before reclassifications (193.8 ) 42.3 (0.1 ) (151.6 ) Amounts reclassified from accumulated other comprehensive loss 53.4 37.4 -- 90.8 Total other comprehensive income (loss) (140.4 ) 79.7 (0.1 ) (60.8 ) Balance, December 31, 2016 (83.8 ) (199.8 ) 3.6 (280.0 ) Other comprehensive income (loss) before reclassifications (38.5 ) (5.7 ) (0.1 ) (44.3 ) Amounts reclassified from accumulated other comprehensive loss 112.2 40.4 -- 152.6 Total other comprehensive income (loss) 73.7 34.7 (0.1 ) 108.3 Balance, December 31, 2017 $ (10.1 ) $ (165.1 ) $ 3.5 $ (171.7 ) 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 2017 2016 Losses (gains) on cash flow hedges: Interest rate derivatives Interest expense $ 40.4 $ 37.4 Commodity derivatives Revenue 111.6 53.6 Commodity derivatives Operating costs and expenses 0.6 (0.2 ) Total $ 152.6 $ 90.8 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 (see Note 12). 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. 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, 2017 2016 2015 Limited partners of Oiltanking other than EPO $ -- $ -- $ 7.8 Joint venture partners 56.3 39.9 29.4 Total $ 56.3 $ 39.9 $ 37.2 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, 2017 2016 2015 Cash distributions paid to noncontrolling interests: Limited partners of Oiltanking other than EPO $ -- $ -- $ 8.1 Joint venture partners 49.2 47.4 39.9 Total $ 49.2 $ 47.4 $ 48.0 Cash contributions from noncontrolling interests: Joint venture partners $ 0.4 $ 20.4 $ 54.0 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 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 2016: 1st Quarter $ 0.3950 4/29/2016 5/6/2016 2nd Quarter $ 0.4000 7/29/2016 8/5/2016 3rd Quarter $ 0.4050 10/31/2016 11/7/2016 4th Quarter $ 0.4100 1/31/2017 2/7/2017 2017: 1st Quarter $ 0.4150 4/28/2017 5/8/2017 2nd Quarter $ 0.4200 7/31/2017 8/7/2017 3rd Quarter $ 0.4225 10/31/2017 11/7/2017 4th Quarter $ 0.4250 1/31/2018 2/7/2018 In October 2017, management announced plans to recommend to the Board cash distribution increases per quarter of $0.0025 per unit with respect to each of the six fiscal quarters beginning with the third quarter of 2017 and ending with the fourth quarter of 2018. Management currently expects to recommend to the Board the following quarterly cash distributions with respect to each quarter of 2018: $0.4275, first quarter of 2018; $0.4300, second quarter of 2018; $0.4325, third quarter of 2018; and $0.4350, fourth quarter of 2018. The payment of any quarterly cash distribution is subject to Board approval and management’s evaluation of our financial condition, results of operations and cash flows in connection with such payment. Management will propose recommendations to the Board regarding our cash distribution growth rate for 2019 as we consider future investment opportunities and alternatives for returning capital to investors. In November 2010, we completed our merger with Enterprise GP Holdings L.P. (the “Holdings Merger”). In connection with the Holdings Merger, a privately held affiliate of EPCO agreed to temporarily waive the regular cash distributions it would otherwise receive from us with respect to a certain number of our common units it owns (the “Designated Units”). Distributions paid by us to this privately held affiliate of EPCO during calendar year 2015 excluded 35,380,000 Designated Units. The temporary distribution waiver expired in November 2015; therefore, distributions paid during calendar years 2016 and 2017 were paid on all outstanding common units.

Business Segments

Business Segments	12 Months Ended
	Dec. 31, 2017
Business Segments [Abstract]
Business Segments	Segment Overview Our operations are reported under four business segments: (i) NGL Pipelines & Services, (ii) Crude Oil Pipelines & Services, (iii) Natural Gas Pipelines & Services and (iv) Petrochemical & Refined Products 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 Chief Executive Officer and President 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 associated NGL marketing activities; approximately 19,600 miles of NGL pipelines; NGL and related product storage facilities; and 14 NGL fractionators. This segment also includes our NGL export docks and related operations.  Our Crude Oil Pipelines & Services business segment includes approximately 5,800 miles of crude oil pipelines, crude oil storage terminals located in Oklahoma and Texas, and associated crude oil marketing activities.  Our Natural Gas Pipelines & Services business segment includes approximately 19,700 miles of natural gas pipeline systems that provide for the gathering and transportation of natural gas in Colorado, Louisiana, New Mexico, Texas and Wyoming. This segment also includes our natural gas marketing activities.  Our Petrochemical & Refined Products Services business segment includes (i) propylene production facilities, which include our propylene fractionation units and recently completed PDH facility, approximately 800 miles of pipelines, and associated marketing operations; (ii) a butane isomerization complex and related deisobutanizer units; (iii) octane enhancement and high purity isobutylene production facilities; (iv) refined products pipelines aggregating approximately 4,100 miles, terminals and associated marketing activities; and (v) marine transportation. Our plants, pipelines and other fixed assets are located in the U.S. Sale of Offshore Business In July 2015, we completed the sale of our Offshore Business, which comprised 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. 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 did not have a major effect on our financial results. 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 – see Note 12). Segment Gross Operating Margin We evaluate segment performance based on our financial measure of gross operating margin. Gross operating margin is an important performance measure of the core profitability of our operations and forms the basis of our internal financial reporting. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results. 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. The following table presents our measurement of total segment gross operating margin for the periods presented. The GAAP financial measure most directly comparable to total segment gross operating margin is operating income. For the Year Ended December 31, 2017 2016 2015 Income before income taxes $ 2,881.3 $ 2,576.4 $ 2,555.9 Add total other expense, net 1,047.6 1,004.3 984.3 Operating income 3,928.9 3,580.7 3,540.2 Adjustments to reconcile operating income to total gross operating margin: Add depreciation, amortization and accretion expense in operating costs and expenses 1,531.3 1,456.7 1,428.2 Add asset impairment and related charges in operating costs and expenses 49.8 52.8 162.6 Add net losses or subtract net gains attributable to asset sales in operating costs and expenses (10.7 ) (2.5 ) 15.6 Add general and administrative costs 181.1 160.1 192.6 Adjustments for make-up rights on certain new pipeline projects: Add non-refundable payments received from shippers attributable to make-up rights (1) 24.1 17.5 53.6 Subtract the subsequent recognition of revenues attributable to make-up rights (2) (29.9 ) (34.6 ) (60.7 ) Total segment gross operating margin $ 5,674.6 $ 5,230.7 $ 5,332.1 (1) Since make-up rights entail a future performance obligation by the pipeline to the shipper, these receipts are recorded as deferred revenue for GAAP purposes; however, these receipts are included in gross operating margin in the period of receipt since they are nonrefundable to the shipper. (2) As deferred revenues attributable to make-up rights are subsequently recognized as revenue under GAAP, gross operating margin must be adjusted to remove such amounts to prevent duplication since the associated non-refundable payments were previously included in gross operating margin. 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 may 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 under GAAP 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 new pipeline projects (Texas Express Pipeline, Front Range Pipeline, ATEX, Aegis Ethane Pipeline and Seaway Pipeline). From an internal (and segment) reporting standpoint, management considers the transportation fees paid by committed shippers on these 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. Although the adjustments for make-up rights are included in segment gross operating margin, our consolidated revenues do not reflect any deferred revenues until the conditions for recognizing such revenues are met in accordance with GAAP. Gross operating margin by segment is calculated by subtracting segment operating costs and expenses from segment revenues, with both segment totals reflecting the adjustments noted in the preceding table, as applicable, and before the elimination of intercompany transactions. The following table presents gross operating margin by segment for the periods indicated: For the Year Ended December 31, 2017 2016 2015 Gross operating margin by segment: NGL Pipelines & Services $ 3,258.3 $ 2,990.6 $ 2,771.6 Crude Oil Pipelines & Services 987.2 854.6 961.9 Natural Gas Pipelines & Services 714.5 734.9 782.6 Petrochemical & Refined Products Services 714.6 650.6 718.5 Offshore Pipelines & Services -- -- 97.5 Total segment gross operating margin $ 5,674.6 $ 5,230.7 $ 5,332.1 Summarized Segment Financial Information Information by business segment, together with reconciliations to amounts presented on our Statements of Consolidated Operations, 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, 2017 $ 12,455.7 $ 8,137.2 $ 3,132.5 $ 5,471.1 $ -- $ -- $ 29,196.5 Year ended December 31, 2016 10,232.7 6,478.7 2,532.4 3,721.8 -- -- 22,965.6 Year ended December 31, 2015 9,779.0 10,258.3 2,729.5 4,111.9 76.9 -- 26,955.6 Revenues from related parties: Year ended December 31, 2017 12.3 19.6 13.1 -- -- -- 45.0 Year ended December 31, 2016 9.8 36.3 10.6 -- -- -- 56.7 Year ended December 31, 2015 9.0 47.6 13.8 -- 1.9 -- 72.3 Intersegment and intrasegment revenues: Year ended December 31, 2017 27,278.6 15,943.0 850.8 1,766.9 -- (45,839.3 ) -- Year ended December 31, 2016 19,150.0 9,052.0 668.5 1,234.8 -- (30,105.3 ) -- Year ended December 31, 2015 10,217.9 5,162.0 662.1 1,126.0 0.6 (17,168.6 ) -- Total revenues: Year ended December 31, 2017 39,746.6 24,099.8 3,996.4 7,238.0 -- (45,839.3 ) 29,241.5 Year ended December 31, 2016 29,392.5 15,567.0 3,211.5 4,956.6 -- (30,105.3 ) 23,022.3 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 Equity in income (loss) of unconsolidated affiliates: Year ended December 31, 2017 73.4 358.4 3.8 (9.6 ) -- -- 426.0 Year ended December 31, 2016 61.4 311.9 3.8 (15.1 ) -- -- 362.0 Year ended December 31, 2015 57.5 281.4 3.8 (15.7 ) 46.6 -- 373.6 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 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 Front Range Pipeline and Texas Express Pipeline to transport mixed NGLs to our Mont Belvieu complex for fractionation and storage and the Seaway Pipeline to transport crude oil to our terminals in the Houston, Texas area. 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. Information by business segment, together with reconciliations to our Consolidated Balance Sheet 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 Property, plant and equipment, net: At December 31, 2017 $ 13,831.2 $ 5,208.4 $ 8,375.0 $ 3,507.7 $ -- $ 4,698.1 $ 35,620.4 At December 31, 2016 14,091.5 4,216.1 8,403.0 3,261.2 -- 3,320.7 33,292.5 At December 31, 2015 12,909.7 3,550.3 8,620.0 3,060.7 -- 3,894.0 32,034.7 Investments in unconsolidated affiliates: At December 31, 2017 733.9 1,839.2 20.8 65.5 -- -- 2,659.4 At December 31, 2016 750.4 1,824.6 21.7 80.6 -- -- 2,677.3 At December 31, 2015 718.7 1,813.4 22.5 73.9 -- -- 2,628.5 Intangible assets, net: At December 31, 2017 322.3 2,186.5 1,018.4 163.1 -- -- 3,690.3 At December 31, 2016 350.2 2,279.0 1,054.5 180.4 -- -- 3,864.1 At December 31, 2015 380.3 2,377.5 1,087.7 191.7 -- -- 4,037.2 Goodwill: At December 31, 2017 2,651.7 1,841.0 296.3 956.2 -- -- 5,745.2 At December 31, 2016 2,651.7 1,841.0 296.3 956.2 -- -- 5,745.2 At December 31, 2015 2,651.7 1,841.0 296.3 956.2 -- -- 5,745.2 Segment assets: At December 31, 2017 17,539.1 11,075.1 9,710.5 4,692.5 -- 4,698.1 47,715.3 At December 31, 2016 17,843.8 10,160.7 9,775.5 4,478.4 -- 3,320.7 45,579.1 At December 31, 2015 16,660.4 9,582.2 10,026.5 4,282.5 -- 3,894.0 44,445.6 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. 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). Other Revenue and Expense Information The following table presents supplemental information regarding our consolidated revenues and costs and expenses for the periods indicated: For the Year Ended December 31, 2017 2016 2015 Consolidated revenues: NGL Pipelines & Services $ 12,468.0 $ 10,242.5 $ 9,788.0 Crude Oil Pipelines & Services 8,156.8 6,515.0 10,305.9 Natural Gas Pipelines & Services 3,145.6 2,543.0 2,743.3 Petrochemical & Refined Products Services 5,471.1 3,721.8 4,111.9 Offshore Pipelines & Services -- -- 78.8 Total consolidated revenues $ 29,241.5 $ 23,022.3 $ 27,027.9 Consolidated costs and expenses: Operating costs and expenses: Cost of sales $ 21,487.0 $ 15,710.9 $ 19,612.9 Other operating costs and expenses (1) 2,500.1 2,425.6 2,449.4 Depreciation, amortization and accretion 1,531.3 1,456.7 1,428.2 Asset impairment and related charges 49.8 52.8 162.6 Ne t losses (g (10.7 ) (2.5 ) 15.6 General and administrative costs 181.1 160.1 192.6 Total consolidated costs and expenses $ 25,738.6 $ 19,803.6 $ 23,861.3 (1) Represents the cost of operating our plants, pipelines and other fixed assets excluding: depreciation, amortization and accretion charges; asset impairment and related charges; and net losses (or gains) attributable to asset sales and insurance recoveries. 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 2017 was (collectively, “ ”), which accounted for $3.29 billion, or 11.2%, of our consolidated revenues for the year. is a global energy and commodity trading company. The following table presents our consolidated revenues from by business segment for the year ended December 31, 2017: NGL Pipelines & Services $ 2,099.1 Crude Oil Pipelines & Services 625.6 Natural Gas Pipelines & Services 51.1 Petrochemical & Refined Products Services 512.5 Total $ 3,288.3 Vitol was our largest non-affiliated customer for 2016, accounting for 9.9% of our consolidated revenues. Shell Oil Company and its affiliates was our largest non-affiliated customer for 2015, accounting for 7.4%, of our consolidated revenues.

Earnings Per Unit

Earnings Per Unit	12 Months Ended
	Dec. 31, 2017
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 excluded the Designated Units (see Note 9) to the extent such units did 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 Designated Units outstanding during a period and (iii) the number of incremental common units resulting from the assumed exercise of dilutive unit options outstanding during a period (the “incremental option units”). In a period of net losses, the 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, 2017 2016 2015 BASIC EARNINGS PER UNIT Net income attributable to limited partners $ 2,799.3 $ 2,513.1 $ 2,521.2 Undistributed earnings allocated and cash payments on phantom unit awards (1) (15.9 ) (12.9 ) (8.7 ) Net income available to common unitholders $ 2,783.4 $ 2,500.2 $ 2,512.5 Basic weighted-average number of common units outstanding 2,145.0 2,081.4 1,966.6 Basic earnings per unit $ 1.30 $ 1.20 $ 1.28 DILUTED EARNINGS PER UNIT Net income attributable to limited partners $ 2,799.3 $ 2,513.1 $ 2,521.2 Diluted weighted-average number of units outstanding: Distribution-bearing common units 2,145.0 2,081.4 1,966.6 Designated Units -- -- 26.5 Phantom units (1) 9.3 7.7 5.4 Incremental option units -- -- 0.1 Total 2,154.3 2,089.1 1,998.6 Diluted earnings per unit $ 1.30 $ 1.20 $ 1.26 (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.

Business Combinations

Business Combinations	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Business Combinations	Acquisition of Azure Midstream In April 2017, we closed the acquisition of a midstream energy business from Azure Midstream Partners, LP and its operating subsidiaries (collectively, “Azure”) for $191.4 million in cash. The acquired business assets, which are located primarily in East Texas, include over 750 miles of natural gas gathering pipelines and two natural gas processing facilities (Panola and Fairway) with an aggregate processing capacity of 130 MMcf/d. The acquired business primarily serves production from the Haynesville Shale and Bossier, Cotton Valley and Travis Peak formations. The financial results of the acquired business are reflected in our consolidated results from April 30, 2017, which was the effective date of the Azure acquisition. On a historical pro forma consolidated basis, our revenues, costs and expenses, operating income, net income attributable to Enterprise Products Partners L.P., and earnings per unit amounts for the years ended December 31, 2017 and 2016 would not have differed materially from those we actually reported had the Azure acquisition been completed on January 1, 2016 rather than April 30, 2017. The following table presents the final fair value allocation of assets acquired and liabilities assumed in the Azure acquisition at April 30, 2017. Assets acquired in business combination: Current assets $ 3.1 Property, plant and equipment 193.1 Total assets acquired 196.2 Liabilities assumed in business combination: Current liabilities 1.4 Long-term liabilities 3.4 Total liabilities assumed 4.8 Cash used for Azure acquisition $ 191.4 The contribution of this newly acquired business to our consolidated revenues and net income was not material for the year ended December 31, 2017. Acquisition of EFS Midstream In July 2015, we purchased EFS Midstream from affiliates of PXD and Reliance for approximately $2.1 billion, which was payable in two installments. The initial payment of $1.1 billion was paid at closing on July 8, 2015. The second and final installment of $1.0 billion was paid on July 11, 2016 using a combination of cash on hand and proceeds from the issuance of short-term notes under EPO’s commercial paper program. The EFS Midstream System provides condensate gathering and processing services as well as gathering, treating and compression services for the associated natural gas. 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, PXD and Reliance dedicated certain of their Eagle Ford Shale acreage to us under 20-year, fixed-fee gathering agreements that include minimum volume requirements for the first seven years. PXD and Reliance 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 PXD 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. Since the effective date of the EFS Midstream acquisition was July 1, 2015, our Statements of Consolidated Operations do not reflect any earnings from this business prior to this date. Our consolidated revenues and net income for the last six months ended December 31, 2015 include $117.8 million and $59.9 million, respectively, from EFS Midstream. The following table presents selected unaudited pro forma earnings information for the year ended December 31, 2015 as if the acquisition had been completed on January 1, 2015. 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 year ended December 31, 2015 had we acquired EFS Midstream on January 1, 2015. Pro forma earnings data: Revenues $ 27,148.5 Costs and expenses 23,937.1 Operating income 3,585.0 Net income 2,594.4 Net income attributable to noncontrolling interests 37.2 Net income attributable to limited partners 2,557.2 Basic earnings per unit: As reported basic earnings per unit $ 1.28 Pro forma basic earnings per unit $ 1.30 Diluted earnings per unit: As reported diluted earnings per unit $ 1.26 Pro forma diluted earnings per unit $ 1.28 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. Oiltanking owned marine terminals located on the Houston Ship Channel and at the Port of Beaumont featuring a number of ship and barge docks and extensive crude oil and petroleum products storage capacity. 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. 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).

Equity-Based Awards

Equity-Based Awards	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 2015 Equity-classified awards: Phantom unit awards $ 92.8 $ 78.6 $ 78.3 Restricted common unit awards 0.5 4.7 14.7 Profits interest awards 6.0 5.4 -- Liability-classified awards 0.4 0.5 0.2 Total $ 99.7 $ 89.2 $ 93.2 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, 2017, all of the phantom unit awards were granted under EPCO’s 2008 Enterprise Products Long-Term Incentive Plan (Third Amendment and Restatement) (“2008 Plan”). The 2008 Plan 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, distribution equivalent rights (“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 authorized for issuance under the 2008 Plan was 40,000,000 at December 31, 2017. This amount automatically increased under the terms of the 2008 Plan by 5,000,000 common units on January 1, 2018 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, 2017, a total of 19,091,065 additional common units were available for issuance. During 2016, EPCO formed four limited partnerships (generally referred to as “Employee Partnerships”) to serve as long-term incentive arrangements for key employees of EPCO by providing them a “profits interest” in an Employee Partnership. The names of the Employee Partnerships are EPD PubCo Unit I L.P. (“PubCo I”), EPD PubCo Unit II L.P. (“PubCo II”), EPD PubCo Unit III L.P. (“PubCo III”) and EPD PrivCo Unit I L.P. (“PrivCo I”). The Employee Partnerships are discussed later in this note. At December 31, 2017, there were no restricted common unit awards outstanding under the Enterprise Products 1998 Long-Term Incentive Plan (“1998 Plan”). The 1998 Plan is effectively closed and no new awards have been granted under this plan since 2014. The 1998 Plan provided 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. Historically, awards under the 1998 Plan consisted of unit options and restricted common units. 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. All of the phantom unit awards were issued under the 2008 Plan. At December 31, 2017, substantially all of our phantom unit awards are expected to result in the issuance of common units upon vesting; therefore, the applicable awards are accounted for as equity-classified awards. The grant date fair value of a phantom unit award is based on the market price per unit of our common units on the date of grant. Compensation expense is recognized based on the grant date fair value, net of an allowance for estimated forfeitures, over the requisite service or vesting period. The following table presents phantom unit award activity for the periods indicated: Number of Units Weighted- Average Grant Date Fair Value per Unit Phantom unit awards at January 1, 2015 3,342,390 $ 33.13 Granted (2) 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 Granted (3) 4,508,310 $ 21.90 Vested (1,761,455 ) $ 33.10 Forfeited (406,303 ) $ 28.52 Phantom unit awards at December 31, 2016 7,767,501 $ 27.20 Granted (4) 4,268,920 $ 28.83 Vested (2,490,081 ) $ 28.30 Forfeited (256,839 ) $ 27.60 Phantom unit awards at December 31, 2017 9,289,501 $ 27.65 (1) Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued. (2) The aggregate grant date fair value of phantom unit awards issued during 2015 was $118.7 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 percent was applied to these awards. (3) The aggregate grant date fair value of phantom unit awards issued during 2016 was $98.7 million based on a grant date market price of our common units ranging from $21.86 to $27.39 per unit. An estimated annual forfeiture rate of 3.9 percent was applied to these awards. (4) The aggregate grant date fair value of phantom unit awards issued during 2017 was $123.1 million based on a grant date market price of our common units ranging from $24.55 to $28.87 per unit. An estimated annual forfeiture rate of 3.8 percent was applied to these awards. After taking into account tax withholding requirements, we issued 1,687,692, 1,170,600 and 618,395 common units in connection with the vesting of phantom unit awards in the years ended December 31, 2017, 2016 and 2015, respectively. The 2008 Plan provides 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 phantom unit awards for the periods indicated: For the Year Ended December 31, 2017 2016 2015 Cash payments made in connection with DERs $ 15.1 $ 11.7 $ 7.7 Total intrinsic value of phantom unit awards that vested during period $ 69.8 $ 40.9 $ 31.2 For the EPCO group of companies, the unrecognized compensation cost associated with phantom unit awards was $92.3 million at December 31, 2017, of which our share of the cost is currently estimated to be $77.5 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 2.1 years. Profits Interest Awards In February and April 2016, EPCO Holdings Inc. (“EPCO Holdings”), a privately held affiliate of EPCO, contributed a portion of the Enterprise common units it owned to each of the Employee Partnerships as disclosed in the table below. In exchange for these contributions, EPCO Holdings was admitted as the Class A limited partner of each Employee Partnership. Also on the applicable contribution date, certain key EPCO employees were issued Class B limited partner interests (i.e., profits interest awards) and admitted as Class B limited partners of each Employee Partnership, all without any capital contribution by such employees. EPCO serves as the general partner of each Employee Partnership. In general, the Class A limited partner earns a quarterly preferred return equal to $0.39 per unit on the number of Enterprise common units contributed by EPCO Holdings to each Employee Partnership, with any residual cash amount remaining in each Employee Partnership being paid to the applicable Class B limited partners on a quarterly basis as a distribution. Upon liquidation of an Employee Partnership, assets having a then current fair market value equal to the Class A limited partner’s capital base in such Employee Partnership will be distributed to the Class A limited partner. Any remaining assets of such Employee Partnership will be distributed to the Class B limited partners of such Employee Partnership as a residual profits interest, which represents the appreciation in value of the Employee Partnership’s assets since the date of EPCO Holdings’ contribution to it, as described above. Unless otherwise agreed to by EPCO and a majority in interest of the limited partners of each Employee Partnership, such Employee Partnership will terminate at the earliest to occur of (i) 30 days following its vesting date, (ii) a change of control or (iii) a dissolution of the Employee Partnership. Individually, each Class B limited partner interest is subject to forfeiture if the participating employee’s employment with EPCO is terminated prior to vesting, with customary exceptions for death, disability and certain retirements. The risk of forfeiture will also lapse upon certain change of control events. Forfeited individual Class B limited partner interests are allocated to the remaining Class B limited partners. The following table summarizes key elements of each Employee Partnership as of December 31, 2017: Employee Partnership Enterprise Common Units contributed to Employee Partnership by EPCO Holdings Class A Capital Base Class A Preference Return Expected Vesting/ Liquidation Date Estimated Grant Date Fair Value of Profits Interest Awards Unrecognized Compensation Cost PubCo I 2,723,052 $63.7 million $ 0.39 Feb. 2020 $13.2 million $7.4 million PubCo II 2,834,198 $66.3 million $ 0.39 Feb. 2021 $14.7 million $9.3 million PubCo III 105,000 $2.5 million $ 0.39 Apr. 2020 $0.6 million $0.2 million PrivCo I 1,111,438 $26.0 million $ 0.39 Feb. 2021 $5.8 million $0.8 million (1) Represents fair market value of the Enterprise common units contributed to each Employee Partnership at the applicable contribution date. (2) Each quarter, the Class A limited partner in each Employee Partnership is paid a cash distribution equal to the product of (i) the number of common units owned by the Employee Partnership and (ii) the Class A Preference Return of $0.39 per unit (subject to equitable adjustment in order to reflect any equity split, equity distribution or dividend, reverse split, combination, reclassification, recapitalization or other similar event affecting such common units). To the extent that the Employee Partnership has cash remaining after making this quarterly payment to the Class A limited partner, the residual cash is distributed to the Class B limited partners on a quarterly basis. (3) Represents the total grant date fair value of the profits interest awards irrespective of how such costs will be allocated between us and EPCO and its privately held affiliates. (4) Represents our expected share of the unrecognized compensation cost at December 31, 2017. We expect to recognize our share of the unrecognized compensation cost for PubCo I, PubCo II, PubCo III and PrivCo I over a weighted-average period of 2.1 years, 3.1 years, 2.3 years and 3.1 years, respectively. The grant date fair value of each Employee Partnership is based on (i) the estimated value (as determined using a Black-Scholes option pricing model) of such Employee Partnership’s assets that would be distributed to the Class B limited partners thereof upon liquidation and (ii) the value, based on a discounted cash flow analysis, of the residual quarterly cash amounts that such Class B limited partners are expected to receive over the life of the Employee Partnership. The following table summarizes the assumptions we used in applying a Black-Scholes option pricing model to derive that portion of the estimated grant date fair value of the profits interest awards for each Employee Partnership: Expected Risk-Free Expected Expected Unit Employee Life Interest Distribution Price Partnership of Award Rate Yield Volatility PubCo I 4.0 years 0.9% to 1.6% 6.2% to 7.0% 29% to 40% PubCo II 5.0 years 1.1% to 1.8% 6.1% to 7.0% 27% to 40% PubCo III 4.0 years 1.0% to 1.4% 6.1% to 6.2% 31% to 40% PrivCo I 5.0 years 1.2% to 1.6% 6.1% to 6.7% 28% to 40% Compensation expense attributable to the profits interest awards is based on the estimated grant date fair value of each award. A portion of the fair value of these equity-based awards is allocated to us under the ASA as a non-cash expense. We are not responsible for reimbursing EPCO for any expenses of the Employee Partnerships, including the value of any contributions of units made by EPCO Holdings. 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 January 1, 2015 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 Vested (1,234,502 ) $ 27.45 Forfeited (43,724 ) $ 28.48 Restricted common units at December 31, 2016 682,294 $ 28.61 Vested (681,044 ) $ 28.60 Forfeited (1,250 ) $ 31.07 Restricted common units at December 31, 2017 -- N/A (1) Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued. Each recipient of a restricted common unit award is entitled to nonforfeitable cash distributions equal to the product of the number of restricted common units outstanding for the participant and the cash distribution per unit paid to our common unitholders. These distributions are included in “Cash distributions paid to limited partners” as presented on our Statements of Consolidated Cash Flows. The following table presents supplemental information regarding restricted common unit awards for the periods indicated: For the Year Ended December 31, 2017 2016 2015 Cash distributions paid to restricted common unitholders $ 0.3 $ 1.6 $ 4.0 Total intrinsic value of restricted common unit awards that vested during period $ 18.9 $ 28.5 $ 67.3 Unit Option Awards EPCO’s long-term incentive plans provide for the issuance of non-qualified incentive options denominated in our common units. Historically, our unit option awards were issued under the 1998 Plan. All such awards had been exercised as of December 31, 2015 and no new unit option awards were granted during the three years ended December 31, 2017. 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 period indicated: Number of Units Weighted- Average Strike Price (dollars/unit) Unit option awards at January 1, 2015 1,270,000 $ 16.14 Exercised (1,270,000 ) $ 16.14 Unit option awards at December 31, 2015 -- $ -- In order to fund its unit option award-related obligations, EPCO purchased our common units at fair value directly from us. When employees exercised unit option awards, we reimbursed EPCO for the cash difference between the strike price paid by the employee and the actual purchase price paid by EPCO for the units issued to the employee. The following table presents supplemental information regarding unit option awards during the year ended December 31, 2015: Total intrinsic value of unit option awards exercised during period $ 21.7 Cash received from EPCO in connection with the exercise of unit option awards $ 13.1 Unit option award-related cash reimbursements to EPCO $ 21.7

Derivative Instruments, Hedging

Derivative Instruments, Hedging Activities and Fair Value Measurements	12 Months Ended
	Dec. 31, 2017
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, 2017: 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 1.87% Fair value hedge At December 31, 2017, our portfolio of forward starting swaps was as follows: Hedged Transaction Number and Type of Derivatives Outstanding Notional Amount Expected Settlement Date Average Rate Locked Accounting Treatment Future long-term debt offering 3 forward starting swaps $ 275.0 2/2019 2.57% Cash flow hedge As a result of market conditions in January 2018, we elected to terminate $100 million notional amount of the forward starting swaps that were outstanding at December 31, 2017, which resulted in cash gains totaling $1.5 million for the first quarter of 2018. As a result of market conditions in August 2017, we elected to terminate forward starting swaps that were scheduled to settle in May 2018, which resulted in cash gains totaling $30.6 million. As cash flow hedges, gains on these derivative instruments will be reflected as a component of accumulated other comprehensive income and be amortized to earnings (as a decrease in interest expense) over the life of the associated future debt obligations beginning in May 2018. As a result of market conditions in October 2016, we elected to terminate forward starting swaps that were scheduled to settle in September 2017, which resulted in cash gains totaling $6.1 million. As cash flow hedges, gains on these derivative instruments will be reflected as a component of accumulated other comprehensive income and be amortized to earnings (as a decrease in interest expense) over the life of the associated future debt obligations beginning in September 2017. 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 and basis swaps. At December 31, 2017, 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 derivative instruments and related contracts.  The objective of our natural gas processing hedging program is to hedge an amount of earnings associated with these activities. We achieve this objective by executing fixed-price sales for a portion of our expected equity NGL production using derivative instruments and related contracts. For certain natural gas processing contracts, the hedging of expected equity NGL production also involves the purchase of natural gas for shrinkage, which is hedged using derivative instruments and related contracts.  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 derivative instruments and related contracts. The following table summarizes our portfolio of commodity derivative instruments outstanding at December 31, 2017 (volume measures as noted): Volume Accounting Derivative Purpose Current Long-Term Treatment Derivatives designated as hedging instruments: Octane enhancement: Forecasted purchase of NGLs (MMBbls) 1.1 n/a Cash flow hedge Forecasted sales of octane enhancement products (MMBbls) 1.0 n/a Cash flow hedge Natural gas marketing: Forecasted purchases of natural gas for fuel (Bcf) 1.0 n/a Cash flow hedge Natural gas storage inventory management activities (Bcf) 3.9 n/a Fair value hedge NGL marketing: Forecasted purchases of NGLs and related hydrocarbon products (MMBbls) 49.0 n/a Cash flow hedge Forecasted sales of NGLs and related hydrocarbon products (MMBbls) 64.6 n/a Cash flow hedge NGLs inventory management activities (MMBbls) 0.5 n/a Fair value hedge Refined products marketing: Forecasted purchases of refined products (MMBbls) 0.6 n/a Cash flow hedge Forecasted sales of refined products (MMBbls) 1.3 n/a Cash flow hedge Refined products inventory management activities (MMBbls) 0.5 n/a Fair value hedge Crude oil marketing: Forecasted purchases of crude oil (MMBbls) 3.7 3.3 Cash flow hedge Forecasted sales of crude oil (MMBbls) 6.9 3.3 Cash flow hedge Petrochemical marketing: Forecasted purchases of NGLs for propylene marketing activities (MMBbls) 0.8 n/a Cash flow hedge Derivatives not designated as hedging instruments: Natural gas risk management activities (Bcf) (3,4) 67.3 9.0 Mark-to-market NGL risk management activities (MMBbls) (4) 18.3 n/a Mark-to-market Refined products risk management activities (MMBbls) (4) 0.6 n/a Mark-to-market Crude oil risk management activities (MMBbls) (4) 104.0 12.2 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 2020, May 2018 and December 2020, respectively. (3) Current and long-term volumes include 21.1 Bcf and 5.3 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. 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, 2017 December 31, 2016 December 31, 2017 December 31, 2016 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 $ -- Current assets $ 0.3 Current liabilities $ 1.5 Current liabilities $ 0.2 Interest rate derivatives Other assets 0.1 Other assets 36.2 Other liabilities 0.2 Other liabilities 0.9 Total interest rate derivatives 0.1 36.5 1.7 1.1 Commodity derivatives Current assets 109.5 Current assets 499.2 Current liabilities 104.4 Current liabilities 662.0 Commodity derivatives Other assets 6.4 Other assets -- Other liabilities 6.8 Other liabilities -- Total commodity derivatives 115.9 499.2 111.2 662.0 Total derivatives designated as hedging instruments $ 116.0 $ 535.7 $ 112.9 $ 663.1 Derivatives not designated as hedging instruments Commodity derivatives Current assets $ 43.9 Current assets $ 41.9 Current liabilities $ 62.3 Current liabilities $ 75.5 Commodity derivatives Other assets 1.9 Other assets 0.3 Other liabilities 3.4 Other liabilities 1.9 Total commodity derivatives 45.8 42.2 65.7 77.4 Total derivatives not designated as hedging instruments $ 45.8 $ 42.2 $ 65.7 $ 77.4 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, 2017: Interest rate derivatives $ 0.1 $ -- $ 0.1 $ (0.1 ) $ -- $ -- $ -- Commodity derivatives 161.7 -- 161.7 (157.8 ) -- -- 3.9 As of December 31, 2016: Interest rate derivatives $ 36.5 $ -- $ 36.5 $ (0.2 ) $ -- $ -- $ 36.3 Commodity derivatives 541.4 -- 541.4 (526.8 ) -- -- 14.6 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, 2017: Interest rate derivatives $ 1.7 $ -- $ 1.7 $ (0.1 ) $ -- $ 1.6 Commodity derivatives 176.9 -- 176.9 (157.8 ) (17.3 ) 1.8 As of December 31, 2016: Interest rate derivatives $ 1.1 $ -- $ 1.1 $ (0.2 ) $ -- $ 0.9 Commodity derivatives 739.4 -- 739.4 (526.8 ) (212.4 ) 0.2 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, 2017 2016 2015 Interest rate derivatives Interest expense $ (0.2 ) $ 0.3 $ (1.4 ) Commodity derivatives Revenue 1.1 (90.5 ) 19.1 Total $ 0.9 $ (90.2 ) $ 17.7 Derivatives in Fair Value Hedging Relationships Location Gain (Loss) Recognized in Income on Hedged Item For the Year Ended December 31, 2017 2016 2015 Interest rate derivatives Interest expense $ 0.4 $ (0.4 ) $ 1.4 Commodity derivatives Revenue 27.4 125.0 0.2 Total $ 27.8 $ 124.6 $ 1.6 For the years ended December 31, 2017 and 2016, the net gains of $28.5 million and $34.5 million, respectively, recognized in income from our commodity derivatives designated as fair value hedges includes $1.0 million and $1.1 million, respectively, of net gains attributable to hedge ineffectiveness. The remaining $27.5 million and $33.4 million was a net gain that was recognized during the years ended December 31, 2017 and 2016, respectively, and primarily related to prompt-to-forward month price differentials that were excluded from the assessment of hedge effectiveness. Net gains or losses due to ineffectiveness and from those amounts excluded from the assessment of hedge effectiveness were immaterial for all other 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, 2017 2016 2015 Interest rate derivatives $ (5.7 ) $ 42.3 $ -- Commodity derivatives – Revenue (1) (33.7 ) (197.4 ) 217.6 Commodity derivatives – Operating costs and expenses (1) (4.8 ) 3.6 (2.7 ) Total $ (44.2 ) $ (151.5 ) $ 214.9 (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, 2017 2016 2015 Interest rate derivatives Interest expense $ (40.4 ) $ (37.4 ) $ (35.3 ) Commodity derivatives Revenue (111.6 ) (53.6 ) 231.7 Commodity derivatives Operating costs and expenses (0.6 ) 0.2 (3.5 ) Total $ (152.6 ) $ (90.8 ) $ 192.9 Derivatives in Cash Flow Hedging Relationships Location Gain (Loss) Recognized in Income on Derivative (Ineffective Portion) For the Year Ended December 31, 2017 2016 2015 Commodity derivatives Revenue $ -- $ -- $ 4.7 Commodity derivatives Operating costs and expenses (1.1 ) 0.5 0.1 Total $ (1.1 ) $ 0.5 $ 4.8 Over the next twelve months, we expect to reclassify $38.4 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 $9.7 million of losses attributable to commodity derivative instruments from accumulated other comprehensive income to earnings, $9.4 million as decrease in revenue and $0.3 million as an increase 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, 2017 2016 2015 Interest rate derivatives Interest expense $ -- $ -- $ -- Commodity derivatives Revenue (42.7 ) (38.4 ) 1.0 Commodity derivatives Operating costs and expenses 0.1 (0.4 ) 0.1 Total $ (42.6 ) $ (38.8 ) $ 1.1 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. The values for commodity derivatives at December 31, 2017 are presented before and after the application of CME Rule 814, which deems that financial instruments cleared by the CME are settled daily in connection with variation margin payments. As a result of this new exchange rule, CME-related derivatives are considered to have no fair value at the balance sheet date for financial reporting purposes; however, the derivatives remain outstanding and subject to future commodity price fluctuations until they are settled in accordance with their contractual terms. The rule change was effective January 1, 2017. December 31, 2017 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 $ -- $ 0.1 $ -- $ 0.1 Commodity derivatives: Value before application of CME Rule 814 47.1 184.9 2.9 234.9 Impact of CME Rule 814 change (47.1 ) (26.1 ) -- (73.2 ) Total commodity derivatives -- 158.8 2.9 161.7 Total $ -- $ 158.9 $ 2.9 $ 161.8 Financial liabilities: Liquidity Option Agreement $ -- $ -- $ 333.9 $ 333.9 Interest rate derivatives -- 1.7 -- 1.7 Commodity derivatives: Value before application of CME Rule 814 118.4 270.6 1.7 390.7 Impact of CME Rule 814 change (118.4 ) (95.4 ) -- (213.8 ) Total commodity derivatives -- 175.2 1.7 176.9 Total $ -- $ 176.9 $ 335.6 $ 512.5 December 31, 2016 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 $ -- $ 36.5 $ -- $ 36.5 Commodity derivatives 84.5 455.2 1.7 541.4 Total $ 84.5 $ 491.7 $ 1.7 $ 577.9 Financial liabilities: Liquidity Option Agreement $ -- $ -- $ 269.6 $ 269.6 Interest rate derivatives -- 1.1 -- 1.1 Commodity derivatives 136.8 602.3 0.3 739.4 Total $ 136.8 $ 603.4 $ 269.9 $ 1,010.1 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 2017 2016 Financial asset (liability) balance, net, January 1 $ (268.2 ) $ (246.7 ) Total gains (losses) included in: Net income (1) Revenue 2.3 2.2 Net income Other expense, net (64.3 ) (24.5 ) Other comprehensive income (loss) Commodity derivative instruments – changes in fair value of cash flow hedges 0.1 (0.5 ) Settlements (1) Revenue (2.4 ) (0.5 ) Transfers out of Level 3 (2) (0.2 ) 1.8 Financial liability balance, net, December 31 $ (332.7 ) $ (268.2 ) (1) There were $0.1 million of unrealized losses and $1.7 million of unrealized gains included in these amounts for the years ended December 31, 2017 and 2016, 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, 2017 and 2016. The following Fair Value At December 31, 2017 Financial Assets Financial Liabilities Valuation Techniques Unobservable Input Range Commodity derivatives – Crude oil $ 2.9 $ 1.7 Discounted cash flow Forward commodity prices $60.21-$66.05/barrel Total $ 2.9 $ 1.7 Fair Value At December 31, 2016 Financial Assets Financial Liabilities Valuation Techniques Unobservable Input Range Commodity derivatives – Crude oil $ 1.7 $ 0.3 Discounted cash flow Forward commodity prices $51.73-$54.77/barrel Total $ 1.7 $ 0.3 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, 2017. 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 Long-lived assets (including intangible assets with finite useful lives and property, plant and equipment) are reviewed for impairment (i.e., subject to nonrecurring fair value measurements) when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Long-lived assets with carrying values that are not expected to be recovered through future cash flows are written-down to their estimated fair values. The following table summarizes our non-cash asset impairment charges for long-lived assets by segment during each of the periods indicated: For the Year Ended December 31, 2017 2016 2015 NGL Pipelines & Services $ 11.5 $ 21.0 $ 20.8 Crude Oil Pipelines & Services 10.2 2.3 33.5 Natural Gas Pipelines & Services 14.3 12.3 21.6 Petrochemical & Refined Products Services 1.8 9.6 28.2 Offshore Pipelines & Services -- -- 58.5 Total $ 37.8 $ 45.2 $ 162.6 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. 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, 2017: Fair Value Measurements at the End of the Reporting Period Using Carrying Value at December 31, 2017 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 $ -- $ -- $ -- $ -- $ 16.7 Long-lived assets held and used 1.5 -- -- 1.5 15.4 Long-lived assets held for sale 2.5 -- -- 2.5 2.5 Long-lived assets disposed of by sale -- -- -- -- 3.2 Total $ 37.8 Total non-cash asset impairment and related charges during 2017 were $49.8 million, which consisted of $37.8 million of impairment charges attributable to long-lived assets and $12.0 million of impairment charges attributable to the write-down of surplus materials classified as current assets. Impairment charges attributable to long-lived assets were primarily due to the write-down of certain natural gas pipeline laterals and other pipelines in Texas, which accounted for $13.0 million in charges, and for the planned abandonment of certain storage and pipeline assets in Texas, which accounted for an additional $12.4 million in charges. 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, 2016: Fair Value Measurements at the End of the Reporting Period Using Carrying Value at December 31, 2016 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 $ -- $ -- $ -- $ -- $ 29.9 Long-lived assets held and used 8.0 8.0 -- -- 2.2 Long-lived assets disposed of by sale -- -- -- -- 13.1 Total $ 45.2 Total non -cash asset impairment and related charges during 2016 were $53.5 million, which consisted of $45.2 million of impairment charges attributable to long-lived assets, $1.2 million of impairment charges attributable to the write-down of surplus materials classified as current assets, and $7.1 million of related charges for equipment destroyed by fire at our Pascagoula gas plant. Impairment charges attributable to long-lived assets primarily relate to the planned abandonment of certain plant and pipeline assets in Texas and New Mexico. 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 and the abandonment of certain natural gas and crude oil pipeline assets in Texas. The following table presents categories of long-lived assets 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 -- -- -- -- 67.0 Total $ 162.6 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 $23.47 billion and $21.95 billion at December 31, 2017 and 2016, respectively. The aggregate carrying value of these debt obligations was $21.48 billion and $20.85 billion at December 31, 2017 and 2016, respectively. These values are primarily based on quoted market prices for such debt or debt of similar terms and maturities (Level 2) and our credit standing. Changes in market rates of interest affect the fair value of our fixed-rate debt. The amounts reported for fixed-rate debt obligations exclude those amounts hedged using fixed-to-floating interest rate swaps. See “ Interest Rate Hedging Activities The carrying values of our variable-rate long-term debt obligations approximate their fair values since the associated interest rates are market-based. We do not have any long-term investments in debt or equity securities recorded at fair value.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 2015 Revenues – related parties: Unconsolidated affiliates $ 45.0 $ 56.7 $ 72.3 Costs and expenses – related parties: EPCO and its privately held affiliates $ 1,010.9 $ 963.2 $ 949.3 Unconsolidated affiliates 223.4 253.9 245.3 Total $ 1,234.3 $ 1,217.1 $ 1,194.6 The following table summarizes our related party accounts receivable and accounts payable balances at the dates indicated: December 31, 2017 2016 Accounts receivable - related parties: Unconsolidated affiliates $ 1.8 $ 1.1 Accounts payable - related parties: EPCO and its privately held affiliates $ 99.3 $ 88.9 Unconsolidated affiliates 28.0 16.2 Total $ 127.3 $ 105.1 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, 2017, 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 689,767,023 32% Of the total number of units held by EPCO and its privately held affiliates, 81,346,154 have been pledged as security under the credit facilities of EPCO and its privately held affiliates at December 31, 2017. 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, 2017, 2016 and 2015, we paid EPCO and its privately held affiliates cash distributions totaling $1.12 billion, $1.07 billion and $948.3 million, respectively. Distributions paid during the year ended December 31, 2015 excluded 35,380,000 Designated Units (see Note 9). From time-to-time, EPCO and its privately held affiliates elect to purchase additional common units under our DRIP and our ATM program. In January 2016 and March 2015, privately held affiliates of EPCO purchased 3,830,256 and 3,225,057 common units, respectively, from us under our ATM program, generating gross proceeds of $100 million during each year. In November 2017, privately held affiliates of EPCO reinvested $100 million through our DRIP, resulting in the issuance of an additional 4,246,498 of our common units. For each of the years ended December 31, 2016 and 2015, DRIP purchases by privately held affiliates of EPCO totaled $100 million. See Note 9 for additional information regarding our ATM program and DRIP. 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, 2017 2016 2015 Operating costs and expenses $ 882.1 $ 840.7 $ 826.4 General and administrative expenses 110.4 105.3 105.2 Total costs and expenses $ 992.5 $ 946.0 $ 931.6 Since the vast majority of such expenses are charged to us on an actual basis (i.e., no mark-up is charged or subsidy is received), 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, 2017, 2016 and 2015, we paid Seaway $98.8 million, $161.2 million and $175.8 million, respectively, for pipeline transportation and storage services in connection with our crude oil marketing activities. Revenues from Seaway were $19.6 million, $36.3 million and $47.7 million for the years ended December 31, 2017, 2016 and 2015, 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 $7.8 million, $7.0 million and $8.8 million for the years ended December 31, 2017, 2016 and 2015, respectively. Expenses with Promix were $27.8 million, $27.1 million and $24.9 million for the years ended December 31, 2017, 2016 and 2015, respectively.  For the years ended December 31, 2017, 2016 and 2015, we paid Texas Express $29.5 million, $22.8 million and $6.7 million, respectively, for pipeline transportation services.  For the years ended December 31, 2017, 2016 and 2015, we paid Eagle Ford Crude Oil Pipeline $42.8 million, $36.2 million and $39.4 million, respectively, for crude oil transportation.  We perform management services for certain of our unconsolidated affiliates. We charged such affiliates $10.6 million, $10.7 million and $19.1 million for the years ended December 31, 2017, 2016 and 2015, respectively. The decrease in such amounts during 2016 is related to the sale of our Offshore Business.

Provision for Income Taxes

Provision for Income Taxes	12 Months Ended
	Dec. 31, 2017
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, 2017, 2016 and 2015 and, as a result, are not subject to federal income tax. However, our partners are individually responsible for paying federal income tax 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, 2017 2016 2015 Current: Federal $ 0.1 $ (0.5 ) $ 0.9 State 18.5 16.7 15.5 Foreign 1.0 0.6 1.7 Total current 19.6 16.8 18.1 Deferred: Federal (1.8 ) 1.1 (1.4 ) State 7.9 5.2 (19.2 ) Foreign -- 0.3 -- Total deferred 6.1 6.6 (20.6 ) Total provision for (benefit from) income taxes $ 25.7 $ 23.4 $ (2.5 ) 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, 2017 2016 2015 Pre-Tax Net Book Income (“NBI”) $ 2,881.3 $ 2,576.4 $ 2,555.9 Texas Margin Tax (1) $ 26.4 $ 22.1 $ (3.7 ) State income taxes (net of federal benefit) 0.5 0.2 0.7 Federal income taxes computed by applying the federal statutory rate to NBI of corporate entities 0.1 0.8 1.1 Other permanent differences (1.3 ) 0.3 (0.6 ) Provision for (benefit from) income taxes $ 25.7 $ 23.4 $ (2.5 ) Effective income tax rate 0.9% 0.9% (0.1)% (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, 2017 2016 Deferred tax assets: Net operating loss carryovers (1) $ 0.2 $ 0.2 Accruals 1.4 1.6 Total deferred tax assets 1.6 1.8 Less: Deferred tax liabilities: Property, plant and equipment 58.0 50.5 Equity investment in partnerships 2.1 3.7 Total deferred tax liabilities 60.1 54.2 Total net deferred tax liabilities $ 58.5 $ 52.4 (1) These losses expire in various years between 2018 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, 2017, 2016 or 2015.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
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, 2017 and 2016, our accruals for litigation contingencies were $4.5 million and $0.3 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 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 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. Oral argument was conducted on April 20, 2016, and the case was then submitted to the Court of Appeals for its consideration. On July 18, 2017, a panel of the Court of Appeals issued a unanimous opinion reversing the trial court’s judgment as to all of ETP’s claims against us, rendering judgment that ETP take nothing on those claims, and affirming our counterclaim against ETP of approximately $0.8 million, plus interest. On August 31, 2017, ETP filed a motion for rehearing before the Dallas Court of Appeals, which was denied on September 13, 2017. As of December 31, 2017, we have not recorded a provision for this matter as management continues to believe that payment of damages by us in this case is not probable. We continue to monitor developments involving this matter. PDH Litigation On September 2, 2016, we terminated AFW for cause and filed a lawsuit in the 151st Judicial Civil District Court of Harris County, Texas against AFW and its parent company, Amec Foster Wheeler plc, asserting claims for breach of contract, breach of warranty, fraudulent inducement, string-along fraud, gross negligence, professional negligence, negligent misrepresentation and attorneys’ fees. We intend to diligently prosecute these claims and seek all direct, consequential, and exemplary damages to which we may be entitled. 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, 2017, we had approximately 9.0 trillion British thermal units (“TBtus”) of natural gas, 15.8 MMBbls of crude oil, and 39.3 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, 2017. A description of each type of contractual obligation follows: Payment or Settlement due by Period Contractual Obligations Total 2018 2019 2020 2021 2022 Thereafter Scheduled maturities of debt obligations $ 24,780.1 $ 2,855.7 $ 1,500.0 $ 1,500.0 $ 575.0 $ 650.0 $ 17,699.4 Estimated cash interest payments $ 23,942.0 $ 1,082.9 $ 1,022.1 $ 964.2 $ 912.1 $ 884.7 $ 19,076.0 Operating lease obligations $ 413.3 $ 57.0 $ 52.8 $ 47.2 $ 40.0 $ 31.3 $ 185.0 Purchase obligations: Product purchase commitments: Estimated payment obligations: Natural gas $ 1,911.5 $ 615.1 $ 528.6 $ 434.9 $ 332.9 $ -- $ -- NGLs $ 99.0 $ 69.6 $ 29.4 $ -- $ -- $ -- $ -- Crude oil $ 7,891.3 $ 1,352.3 $ 1,341.0 $ 945.8 $ 728.4 $ 728.4 $ 2,795.4 Petrochemicals & refined products $ 632.1 $ 411.9 $ 214.1 $ 6.1 $ -- $ -- $ -- Other $ 33.3 $ 9.3 $ 9.3 $ 7.6 $ 3.5 $ 1.4 $ 2.2 Underlying major volume commitments: Natural gas (in TBtus) 812 265 225 182 140 -- -- NGLs (in MMBbls) 7 5 2 -- -- -- -- Crude oil (in MMBbls) 471 38 55 51 47 47 233 Petrochemicals & refined products (in MMBbls) 11 7 4 -- -- -- -- Service payment commitments $ 398.0 $ 98.3 $ 84.5 $ 60.0 $ 44.8 $ 43.1 $ 67.3 Capital expenditure commitments $ 171.6 $ 171.6 $ -- $ -- $ -- $ -- $ -- 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 $103.6 million, $110.1 million and $104.3 million during the years ended December 31, 2017, 2016 and 2015, respectively. Purchase Obligations .  We have long-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, 2017 applied to all future volume commitments. Actual future payment obligations may vary depending on prices at the time of delivery.  We have long-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 PXD 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. As of December 31, 2017, we have spent approximately $151 million of the $270 million commitment. Other Long-Term Liabilities The following table summarizes the components of “Other long-term liabilities” as presented on our Consolidated Balance Sheets at the dates indicated: December 31, 2017 2016 Noncurrent portion of AROs (see Note 5) $ 81.1 $ 76.5 Deferred revenues – non-current portion (see Note 3) 135.5 137.0 Liquidity Option Agreement 333.9 269.6 Derivative liabilities 10.4 2.8 Centennial guarantees 4.5 5.3 Other 13.0 12.7 Total $ 578.4 $ 503.9 Liquidity Option Agreement We entered into a put option agreement (the “Liquidity Option Agreement” or “Liquidity Option”) with OTA and Marquard & Bahls AG, a German corporation and the ultimate parent company of OTA (“M&B”), in connection with the Oiltanking acquisition (see Note 12). Under the Liquidity Option Agreement, we granted M&B the option to sell to us 100% of the issued and outstanding capital stock of OTA at any time within a 90-day period commencing on February 1, 2020. If the Liquidity Option is exercised, we would indirectly acquire any Enterprise common units then 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 deferred tax liabilities. To the extent that the sum of OTA’s deferred tax liabilities exceeds the then current book value of the Liquidity Option liability at the exercise date, we will recognize expense for the difference. 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. The Liquidity Option may be exercised prior to February 2020 if a Trigger Event (as defined in the underlying agreements) occurs. The exercise period for a Trigger Event is 135 days following the notice of such event. Trigger Events include, among other scenarios, any Enterprise Tax Event (as defined in the underlying agreements), which includes certain events in which OTA would recognize a taxable gain on the Enterprise common units that it owns. The carrying value of the Liquidity Option Agreement, which is a component of “Other long-term liabilities” on our Consolidated Balance Sheet, was $333.9 million and $269.6 million at December 31, 2017 and 2016, respectively. 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 future 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 certain tax planning strategies we believe could be employed. 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 years ended December 31, 2017, 2016 and 2015 include $64.3 million, $24.5 million and $25.4 million, respectively, of aggregate non-cash expense attributable to accretion and changes in management estimates regarding inputs to the valuation model. The fair value of the Liquidity Option at December 31, 2017 reflects the estimated impact of the Tax Cuts and Jobs Act (the “TCJA”) enacted by the U.S. Congress in late December 2017. The TCJA makes broad and complex changes to the U.S. tax code that will affect the carrying value of the Liquidity Option Agreement, including, but not limited to, (i) reducing the federal corporate tax rate payable by OTA from 35% to 21%, (ii) creating a new limitation on deductible interest expense, (iii) bonus depreciation that will allow for full expensing of qualified properties for certain tax years, and (iv) changing rules related to uses and limitations of OTA’s net operating loss carryforwards created in tax years beginning after December 31, 2017. In connection with our initial analysis of the impact of the TCJA for the Liquidity Option, we have recorded an estimate resulting in the recognition of $21.2 million of non-cash expense, which is a component of the overall $64.3 million of non-cash expense we recognized for the Liquidity Option during the year ended December 31, 2017. In addition to the effects of recently enacted tax reforms, our valuation estimate for the Liquidity Option at December 31, 2017 is based on several inputs that are not readily observable in the market (i.e., Level 3 inputs) such as the following:  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 that OTA will be dissolved was assigned to each year in the 30-year forecast period;  Forecasted annual growth rates of Enterprise’s taxable earnings before interest, taxes, depreciation and amortization ranging from 2.1% to 7.2%;  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, 2017, we used ownership interests ranging from 1.8% to 2.5%;  OTA pays an aggregate federal and state income tax rate of 24% on its taxable income; and  A discount rate of 7.6% based on our weighted-average cost of capital at December 31, 2017. 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. At December 31, 2017, based on these scenarios, we expect that OTA would own approximately 89% of the 54,807,352 Enterprise common units it received in Step 1 when the option period begins in February 2020. If our valuation estimate at December 31, 2017 had assumed that OTA owned all of the Enterprise common units it received in Step 1 at the time of exercise (and all other inputs remained the same), the estimated fair value of the Liquidity Option liability would have increased by $40.2 million. Centennial Guarantees At December 31, 2017, Centennial’s debt obligations consisted of $50.0 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 $25.0 million payment to Centennial’s lenders in connection with the guarantee agreements (based on Centennial’s debt principal outstanding at December 31, 2017). We recognized a liability of $3.7 million for our share of the Centennial debt guaranty at December 31, 2017. 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, 2017, we have a recorded liability of $1.6 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, 2017
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 natural gas, NGLs and crude oil 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 in 2015 and 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 markets 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 independent and major integrated oil and gas companies and other pipelines and wholesalers. These concentrations of market areas may affect our overall credit risk in that these energy industry 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 $30 million. We also have business interruption protection; however, such claims must involve physical damage and have a combined loss value in excess of $30 million and the period of interruption must exceed 60 days. With respect to named windstorm claims, the maximum amount of insurance coverage available to us for any single event is $200 million, after applying the appropriate deductibles. A named windstorm is a hurricane, typhoon, tropical storm or cyclone as declared by the U.S. National Weather Service.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 2015 Decrease (increase) in: Accounts receivable – trade $ (1,076.2 ) $ (679.0 ) $ 1,279.3 Accounts receivable – related parties (0.7 ) 0.4 1.3 Inventories 194.6 (871.8 ) (72.7 ) Prepaid and other current assets 226.0 (49.3 ) (59.1 ) Other assets (111.0 ) (2.0 ) (5.8 ) Increase (decrease) in: Accounts payable – trade 66.6 (21.5 ) (52.9 ) Accounts payable – related parties 56.0 21.0 (34.8 ) Accrued product payables 952.3 1,193.3 (1,342.4 ) Accrued interest 17.3 (11.4 ) 16.5 Other current liabilities (291.4 ) 189.9 (67.1 ) Other liabilities (1.3 ) 49.5 14.4 Net effect of changes in operating accounts $ 32.2 $ (180.9 ) $ (323.3 ) Cash payments for interest, net of $192.1, $168.2 and $149.1 capitalized in 2017, 2016 and 2015, respectively $ 912.1 $ 947.9 $ 911.6 Cash payments for federal and state income taxes $ 20.9 $ 18.7 $ 17.5 We incurred liabilities for construction in progress that had not been paid at December 31, 2017, 2016 and 2015 of $373.0 million, $124.3 million and $472.8 million, respectively. Such amounts are not included under the caption “Capital expenditures” on our Statements of Consolidated Cash Flows. The following table presents our cash proceeds from asset sales for the periods indicated: For the Year Ended December 31, 2017 2016 2015 Sale of Offshore Business (see Note 10) $ -- $ -- $ 1,527.7 Cash proceeds from other asset sales 40.1 46.5 80.9 Total $ 40.1 $ 46.5 $ 1,608.6 The following table presents net gains (losses) attributable to asset sales for the periods indicated: For the Year Ended December 31, 2017 2016 2015 Sale of Offshore Business (see Note 10) $ -- $ -- $ (12.3 ) Net gains (losses) attributable to other asset sales 10.7 2.5 (3.3 ) Total $ 10.7 $ 2.5 $ (15.6 ) In July 2015, we purchased EFS Midstream for approximately $2.1 billion in cash, which was payable in two installments. The initial payment of $1.1 billion was paid in July 2015, with the second and final installment of $1.0 billion paid in July 2016. See Note 12 for information regarding this business combination. See Note 12 for information regarding non-cash consideration we issued in connection with Step 2 of the Oiltanking acquisition. See Note 14 for information regarding asset impairment and related charges as presented on our Statements of Consolidated Cash Flows.

Quarterly Financial Information

Quarterly Financial Information (Unaudited)	12 Months Ended
	Dec. 31, 2017
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, 2017: Revenues $ 7,320.4 $ 6,607.6 $ 6,886.9 $ 8,426.6 Operating income 1,031.6 938.7 879.2 1,079.4 Net income 771.0 666.0 621.3 797.3 Net income attributable to limited partners 760.7 653.7 610.9 774.0 Earnings per unit: Basic $ 0.36 $ 0.30 $ 0.28 $ 0.36 Diluted $ 0.36 $ 0.30 $ 0.28 $ 0.36 For the Year Ended December 31, 2016: Revenues $ 5,005.3 $ 5,617.8 $ 5,920.4 $ 6,478.8 Operating income 915.6 836.9 905.0 923.2 Net income 670.2 570.0 643.1 669.7 Net income attributable to limited partners 661.2 558.5 634.6 658.8 Earnings per unit: Basic $ 0.32 $ 0.27 $ 0.30 $ 0.31 Diluted $ 0.32 $ 0.27 $ 0.30 $ 0.31 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, 2017
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. There are no significant restrictions on the ability of EPO to receive funds from Enterprise Products Partners L.P. Enterprise Products Partners L.P. Condensed Consolidating Balance Sheet December 31, 2017 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 $ 65.2 $ 31.5 $ (26.4 ) $ 70.3 $ -- $ -- $ 70.3 Accounts receivable – trade, net 1,382.3 2,976.6 (0.5 ) 4,358.4 -- -- 4,358.4 Accounts receivable – related parties 110.3 1,182.1 (1,289.3 ) 3.1 -- (1.3 ) 1.8 Inventories 1,038.9 572.3 (1.4 ) 1,609.8 -- -- 1,609.8 Derivative assets 110.0 43.4 -- 153.4 -- -- 153.4 Prepaid and other current assets 136.3 189.0 (12.6 ) 312.7 -- -- 312.7 Total current assets 2,843.0 4,994.9 (1,330.2 ) 6,507.7 -- (1.3 ) 6,506.4 Property, plant and equipment, net 5,622.6 29,996.3 1.5 35,620.4 -- -- 35,620.4 Investments in unconsolidated affiliates 41,616.6 4,298.0 (43,255.2 ) 2,659.4 22,881.5 (22,881.5 ) 2,659.4 Intangible assets, net 675.5 3,028.6 (13.8 ) 3,690.3 -- -- 3,690.3 Goodwill 459.5 5,285.7 -- 5,745.2 -- -- 5,745.2 Other assets 296.4 110.0 (211.0 ) 195.4 1.0 -- 196.4 Total assets $ 51,513.6 $ 47,713.5 $ (44,808.7 ) $ 54,418.4 $ 22,882.5 $ (22,882.8 ) $ 54,418.1 LIABILITIES AND EQUITY Current liabilities: Current maturities of debt $ 2,854.6 $ 0.4 $ -- $ 2,855.0 $ -- $ -- $ 2,855.0 Accounts payable – trade 290.2 537.8 (26.4 ) 801.6 0.1 -- 801.7 Accounts payable – related parties 1,320.3 112.0 (1,305.0 ) 127.3 1.3 (1.3 ) 127.3 Accrued product payables 1,825.9 2,741.7 (1.3 ) 4,566.3 -- -- 4,566.3 Accrued interest 358.0 -- -- 358.0 -- -- 358.0 Derivative liabilities 115.2 53.0 -- 168.2 -- -- 168.2 Other current liabilities 108.9 320.1 (10.8 ) 418.2 -- 0.4 418.6 Total current liabilities 6,873.1 3,765.0 (1,343.5 ) 9,294.6 1.4 (0.9 ) 9,295.1 Long-term debt 21,699.0 14.7 -- 21,713.7 -- -- 21,713.7 Deferred tax liabilities 6.7 50.2 (0.5 ) 56.4 -- 2.1 58.5 Other long-term liabilities 60.4 396.5 (212.4 ) 244.5 333.9 -- 578.4 Commitments and contingencies Equity: Partners’ and other owners’ equity 22,874.4 43,412.0 (43,433.3 ) 22,853.1 22,547.2 (22,853.1 ) 22,547.2 Noncontrolling interests -- 75.1 181.0 256.1 -- (30.9 ) 225.2 Total equity 22,874.4 43,487.1 (43,252.3 ) 23,109.2 22,547.2 (22,884.0 ) 22,772.4 Total liabilities and equity $ 51,513.6 $ 47,713.5 $ (44,808.7 ) $ 54,418.4 $ 22,882.5 $ (22,882.8 ) $ 54,418.1 Enterprise Products Partners L.P. Condensed Consolidating Balance Sheet December 31, 2016 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 $ 366.2 $ 58.9 $ (7.5 ) $ 417.6 $ -- $ -- $ 417.6 Accounts receivable – trade, net 1,499.4 1,830.3 (0.2 ) 3,329.5 -- -- 3,329.5 Accounts receivable – related parties 131.5 961.4 (1,090.7 ) 2.2 -- (1.1 ) 1.1 Inventories 1,357.5 413.5 (0.5 ) 1,770.5 -- -- 1,770.5 Derivative assets 464.8 76.6 -- 541.4 -- -- 541.4 Prepaid and other current assets 290.7 191.1 (13.7 ) 468.1 -- -- 468.1 Total current assets 4,110.1 3,531.8 (1,112.6 ) 6,529.3 -- (1.1 ) 6,528.2 Property, plant and equipment, net 4,796.5 28,495.7 0.3 33,292.5 -- -- 33,292.5 Investments in unconsolidated affiliates 39,995.5 4,227.9 (41,546.1 ) 2,677.3 22,317.1 (22,317.1 ) 2,677.3 Intangible assets, net 700.2 3,178.2 (14.3 ) 3,864.1 -- -- 3,864.1 Goodwill 459.5 5,285.7 -- 5,745.2 -- -- 5,745.2 Other assets 222.6 41.0 (177.5 ) 86.1 0.6 -- 86.7 Total assets $ 50,284.4 $ 44,760.3 $ (42,850.2 ) $ 52,194.5 $ 22,317.7 $ (22,318.2 ) $ 52,194.0 LIABILITIES AND EQUITY Current liabilities: Current maturities of debt $ 2,576.7 $ 0.1 $ -- $ 2,576.8 $ -- $ -- $ 2,576.8 Accounts payable – trade 133.1 272.1 (7.5 ) 397.7 -- -- 397.7 Accounts payable – related parties 1,071.5 139.6 (1,106.0 ) 105.1 1.1 (1.1 ) 105.1 Accrued product payables 1,944.5 1,670.3 (1.1 ) 3,613.7 -- -- 3,613.7 Accrued interest 340.7 0.1 -- 340.8 -- -- 340.8 Derivative liabilities 590.3 147.4 -- 737.7 -- -- 737.7 Other current liabilities 173.5 316.5 (12.0 ) 478.0 -- 0.7 478.7 Total current liabilities 6,830.3 2,546.1 (1,126.6 ) 8,249.8 1.1 (0.4 ) 8,250.5 Long-term debt 21,105.7 15.2 -- 21,120.9 -- -- 21,120.9 Deferred tax liabilities 5.0 45.1 (1.1 ) 49.0 -- 3.7 52.7 Other long-term liabilities 13.5 400.6 (179.8 ) 234.3 269.6 -- 503.9 Commitments and contingencies Equity: Partners’ and other owners’ equity 22,329.9 41,675.3 (41,713.4 ) 22,291.8 22,047.0 (22,291.8 ) 22,047.0 Noncontrolling interests -- 78.0 170.7 248.7 -- (29.7 ) 219.0 Total equity 22,329.9 41,753.3 (41,542.7 ) 22,540.5 22,047.0 (22,321.5 ) 22,266.0 Total liabilities and equity $ 50,284.4 $ 44,760.3 $ (42,850.2 ) $ 52,194.5 $ 22,317.7 $ (22,318.2 ) $ 52,194.0 Enterprise Products Partners L.P. Condensed Consolidating Statement of Operations For the Year Ended December 31, 2017 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 $ 40,696.8 $ 18,451.2 $ (29,906.5 ) $ 29,241.5 $ -- $ -- $ 29,241.5 Costs and expenses: Operating costs and expenses 39,809.6 15,654.9 (29,907.0 ) 25,557.5 -- -- 25,557.5 General and administrative costs 31.4 148.0 (0.1 ) 179.3 1.8 -- 181.1 Total costs and expenses 39,841.0 15,802.9 (29,907.1 ) 25,736.8 1.8 -- 25,738.6 Equity in income of unconsolidated affiliates 2,990.1 566.8 (3,130.9 ) 426.0 2,865.4 (2,865.4 ) 426.0 Operating income 3,845.9 3,215.1 (3,130.3 ) 3,930.7 2,863.6 (2,865.4 ) 3,928.9 Other income (expense): Interest expense (982.5 ) (11.8 ) 9.7 (984.6 ) -- -- (984.6 ) Other, net 9.2 1.8 (9.7 ) 1.3 (64.3 ) -- (63.0 ) Total other expense, net (973.3 ) (10.0 ) -- (983.3 ) (64.3 ) -- (1,047.6 ) Income before income taxes 2,872.6 3,205.1 (3,130.3 ) 2,947.4 2,799.3 (2,865.4 ) 2,881.3 Provision for income taxes (12.0 ) (13.7 ) -- (25.7 ) -- -- (25.7 ) Net income 2,860.6 3,191.4 (3,130.3 ) 2,921.7 2,799.3 (2,865.4 ) 2,855.6 Net loss (income) attributable to noncontrolling interests -- (6.5 ) (55.1 ) (61.6 ) -- 5.3 (56.3 ) Net income attributable to entity $ 2,860.6 $ 3,184.9 $ (3,185.4 ) $ 2,860.1 $ 2,799.3 $ (2,860.1 ) $ 2,799.3 Enterprise Products Partners L.P. Condensed Consolidating Statement of Operations For the Year Ended December 31, 2016 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 $ 28,958.7 $ 15,296.8 $ (21,233.2 ) $ 23,022.3 $ -- $ -- $ 23,022.3 Costs and expenses: Operating costs and expenses 28,108.2 12,768.9 (21,233.6 ) 19,643.5 -- -- 19,643.5 General and administrative costs 22.5 135.3 -- 157.8 2.3 -- 160.1 Total costs and expenses 28,130.7 12,904.2 (21,233.6 ) 19,801.3 2.3 -- 19,803.6 Equity in income of unconsolidated affiliates 2,686.1 521.7 (2,845.8 ) 362.0 2,539.9 (2,539.9 ) 362.0 Operating income 3,514.1 2,914.3 (2,845.4 ) 3,583.0 2,537.6 (2,539.9 ) 3,580.7 Other income (expense): Interest expense (973.1 ) (17.3 ) 7.8 (982.6 ) -- -- (982.6 ) Other, net 8.3 2.3 (7.8 ) 2.8 (24.5 ) -- (21.7 ) Total other expense, net (964.8 ) (15.0 ) -- (979.8 ) (24.5 ) -- (1,004.3 ) Income before income taxes 2,549.3 2,899.3 (2,845.4 ) 2,603.2 2,513.1 (2,539.9 ) 2,576.4 Provision for income taxes (13.1 ) (8.2 ) -- (21.3 ) -- (2.1 ) (23.4 ) Net income 2,536.2 2,891.1 (2,845.4 ) 2,581.9 2,513.1 (2,542.0 ) 2,553.0 Net loss (income) attributable to noncontrolling interests -- (7.4 ) (37.8 ) (45.2 ) -- 5.3 (39.9 ) Net income attributable to entity $ 2,536.2 $ 2,883.7 $ (2,883.2 ) $ 2,536.7 $ 2,513.1 $ (2,536.7 ) $ 2,513.1 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 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 Comprehensive Income For the Year Ended December 31, 2017 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 $ 2,951.7 $ 3,208.6 $ (3,130.2 ) $ 3,030.1 $ 2,907.6 $ (2,973.8 ) $ 2,963.9 Comprehensive loss (income) attributable to noncontrolling interests -- (6.5 ) (55.1 ) (61.6 ) -- 5.3 (56.3 ) Comprehensive income attributable to entity $ 2,951.7 $ 3,202.1 $ (3,185.3 ) $ 2,968.5 $ 2,907.6 $ (2,968.5 ) $ 2,907.6 Enterprise Products Partners L.P. Condensed Consolidating Statement of Comprehensive Income For the Year Ended December 31, 2016 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 $ 2,544.3 $ 2,822.1 $ (2,845.3 ) $ 2,521.1 $ 2,452.2 $ (2,481.1 ) $ 2,492.2 Comprehensive loss (income) attributable to noncontrolling interests -- (7.4 ) (37.8 ) (45.2 ) -- 5.3 (39.9 ) Comprehensive income attributable to entity $ 2,544.3 $ 2,814.7 $ (2,883.1 ) $ 2,475.9 $ 2,452.2 $ (2,475.8 ) $ 2,452.3 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 Cash Flows For the Year Ended December 31, 2017 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 $ 2,860.6 $ 3,191.4 $ (3,130.3 ) $ 2,921.7 $ 2,799.3 $ (2,865.4 ) $ 2,855.6 Reconciliation of net income to net cash flows provided by operating activities: Depreciation, amortization and accretion 216.6 1,427.8 (0.4 ) 1,644.0 -- -- 1,644.0 Equity in income of unconsolidated affiliates (2,990.1 ) (566.8 ) 3,130.9 (426.0 ) (2,865.4 ) 2,865.4 (426.0 ) Distributions received on earnings from unconsolidated affiliates 1,162.8 272.7 (1,001.8 ) 433.7 3,574.6 (3,574.6 ) 433.7 Net effect of changes in operating accounts and other operating activities 2,812.2 (2,726.3 ) (19.1 ) 66.8 93.2 (1.0 ) 159.0 Net cash flows provided by operating activities 4,062.1 1,598.8 (1,020.7 ) 4,640.2 3,601.7 (3,575.6 ) 4,666.3 Investing activities: Capital expenditures, net of contributions in aid of construction costs (846.8 ) (2,255.0 ) -- (3,101.8 ) -- -- (3,101.8 ) Cash used for business combinations, net of cash received (7.3 ) (191.4 ) -- (198.7 ) -- -- (198.7 ) Proceeds from asset sales 17.0 23.1 -- 40.1 -- -- 40.1 Other investing activities (1,908.5 ) (28.0 ) 1,910.8 (25.7 ) (1,060.5 ) 1,060.5 (25.7 ) Cash used in investing activities (2,745.6 ) (2,451.3 ) 1,910.8 (3,286.1 ) (1,060.5 ) 1,060.5 (3,286.1 ) Financing activities: Borrowings under debt agreements 69,349.3 -- (34.0 ) 69,315.3 -- -- 69,315.3 Repayments of debt (68,459.5 ) (0.1 ) -- (68,459.6 ) -- -- (68,459.6 ) Cash distributions paid to partners (3,574.6 ) (1,065.3 ) 1,065.3 (3,574.6 ) (3,569.9 ) 3,574.6 (3,569.9 ) Cash payments made in connection with DERs -- -- -- -- (15.1 ) -- (15.1 ) Cash distributions paid to noncontrolling interests -- (9.6 ) (40.6 ) (50.2 ) -- 1.0 (49.2 ) Cash contributions from noncontrolling interests -- 0.1 0.3 0.4 -- -- 0.4 Net cash proceeds from issuance of common units -- -- -- -- 1,073.4 -- 1,073.4 Cash contributions from owners 1,060.5 1,900.0 (1,900.0 ) 1,060.5 -- (1,060.5 ) -- Other financing activities 6.8 -- -- 6.8 (29.6 ) -- (22.8 ) Cash provided by (used in) financing activities (1,617.5 ) 825.1 (909.0 ) (1,701.4 ) (2,541.2 ) 2,515.1 (1,727.5 ) Net change in cash, cash equivalents and restricted cash (301.0 ) (27.4 ) (18.9 ) (347.3 ) -- -- (347.3 ) Cash, cash equivalents and restricted cash, January 1 366.2 58.9 (7.5 ) 417.6 -- -- 417.6 Cash, cash equivalents and restricted cash, December 31 $ 65.2 $ 31.5 $ (26.4 ) $ 70.3 $ -- $ -- $ 70.3 Enterprise Products Partners L.P. Condensed Consolidating Statement of Cash Flows For the Year Ended December 31, 2016 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 $ 2,536.2 $ 2,891.1 $ (2,845.4 ) $ 2,581.9 $ 2,513.1 $ (2,542.0 ) $ 2,553.0 Reconciliation of net income to net cash flows provided by operating activities: Depreciation, amortization and accretion 185.4 1,367.0 (0.4 ) 1,552.0 -- -- 1,552.0 Equity in income of unconsolidated affiliates (2,686.1 ) (521.7 ) 2,845.8 (362.0 ) (2,539.9 ) 2,539.9 (362.0 ) Distributions received on earnings from unconsolidated affiliates 1,127.3 265.9 (1,012.7 ) 380.5 3,331.2 (3,331.2 ) 380.5 Net effect of changes in operating accounts and other operating activities 2,448.6 (2,568.5 ) 43.1 (76.8 ) 18.9 1.2 (56.7 ) Net cash flows provided by operating activities 3,611.4 1,433.8 (969.6 ) 4,075.6 3,323.3 (3,332.1 ) 4,066.8 Investing activities: Capital expenditures, net of contributions in aid of construction costs (1,327.4 ) (1,656.7 ) -- (2,984.1 ) -- -- (2,984.1 ) Cash used for business combinations, net of cash received -- (1,000.0 ) -- (1,000.0 ) -- -- (1,000.0 ) Proceeds from asset sales 28.8 17.7 -- 46.5 -- -- 46.5 Other investing activities (2,301.9 ) (63.2 ) 2,296.9 (68.2 ) (2,530.9 ) 2,530.9 (68.2 ) Cash used in investing activities (3,600.5 ) (2,702.2 ) 2,296.9 (4,005.8 ) (2,530.9 ) 2,530.9 (4,005.8 ) Financing activities: Borrowings under debt agreements 62,813.9 41.8 (41.8 ) 62,813.9 -- -- 62,813.9 Repayments of debt (61,672.5 ) (0.1 ) -- (61,672.6 ) -- -- (61,672.6 ) Cash distributions paid to partners (3,331.2 ) (1,089.6 ) 1,089.6 (3,331.2 ) (3,300.5 ) 3,331.2 (3,300.5 ) Cash payments made in connection with DERs -- -- -- -- (11.7 ) -- (11.7 ) Cash distributions paid to noncontrolling interests -- (8.5 ) (39.8 ) (48.3 ) -- 0.9 (47.4 ) Cash contributions from noncontrolling interests -- 20.4 -- 20.4 -- -- 20.4 Net cash proceeds from issuance of common units -- -- -- -- 2,542.8 -- 2,542.8 Cash contributions from owners 2,530.9 2,292.2 (2,292.2 ) 2,530.9 -- (2,530.9 ) -- Other financing activities (0.2 ) -- -- (0.2 ) (23.0 ) -- (23.2 ) Cash provided by (used in) financing activities 340.9 1,256.2 (1,284.2 ) 312.9 (792.4 ) 801.2 321.7 Net change in cash, cash equivalents and restricted cash 351.8 (12.2 ) 43.1 382.7 -- -- 382.7 Cash, cash equivalents and restricted cash, January 1 14.4 71.1 (50.6 ) 34.9 -- -- 34.9 Cash, cash equivalents and restricted cash, December 31 $ 366.2 $ 58.9 $ (7.5 ) $ 417.6 $ -- $ -- $ 417.6 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 on earnings 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 1,531.3 77.3 -- 1,608.6 -- -- 1,608.6 Other investing activities (1,499.0 ) (1,246.7 ) 2,579.3 (166.4 ) (1,179.8 ) 1,179.8 (166.4 ) Cash used in investing activities (2,217.6 ) (3,787.6 ) 2,579.3 (3,425.9 ) (1,179.8 ) 1,179.8 (3,425.9 ) 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, cash equivalents and restricted cash (4.3 ) 0.7 (35.9 ) (39.5 ) -- -- (39.5 ) Cash, cash equivalents and restricted cash, January 1 18.7 70.4 (14.7 ) 74.4 -- -- 74.4 Cash, cash equivalents and restricted cash, December 31 $ 14.4 $ 71.1 $ (50.6 ) $ 34.9 $ -- $ -- $ 34.9

Subsequent Event

Subsequent Event	12 Months Ended
	Dec. 31, 2017
Subsequent Event [Abstract]
Subsequent Event	Issuance of $2.0 Billion of Senior Notes and $700 Million of Junior Subordinated Notes in February 2018 In February 2018, EPO issued $2.7 billion aggregate principal amount of notes comprised of (i) $750 million principal amount of senior notes due February 15, 2021 (“Senior Notes TT”), (ii) $1.25 billion principal amount of senior notes due February 15, 2048 (“Senior Notes UU”) and (iii) $700 million principal amount of junior subordinated notes due February 15, 2078 (“Junior Subordinated Notes F”). We issued these notes using our 2016 Shelf (see Note 9). Net proceeds from these offerings were used by EPO for the temporary repayment of amounts outstanding under its commercial paper program, general company purposes, and the expected redemption of all $682.7 million outstanding aggregate principal amount of its 7.034% Junior Subordinated Notes B (the “7.034% Notes”). Senior Notes TT were issued at 99.946% of their principal amount and have a fixed-rate interest rate of 2.80% per year. Senior Notes UU were issued at 99.865% of their principal amount and have a fixed-rate interest rate of 4.25% per year. Enterprise Products Partners L.P. has guaranteed the senior notes through an unconditional guarantee on an unsecured and unsubordinated basis. The Junior Subordinated Notes F are redeemable at EPO’s option, in whole or in part, on one or more occasions, on or after February 15, 2028 at 100% of their principal amount, plus any accrued and unpaid interest thereon, and bear interest at a fixed rate of 5.375% per year through February 14, 2028. Beginning February 15, 2028, the Junior Subordinated Notes F will bear interest at a floating rate based on a three-month LIBOR rate plus 2.57%, reset quarterly. Enterprise Products Partners L.P. has guaranteed the Junior Subordinated Notes F through an unconditional guarantee on an unsecured and subordinated basis. The redemption of the 7.034% Notes and the issuance of the 5.375% Junior Subordinated Notes F will result in annual interest savings to EPO of approximately $11.3 million. On February 1, 2018, EPO notified its trustee and paying agent to redeem all of the $682.7 million outstanding aggregate principal amount of its 7.034% Notes. EPO anticipates that the 7.034% Notes will be redeemed on or about March 5, 2018, in accordance with the terms of the 7.034% Notes, at a price equal to 100% of the principal amount of the notes being redeemed, plus all accrued and unpaid interest thereon to, but not including, the redemption date.

Summary of Significant Accoun30

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 2015 Balance at beginning of period $ 11.3 $ 12.1 $ 13.9 Charged to costs and expenses 2.7 2.3 0.8 Deductions (1.9 ) (3.1 ) (2.6 ) Balance at end of period $ 12.1 $ 11.3 $ 12.1 See “Credit Risk” in Note 18 for additional information.
Cash, Cash Equivalents and Restricted Cash	Cash, Cash Equivalents and Restricted Cash 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. 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 margin requirements change. In November 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash, which standardizes the presentation of transfers to and from restricted cash within the cash flow statement. As a result, the cash flow statement will present changes in total cash amounts, regardless of whether the cash balances are restricted or unrestricted. We adopted this guidance in the fourth quarter of 2017 and applied this ASU retrospectively to the periods presented in our Statements of Consolidated Cash Flows. As a result, the decrease in restricted cash of $338.6 million and $15.9 million was excluded from net cash used in investing activities for the years ended December 31, 2016 and 2015, respectively. The following table provides a reconciliation of cash and cash equivalents, and restricted cash reported within the Consolidated Balance Sheets that sum to the total of the amounts shown in the Statements of Consolidated Cash Flows. December 31, 2017 2016 Cash and cash equivalents $ 5.1 $ 63.1 Restricted cash 65.2 354.5 Total cash, cash equivalents and restricted cash shown in the Statements of Consolidated Cash Flows $ 70.3 $ 417.6 The balance of restricted cash at December 31, 2017 consisted of initial margin requirements of $33.4 million and variation margin requirements of $31.8 million. The initial margin requirements will be returned to us as the related derivative instruments are settled. See Note 14 for information regarding our derivative instruments and hedging activities.
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, 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, 2017, 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, 2017 2016 2015 Balance at beginning of period $ 11.9 $ 13.0 $ 15.6 Charged to costs and expenses 12.1 7.0 6.4 Acquisition-related additions and other 1.7 0.5 1.1 Deductions (14.1 ) (8.6 ) (10.1 ) Balance at end of period $ 11.6 $ 11.9 $ 13.0 At December 31, 2017 and 2016, $5.6 million 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, 2017 and 2016. 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 non-cash impairment 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 in their fair value estimation process. Based on our most recent goodwill impairment test at December 31, 2017, 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 non-cash 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 to determine whether there are events or changes in circumstances that indicate 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 non-cash impairment charge to equity earnings to adjust the carrying value of the investment to its estimated fair value. There were not any non-cash impairment charges related to our equity method investments during the years ended 2017, 2016 and 2015. See Note 6 for information regarding our equity method investments.
Inventories	Inventories Inventories primarily consist of NGLs, petrochemicals, refined products, crude oil and natural gas volumes that are valued at the lower of cost or net realizable value. 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 on a straight-line basis 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	Recent Accounting Developments Revenue Recognition . Revenues from Contracts with Customers 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. Our implementation activities related to ASC 606 are nearly complete. For the vast majority of our businesses, we will not have any material differences in the amount or timing of revenues once we adopt ASC 606. However, based on guidance in ASC 606 applicable to non-cash consideration, we will start recognizing revenue in connection with equity NGL volumes we receive as consideration for providing processing services under percent of liquids and similar arrangements. The value assigned to this non-cash consideration and related inventory will be based on the fair value of NGLs we are entitled to at the time the processing services are performed. An additional revenue stream, along with the related cost of sales, would be recognized in connection with the ultimate sale of the NGL products derived from the NGLs acquired as a fee for service. Under current accounting practice, we only recognize revenue from the downstream sale of NGL products and do not record service revenue. Based on our estimates, if the changes required by ASC 606 had been adopted at January 1, 2017, our total consolidated revenues for the year ended December 31, 2017 would have increased by approximately 1%. Given the rapid turnover of our inventories of NGL products each month, we do not expect a significant change in our gross operating margin from natural gas processing and related NGL marketing activities as a result of the changes required by ASC 606. The additional revenue stream recognized in connection with receipt of the equity NGLs will be offset by an equal cost of sales amount when the associated NGL products are sold, which is expected to typically be completed in the same accounting period. As a result of adopting the new standard, there will be significant changes to our disclosures based on the additional requirements prescribed by ASC 606. These new disclosures include information regarding the significant judgments used in evaluating when and how revenue is (or will be) recognized and data related to contract assets and liabilities. Additionally, we have revised our business processes, systems and controls to ensure the accuracy and timeliness of the recognition and disclosure requirements under the new revenue guidance. Leases Leases The new standard introduces two lease accounting models, which result in a lease being classified as either a “finance” or “operating” lease on the basis of whether the lessee effectively obtains control of the underlying asset during the lease term. A lease would be classified as a finance lease if it meets one of five classification criteria, four of which are generally consistent with current lease accounting guidance. By default, a lease that does not meet the criteria to be classified as a finance lease will be deemed an operating lease. Regardless of classification, the initial measurement of both lease types will result in the balance sheet recognition of a ROU asset representing a company’s right to use the underlying asset for a specified period of time and a corresponding lease liability. The lease liability will be recognized at the present value of the future lease payments, and the ROU asset will equal the lease liability adjusted for any prepaid rent, lease incentives provided by the lessor, and any indirect costs. The subsequent measurement of each type of lease varies. Leases classified as a finance lease will be accounted for using the effective interest method. Under this approach, a lessee will amortize the ROU asset (generally on a straight-line basis in a manner similar to depreciation) and the discount on the lease liability (as a component of interest expense). Leases classified as an operating lease will result in the recognition of a single lease expense amount that is recorded on a straight-line basis (or another systematic basis, if more appropriate). We have started the process of reviewing our lease agreements in light of the new guidance. Although we are in the early stages of our ASC 842 implementation project, we anticipate that this new lease guidance will result in changes to the way our operating leases are recorded, presented and disclosed in our consolidated financial statements. Derivative instruments Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities which amends and simplifies existing guidance in order to allow companies to more accurately present the economic effects of risk management activities in the financial statements. As a result of the new guidance, we will no longer be required to separately measure and disclose the effect of periodic hedge ineffectiveness related to cash flow hedges. We early adopted this new guidance on January 1, 2018. The impact of the new guidance on our consolidated financial statements and disclosures is not expected to be material

Summary of Significant Accoun31

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 2015 Balance at beginning of period $ 11.3 $ 12.1 $ 13.9 Charged to costs and expenses 2.7 2.3 0.8 Deductions (1.9 ) (3.1 ) (2.6 ) Balance at end of period $ 12.1 $ 11.3 $ 12.1
Cash, Cash Equivalents and Restricted Cash	The following table provides a reconciliation of cash and cash equivalents, and restricted cash reported within the Consolidated Balance Sheets that sum to the total of the amounts shown in the Statements of Consolidated Cash Flows. December 31, 2017 2016 Cash and cash equivalents $ 5.1 $ 63.1 Restricted cash 65.2 354.5 Total cash, cash equivalents and restricted cash shown in the Statements of Consolidated Cash Flows $ 70.3 $ 417.6
Environmental Reserves Activity	The following table presents the activity of our environmental reserves for the periods indicated: For the Year Ended December 31, 2017 2016 2015 Balance at beginning of period $ 11.9 $ 13.0 $ 15.6 Charged to costs and expenses 12.1 7.0 6.4 Acquisition-related additions and other 1.7 0.5 1.1 Deductions (14.1 ) (8.6 ) (10.1 ) Balance at end of period $ 11.6 $ 11.9 $ 13.0

Revenue Recognition (Tables)

Revenue Recognition (Tables)	12 Months Ended
	Dec. 31, 2017
Revenue Recognition [Abstract]
Consolidated Revenues	The following table information regarding our consolidated revenues by business segment for the periods indicated: For the Year Ended December 31, 2017 2016 2015 NGL Pipelines & Services: Sales of NGLs and related products $ 10,521.3 $ 8,380.5 $ 8,044.8 Midstream services 1,946.7 1,862.0 1,743.2 Total 12,468.0 10,242.5 9,788.0 Crude Oil Pipelines & Services: Sales of crude oil 7,365.2 5,802.5 9,732.9 Midstream services 791.6 712.5 573.0 Total 8,156.8 6,515.0 10,305.9 Natural Gas Pipelines & Services: Sales of natural gas 2,238.5 1,591.9 1,722.6 Midstream services 907.1 951.1 1,020.7 Total 3,145.6 2,543.0 2,743.3 Petrochemical & Refined Products Services: Sales of petrochemicals and refined products 4,696.3 2,921.9 3,333.5 Midstream services 774.8 799.9 778.4 Total 5,471.1 3,721.8 4,111.9 Offshore Pipelines & Services: Sales of crude oil -- -- 3.2 Midstream services -- -- 75.6 Total -- -- 78.8 Total consolidated revenues $ 29,241.5 $ 23,022.3 $ 27,027.9

Inventories (Tables)

Inventories (Tables)	12 Months Ended
	Dec. 31, 2017
Inventories [Abstract]
Inventory Amounts by Product Type	Our inventory amounts by product type were as follows at the dates indicated: December 31, 2017 2016 NGLs $ 917.4 $ 1,156.1 Petrochemicals and refined products 161.5 220.7 Crude oil 516.3 360.0 Natural gas 14.6 33.7 Total $ 1,609.8 $ 1,770.5
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 net realizable value adjustments for the periods indicated: For the Year Ended December 31, 2017 2016 2015 Cost of sales (1) $ 21,487.0 $ 15,710.9 $ 19,612.9 Lower of cost or net realizable value adjustments within cost of sales 9.1 11.5 19.8 (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.

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2017
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 2017 2016 Plants, pipelines and facilities (1) 3-45 (5) $ 37,132.2 $ 35,124.6 Underground and other storage facilities (2) 5-40 (6) 3,460.9 3,326.9 Transportation equipment (3) 3-10 177.1 165.8 Marine vessels (4) 15-30 803.8 800.7 Land 273.1 264.6 Construction in progress 4,698.1 3,320.7 Total 46,545.2 43,003.3 Less accumulated depreciation 10,924.8 9,710.8 Property, plant and equipment, net $ 35,620.4 $ 33,292.5 (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) Transportation equipment includes tractor-trailer tank trucks and other vehicles and similar assets used in our operations. (4) Marine vessels include tow boats, barges and related equipment used in our marine transportation business. (5) 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. (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.
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, 2017 2016 2015 Depreciation expense (1) $ 1,296.1 $ 1,215.7 $ 1,161.6 Capitalized interest (2) 192.1 168.2 149.1 (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, 2017 2016 2015 ARO liability beginning balance $ 85.4 $ 58.5 $ 98.3 Liabilities incurred 4.7 4.2 2.7 Liabilities settled (2.2 ) (5.7 ) (6.3 ) Revisions in estimated cash flows (6.7 ) 24.6 49.7 Accretion expense 5.5 3.8 5.2 AROs related to Offshore Business sold in July 2015 -- -- (91.1 ) ARO liability ending balance $ 86.7 $ 85.4 $ 58.5
Forecasted Accretion Expense Associated with AROs	The following table presents our forecast of accretion expense for the periods indicated: 2018 2019 2020 2021 2022 $ 5.8 $ 6.2 $ 6.5 $ 6.9 $ 7.3

Investments in Unconsolidated35

Investments in Unconsolidated Affiliates (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 December 31, 2017 2016 NGL Pipelines & Services: Venice Energy Service Company, L.L.C. (“VESCO”) 13.1% $ 25.7 $ 24.8 K/D/S Promix, L.L.C. (“Promix”) 50% 30.9 33.7 Baton Rouge Fractionators LLC (“BRF”) 32.2% 17.0 17.3 Skelly-Belvieu Pipeline Company, L.L.C. (“Skelly-Belvieu”) 50% 37.0 38.9 Texas Express Pipeline LLC (“Texas Express”) 35% 314.4 331.9 Texas Express Gathering LLC (“TEG”) 45% 35.9 35.8 Front Range Pipeline LLC (“Front Range”) 33.3% 165.7 165.4 Delaware Basin Gas Processing LLC (“Delaware Processing”) 50% 107.3 102.6 Crude Oil Pipelines & Services: Seaway Crude Pipeline Company LLC (“Seaway”) 50% 1,378.9 1,393.8 Eagle Ford Pipeline LLC (“Eagle Ford Crude Oil Pipeline”) 50% 385.2 377.9 Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Corpus Christi”) 50% 75.1 52.9 Natural Gas Pipelines & Services: White River Hub, LLC (“White River Hub”) 50% 20.8 21.7 Petrochemical & Refined Products Services: Centennial Pipeline LLC (“Centennial”) 50% 60.8 62.3 Other Various 4.7 18.3 Total investments in unconsolidated affiliates $ 2,659.4 $ 2,677.3 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, 2017 2016 2015 NGL Pipelines & Services $ 73.4 $ 61.4 $ 57.5 Crude Oil Pipelines & Services 358.4 311.9 281.4 Natural Gas Pipelines & Services 3.8 3.8 3.8 Petrochemical & Refined Products Services (1) (9.6 ) (15.1 ) (15.7 ) Offshore Pipelines & Services (2) -- -- 46.6 Total $ 426.0 $ 362.0 $ 373.6 (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 market and income approaches, indicate that the fair value of this investment remains in excess of its carrying value. (2) Our investments in unconsolidated affiliates classified within the Offshore Pipelines & Services segment were sold in July 2015 (see Note 10). The following table presents our unamortized excess cost amounts by business segment at the dates indicated: December 31, 2017 2016 NGL Pipelines & Services $ 22.9 $ 24.1 Crude Oil Pipelines & Services 18.2 19.0 Petrochemical & Refined Products Services 1.8 2.1 Total $ 42.9 $ 45.2 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, 2017 2016 Balance Sheet Data: Current assets $ 288.8 $ 199.5 Property, plant and equipment, net 5,509.7 5,644.4 Other assets 71.2 61.5 Total assets $ 5,869.7 $ 5,905.4 Current liabilities $ 233.5 $ 208.5 Other liabilities 84.8 112.3 Combined equity 5,551.4 5,584.6 Total liabilities and combined equity $ 5,869.7 $ 5,905.4 For the Year Ended December 31, 2017 2016 2015 Income Statement Data: Revenues $ 1,509.0 $ 1,342.0 $ 1,426.6 Operating income 925.9 786.7 825.8 Net income 929.5 781.7 814.1

Intangible Assets and Goodwill

Intangible Assets and Goodwill (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 December 31, 2016 Gross Value Accumulated Amortization Carrying Value Gross Value Accumulated Amortization Carrying Value NGL Pipelines & Services: Customer relationship intangibles $ 447.4 $ (187.5 ) $ 259.9 $ 447.4 $ (172.7 ) $ 274.7 Contract-based intangibles 280.8 (218.4 ) 62.4 279.9 (204.4 ) 75.5 Segment total 728.2 (405.9 ) 322.3 727.3 (377.1 ) 350.2 Crude Oil Pipelines & Services: Customer relationship intangibles 2,203.5 (127.0 ) 2,076.5 2,204.4 (84.5 ) 2,119.9 Contract-based intangibles 281.0 (171.0 ) 110.0 281.0 (121.9 ) 159.1 Segment total 2,484.5 (298.0 ) 2,186.5 2,485.4 (206.4 ) 2,279.0 Natural Gas Pipelines & Services: Customer relationship intangibles 1,350.3 (417.1 ) 933.2 1,350.3 (390.0 ) 960.3 Contract-based intangibles 464.7 (379.5 ) 85.2 464.7 (370.5 ) 94.2 Segment total 1,815.0 (796.6 ) 1,018.4 1,815.0 (760.5 ) 1,054.5 Petrochemical & Refined Products Services: Customer relationship intangibles 181.4 (45.9 ) 135.5 185.5 (43.9 ) 141.6 Contract-based intangibles 46.0 (18.4 ) 27.6 54.0 (15.2 ) 38.8 Segment total 227.4 (64.3 ) 163.1 239.5 (59.1 ) 180.4 Total intangible assets $ 5,255.1 $ (1,564.8 ) $ 3,690.3 $ 5,267.2 $ (1,403.1 ) $ 3,864.1
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, 2017 2016 2015 NGL Pipelines & Services $ 28.9 $ 30.6 $ 33.6 Crude Oil Pipelines & Services 92.5 98.4 87.1 Natural Gas Pipelines & Services 36.2 33.2 40.0 Petrochemical & Refined Products Services 9.3 9.1 8.9 Offshore Pipelines & Services -- -- 4.5 Total $ 166.9 $ 171.3 $ 174.1
Forecasted Amortization Expense	The following table presents our forecast of amortization expense associated with existing intangible assets for the years indicated: 2018 2019 2020 2021 2022 $ 174.5 $ 165.8 $ 150.7 $ 145.6 $ 141.6
Significant Acquired Intangible Assets	At December 31, 2017, the carrying value of our portfolio of customer relationship intangible assets was $3.4 billion, the principal components of which are as follows: Weighted Average Remaining Amortization Period December 31, 2017 Gross Value Accumulated Amortization Carrying Value Basin-specific customer relationships: EFS Midstream (1) 24.4 years $ 1,409.8 $ (88.8 ) $ 1,321.0 State Line and Fairplay (2) 29.2 years 895.0 (164.7 ) 730.3 San Juan Gathering (3) 21.8 years 331.3 (218.0 ) 113.3 Encinal (4) 9.0 years 132.9 (98.4 ) 34.5 General customer relationships: Oiltanking (5) 26.0 years 1,192.5 (57.1 ) 1,135.4 (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 formation in Louisiana and eastern Texas. The Fairplay system serves producers in the Cotton Valley formation 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 January 1, 2015 $ 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 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 Balance at December 31, 2016 2,651.7 1,841.0 296.3 956.2 -- 5,745.2 Balance at December 31, 2017 $ 2,651.7 $ 1,841.0 $ 296.3 $ 956.2 $ -- $ 5,745.2

Debt Obligations (Tables)

Debt Obligations (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 EPO senior debt obligations: Commercial Paper Notes, variable-rates $ 1,755.7 $ 1,777.2 Senior Notes L, 6.30% fixed-rate, due September 2017 -- 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 750.0 750.0 364-Day Revolving Credit Agreement, variable-rate, due September 2018 -- -- 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 Senior Notes RR, 2.85% fixed-rate, due April 2021 575.0 575.0 Senior Notes CC, 4.05% fixed-rate, due February 2022 650.0 650.0 Multi-Year Revolving Credit Facility, variable-rate, due September 2022 -- -- 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 875.0 875.0 Senior Notes SS, 3.95% fixed-rate, due February 2027 575.0 575.0 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 975.0 975.0 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 21,605.7 22,427.2 EPO Junior Subordinated Notes A, fixed/variable-rate, due August 2066 521.1 521.1 EPO Junior Subordinated Notes C, fixed/variable-rate, due June 2067 256.4 256.4 EPO Junior Subordinated Notes B, fixed/variable-rate, due January 2068 682.7 682.7 EPO Junior Subordinated Notes D, fixed/variable-rate, due August 2077 700.0 -- EPO Junior Subordinated Notes E, fixed/variable-rate, due August 2077 1,000.0 -- TEPPCO Junior Subordinated Notes, fixed/variable-rate, due June 2067 14.2 14.2 Total principal amount of senior and junior debt obligations 24,780.1 23,901.6 Other, non-principal amounts (211.4 ) (203.9 ) Less current maturities of debt (2,855.0 ) (2,576.8 ) Total long-term debt $ $ 21,713.7 $ $ 21,120.9 (1) Variable rate is reset quarterly and based on 3-month LIBOR plus 3.708%. (2) Fixed rate of 7.000% through May 31, 2017; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 2.778%. (3) Fixed rate of 7.034% through January 14, 2018; thereafter, the rate will be the greater of 7.034% or a variable rate reset quarterly and based on 3-month LIBOR plus 2.680%. These notes are expected to be redeemed in March 2018 (see Note 22). (4) Fixed rate of 4.875% through August 15, 2022; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 2.986%. (5) Fixed rate of 5.250% through August 15, 2027; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 3.033%.
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, 2017: Range of Interest Rates Paid Weighted-Average Interest Rate Paid Commercial Paper Notes 0.90% to 1.80% 1.34% Multi-Year Revolving Credit Facility 2.23% to 2.23% 2.23% EPO Junior Subordinated Notes A 4.59% to 5.08% 4.89% EPO Junior Subordinated Notes C 3.98% to 4.26% 4.07%
Consolidated Debt Maturities	The following table presents contractually scheduled maturities of our consolidated debt obligations outstanding at December 31, 2017 for the next five years, and in total thereafter: Scheduled Maturities of Debt Total 2018 2019 2020 2021 2022 Thereafter Commercial Paper Notes $ 1,755.7 $ 1,755.7 $ -- $ -- $ -- $ -- $ -- Senior Notes 19,850.0 1,100.0 1,500.0 1,500.0 575.0 650.0 14,525.0 Junior Subordinated Notes 3,174.4 -- -- -- -- -- 3,174.4 Total $ 24,780.1 $ 2,855.7 $ 1,500.0 $ 1,500.0 $ 575.0 $ 650.0 $ 17,699.4
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 EPO Junior Subordinated Notes A 8.375% through July 31, 2016 3-month LIBOR rate + 3.708% (6) EPO Junior Subordinated Notes B 7.034% through January 14, 2018 (2) Greater of: (i) 3-month LIBOR rate + 2.680% or (ii) 7.034% (7) EPO Junior Subordinated Notes C 7.000% through May 31, 2017 (3) 3-month LIBOR rate + 2.778% EPO Junior Subordinated Notes D 4.875% through August 15, 2022 (4) 3-month LIBOR rate + 2.986% EPO Junior Subordinated Notes E 5.250% through August 15, 2027 (5) 3-month LIBOR rate + 3.033% (1) Interest is payable semi-annually in arrears in February and August of each year, which commenced in February 2007. (2) Interest was 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 semi-annually in arrears in February and August of each year, which commenced in February 2018. (5) Interest is payable semi-annually in arrears in February and August of each year, which commenced in February 2018. (6) Interest is payable quarterly in arrears in February, May, August and November of each, which commenced in November 2016. (7) Interest was payable quarterly in arrears in January, April, July and October of each year commencing in April 2018. (8) Interest is payable quarterly in arrears in March, June, September and December of each year, which commenced in September 2017. (9) Interest is payable quarterly in arrears in February, May, August and November of each year commencing in November 2022. (10) Interest is payable quarterly in arrears in February, May, August and November of each year commencing in November 2027. See Note 22, Subsequent Events

Equity and Distributions (Table

Equity and Distributions (Tables)	12 Months Ended
	Dec. 31, 2017
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) outstanding. The following table summarizes changes in the number of our outstanding units since January 1, 2015: Common Units (Unrestricted) Restricted Common Units Total Common Units Number of units outstanding at January 1, 2015 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 ) Cancellation of treasury units acquired 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 Common units issued in connection with ATM program 87,867,037 -- 87,867,037 Common units issued in connection with DRIP and EUPP 16,316,534 -- 16,316,534 Common units issued in connection with the vesting of phantom unit awards 1,761,455 -- 1,761,455 Common units issued in connection with the vesting of restricted common unit awards 1,234,502 (1,234,502 ) -- Forfeiture of restricted common unit awards -- (43,724 ) (43,724 ) Cancellation of treasury units acquired in connection with the vesting of equity-based awards (1,000,619 ) -- (1,000,619 ) Other 134,707 -- 134,707 Number of units outstanding at December 31, 2016 2,116,906,120 682,294 2,117,588,414 Common units issued in connection with ATM program 21,807,726 -- 21,807,726 Common units issued in connection with DRIP and EUPP 19,046,019 -- 19,046,019 Common units issued in connection with the vesting of phantom unit awards 2,485,580 -- 2,485,580 Common units issued in connection with the vesting of restricted common unit awards 681,044 (681,044 ) -- Forfeiture of restricted common unit awards -- (1,250 ) (1,250 ) Cancellation of treasury units acquired in connection with the vesting of equity-based awards (1,027,798 ) -- (1,027,798 ) Common units issued in connection with employee compensation 1,176,103 -- 1,176,103 Other 14,685 -- 14,685 Number of units outstanding at December 31, 2017 2,161,089,479 -- 2,161,089,479
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, 2015 $ 56.6 $ (279.5 ) $ 3.7 $ (219.2 ) Other comprehensive income (loss) before reclassifications (193.8 ) 42.3 (0.1 ) (151.6 ) Amounts reclassified from accumulated other comprehensive loss 53.4 37.4 -- 90.8 Total other comprehensive income (loss) (140.4 ) 79.7 (0.1 ) (60.8 ) Balance, December 31, 2016 (83.8 ) (199.8 ) 3.6 (280.0 ) Other comprehensive income (loss) before reclassifications (38.5 ) (5.7 ) (0.1 ) (44.3 ) Amounts reclassified from accumulated other comprehensive loss 112.2 40.4 -- 152.6 Total other comprehensive income (loss) 73.7 34.7 (0.1 ) 108.3 Balance, December 31, 2017 $ (10.1 ) $ (165.1 ) $ 3.5 $ (171.7 )
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 2017 2016 Losses (gains) on cash flow hedges: Interest rate derivatives Interest expense $ 40.4 $ 37.4 Commodity derivatives Revenue 111.6 53.6 Commodity derivatives Operating costs and expenses 0.6 (0.2 ) Total $ 152.6 $ 90.8
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, 2017 2016 2015 Limited partners of Oiltanking other than EPO $ -- $ -- $ 7.8 Joint venture partners 56.3 39.9 29.4 Total $ 56.3 $ 39.9 $ 37.2
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, 2017 2016 2015 Cash distributions paid to noncontrolling interests: Limited partners of Oiltanking other than EPO $ -- $ -- $ 8.1 Joint venture partners 49.2 47.4 39.9 Total $ 49.2 $ 47.4 $ 48.0 Cash contributions from noncontrolling interests: Joint venture partners $ 0.4 $ 20.4 $ 54.0
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 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 2016: 1st Quarter $ 0.3950 4/29/2016 5/6/2016 2nd Quarter $ 0.4000 7/29/2016 8/5/2016 3rd Quarter $ 0.4050 10/31/2016 11/7/2016 4th Quarter $ 0.4100 1/31/2017 2/7/2017 2017: 1st Quarter $ 0.4150 4/28/2017 5/8/2017 2nd Quarter $ 0.4200 7/31/2017 8/7/2017 3rd Quarter $ 0.4225 10/31/2017 11/7/2017 4th Quarter $ 0.4250 1/31/2018 2/7/2018

Business Segments (Tables)

Business Segments (Tables)	12 Months Ended
	Dec. 31, 2017
Business Segments [Abstract]
Measurement of Total Segment Gross Operating Margin	The following table presents our measurement of total segment gross operating margin for the periods presented. The GAAP financial measure most directly comparable to total segment gross operating margin is operating income. For the Year Ended December 31, 2017 2016 2015 Income before income taxes $ 2,881.3 $ 2,576.4 $ 2,555.9 Add total other expense, net 1,047.6 1,004.3 984.3 Operating income 3,928.9 3,580.7 3,540.2 Adjustments to reconcile operating income to total gross operating margin: Add depreciation, amortization and accretion expense in operating costs and expenses 1,531.3 1,456.7 1,428.2 Add asset impairment and related charges in operating costs and expenses 49.8 52.8 162.6 Add net losses or subtract net gains attributable to asset sales in operating costs and expenses (10.7 ) (2.5 ) 15.6 Add general and administrative costs 181.1 160.1 192.6 Adjustments for make-up rights on certain new pipeline projects: Add non-refundable payments received from shippers attributable to make-up rights (1) 24.1 17.5 53.6 Subtract the subsequent recognition of revenues attributable to make-up rights (2) (29.9 ) (34.6 ) (60.7 ) Total segment gross operating margin $ 5,674.6 $ 5,230.7 $ 5,332.1 (1) Since make-up rights entail a future performance obligation by the pipeline to the shipper, these receipts are recorded as deferred revenue for GAAP purposes; however, these receipts are included in gross operating margin in the period of receipt since they are nonrefundable to the shipper. (2) As deferred revenues attributable to make-up rights are subsequently recognized as revenue under GAAP, gross operating margin must be adjusted to remove such amounts to prevent duplication since the associated non-refundable payments were previously included in gross operating margin.
Information by Business Segments	Gross operating margin by segment is calculated by subtracting segment operating costs and expenses from segment revenues, with both segment totals reflecting the adjustments noted in the preceding table, as applicable, and before the elimination of intercompany transactions. The following table presents gross operating margin by segment for the periods indicated: For the Year Ended December 31, 2017 2016 2015 Gross operating margin by segment: NGL Pipelines & Services $ 3,258.3 $ 2,990.6 $ 2,771.6 Crude Oil Pipelines & Services 987.2 854.6 961.9 Natural Gas Pipelines & Services 714.5 734.9 782.6 Petrochemical & Refined Products Services 714.6 650.6 718.5 Offshore Pipelines & Services -- -- 97.5 Total segment gross operating margin $ 5,674.6 $ 5,230.7 $ 5,332.1 Information by business segment, together with reconciliations to amounts presented on our Statements of Consolidated Operations, 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, 2017 $ 12,455.7 $ 8,137.2 $ 3,132.5 $ 5,471.1 $ -- $ -- $ 29,196.5 Year ended December 31, 2016 10,232.7 6,478.7 2,532.4 3,721.8 -- -- 22,965.6 Year ended December 31, 2015 9,779.0 10,258.3 2,729.5 4,111.9 76.9 -- 26,955.6 Revenues from related parties: Year ended December 31, 2017 12.3 19.6 13.1 -- -- -- 45.0 Year ended December 31, 2016 9.8 36.3 10.6 -- -- -- 56.7 Year ended December 31, 2015 9.0 47.6 13.8 -- 1.9 -- 72.3 Intersegment and intrasegment revenues: Year ended December 31, 2017 27,278.6 15,943.0 850.8 1,766.9 -- (45,839.3 ) -- Year ended December 31, 2016 19,150.0 9,052.0 668.5 1,234.8 -- (30,105.3 ) -- Year ended December 31, 2015 10,217.9 5,162.0 662.1 1,126.0 0.6 (17,168.6 ) -- Total revenues: Year ended December 31, 2017 39,746.6 24,099.8 3,996.4 7,238.0 -- (45,839.3 ) 29,241.5 Year ended December 31, 2016 29,392.5 15,567.0 3,211.5 4,956.6 -- (30,105.3 ) 23,022.3 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 Equity in income (loss) of unconsolidated affiliates: Year ended December 31, 2017 73.4 358.4 3.8 (9.6 ) -- -- 426.0 Year ended December 31, 2016 61.4 311.9 3.8 (15.1 ) -- -- 362.0 Year ended December 31, 2015 57.5 281.4 3.8 (15.7 ) 46.6 -- 373.6 Information by business segment, together with reconciliations to our Consolidated Balance Sheet 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 Property, plant and equipment, net: At December 31, 2017 $ 13,831.2 $ 5,208.4 $ 8,375.0 $ 3,507.7 $ -- $ 4,698.1 $ 35,620.4 At December 31, 2016 14,091.5 4,216.1 8,403.0 3,261.2 -- 3,320.7 33,292.5 At December 31, 2015 12,909.7 3,550.3 8,620.0 3,060.7 -- 3,894.0 32,034.7 Investments in unconsolidated affiliates: At December 31, 2017 733.9 1,839.2 20.8 65.5 -- -- 2,659.4 At December 31, 2016 750.4 1,824.6 21.7 80.6 -- -- 2,677.3 At December 31, 2015 718.7 1,813.4 22.5 73.9 -- -- 2,628.5 Intangible assets, net: At December 31, 2017 322.3 2,186.5 1,018.4 163.1 -- -- 3,690.3 At December 31, 2016 350.2 2,279.0 1,054.5 180.4 -- -- 3,864.1 At December 31, 2015 380.3 2,377.5 1,087.7 191.7 -- -- 4,037.2 Goodwill: At December 31, 2017 2,651.7 1,841.0 296.3 956.2 -- -- 5,745.2 At December 31, 2016 2,651.7 1,841.0 296.3 956.2 -- -- 5,745.2 At December 31, 2015 2,651.7 1,841.0 296.3 956.2 -- -- 5,745.2 Segment assets: At December 31, 2017 17,539.1 11,075.1 9,710.5 4,692.5 -- 4,698.1 47,715.3 At December 31, 2016 17,843.8 10,160.7 9,775.5 4,478.4 -- 3,320.7 45,579.1 At December 31, 2015 16,660.4 9,582.2 10,026.5 4,282.5 -- 3,894.0 44,445.6
Consolidated Revenues and Expenses	Other Revenue and Expense Information The following table presents supplemental information regarding our consolidated revenues and costs and expenses for the periods indicated: For the Year Ended December 31, 2017 2016 2015 Consolidated revenues: NGL Pipelines & Services $ 12,468.0 $ 10,242.5 $ 9,788.0 Crude Oil Pipelines & Services 8,156.8 6,515.0 10,305.9 Natural Gas Pipelines & Services 3,145.6 2,543.0 2,743.3 Petrochemical & Refined Products Services 5,471.1 3,721.8 4,111.9 Offshore Pipelines & Services -- -- 78.8 Total consolidated revenues $ 29,241.5 $ 23,022.3 $ 27,027.9 Consolidated costs and expenses: Operating costs and expenses: Cost of sales $ 21,487.0 $ 15,710.9 $ 19,612.9 Other operating costs and expenses (1) 2,500.1 2,425.6 2,449.4 Depreciation, amortization and accretion 1,531.3 1,456.7 1,428.2 Asset impairment and related charges 49.8 52.8 162.6 Ne t losses (g (10.7 ) (2.5 ) 15.6 General and administrative costs 181.1 160.1 192.6 Total consolidated costs and expenses $ 25,738.6 $ 19,803.6 $ 23,861.3 (1) Represents the cost of operating our plants, pipelines and other fixed assets excluding: depreciation, amortization and accretion charges; asset impairment and related charges; and net losses (or gains) attributable to asset sales and insurance recoveries. Our largest non-affiliated customer for 2017 was (collectively, “ ”), which accounted for $3.29 billion, or 11.2%, of our consolidated revenues for the year. is a global energy and commodity trading company. The following table presents our consolidated revenues from by business segment for the year ended December 31, 2017: NGL Pipelines & Services $ 2,099.1 Crude Oil Pipelines & Services 625.6 Natural Gas Pipelines & Services 51.1 Petrochemical & Refined Products Services 512.5 Total $ 3,288.3

Earnings Per Unit (Tables)

Earnings Per Unit (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 2015 BASIC EARNINGS PER UNIT Net income attributable to limited partners $ 2,799.3 $ 2,513.1 $ 2,521.2 Undistributed earnings allocated and cash payments on phantom unit awards (1) (15.9 ) (12.9 ) (8.7 ) Net income available to common unitholders $ 2,783.4 $ 2,500.2 $ 2,512.5 Basic weighted-average number of common units outstanding 2,145.0 2,081.4 1,966.6 Basic earnings per unit $ 1.30 $ 1.20 $ 1.28 DILUTED EARNINGS PER UNIT Net income attributable to limited partners $ 2,799.3 $ 2,513.1 $ 2,521.2 Diluted weighted-average number of units outstanding: Distribution-bearing common units 2,145.0 2,081.4 1,966.6 Designated Units -- -- 26.5 Phantom units (1) 9.3 7.7 5.4 Incremental option units -- -- 0.1 Total 2,154.3 2,089.1 1,998.6 Diluted earnings per unit $ 1.30 $ 1.20 $ 1.26 (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.

Business Combinations (Tables)

Business Combinations (Tables)	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Allocation of Total Purchase Prices Paid in Connection with Business Combinations	The following table presents the final fair value allocation of assets acquired and liabilities assumed in the Azure acquisition at April 30, 2017. Assets acquired in business combination: Current assets $ 3.1 Property, plant and equipment 193.1 Total assets acquired 196.2 Liabilities assumed in business combination: Current liabilities 1.4 Long-term liabilities 3.4 Total liabilities assumed 4.8 Cash used for Azure acquisition $ 191.4
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 reflect any earnings from this business prior to this date. Our consolidated revenues and net income for the last six months ended December 31, 2015 include $117.8 million and $59.9 million, respectively, from EFS Midstream. The following table presents selected unaudited pro forma earnings information for the year ended December 31, 2015 as if the acquisition had been completed on January 1, 2015. 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 year ended December 31, 2015 had we acquired EFS Midstream on January 1, 2015. Pro forma earnings data: Revenues $ 27,148.5 Costs and expenses 23,937.1 Operating income 3,585.0 Net income 2,594.4 Net income attributable to noncontrolling interests 37.2 Net income attributable to limited partners 2,557.2 Basic earnings per unit: As reported basic earnings per unit $ 1.28 Pro forma basic earnings per unit $ 1.30 Diluted earnings per unit: As reported diluted earnings per unit $ 1.26 Pro forma diluted earnings per unit $ 1.28

Equity-Based Awards (Tables)

Equity-Based Awards (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 2015 Equity-classified awards: Phantom unit awards $ 92.8 $ 78.6 $ 78.3 Restricted common unit awards 0.5 4.7 14.7 Profits interest awards 6.0 5.4 -- Liability-classified awards 0.4 0.5 0.2 Total $ 99.7 $ 89.2 $ 93.2
Other Share-based Compensation Plans	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 January 1, 2015 3,342,390 $ 33.13 Granted (2) 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 Granted (3) 4,508,310 $ 21.90 Vested (1,761,455 ) $ 33.10 Forfeited (406,303 ) $ 28.52 Phantom unit awards at December 31, 2016 7,767,501 $ 27.20 Granted (4) 4,268,920 $ 28.83 Vested (2,490,081 ) $ 28.30 Forfeited (256,839 ) $ 27.60 Phantom unit awards at December 31, 2017 9,289,501 $ 27.65 (1) Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued. (2) The aggregate grant date fair value of phantom unit awards issued during 2015 was $118.7 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 percent was applied to these awards. (3) The aggregate grant date fair value of phantom unit awards issued during 2016 was $98.7 million based on a grant date market price of our common units ranging from $21.86 to $27.39 per unit. An estimated annual forfeiture rate of 3.9 percent was applied to these awards. (4) The aggregate grant date fair value of phantom unit awards issued during 2017 was $123.1 million based on a grant date market price of our common units ranging from $24.55 to $28.87 per unit. An estimated annual forfeiture rate of 3.8 percent was applied to these awards. The following table summarizes key elements of each Employee Partnership as of December 31, 2017: Employee Partnership Enterprise Common Units contributed to Employee Partnership by EPCO Holdings Class A Capital Base Class A Preference Return Expected Vesting/ Liquidation Date Estimated Grant Date Fair Value of Profits Interest Awards Unrecognized Compensation Cost PubCo I 2,723,052 $63.7 million $ 0.39 Feb. 2020 $13.2 million $7.4 million PubCo II 2,834,198 $66.3 million $ 0.39 Feb. 2021 $14.7 million $9.3 million PubCo III 105,000 $2.5 million $ 0.39 Apr. 2020 $0.6 million $0.2 million PrivCo I 1,111,438 $26.0 million $ 0.39 Feb. 2021 $5.8 million $0.8 million (1) Represents fair market value of the Enterprise common units contributed to each Employee Partnership at the applicable contribution date. (2) Each quarter, the Class A limited partner in each Employee Partnership is paid a cash distribution equal to the product of (i) the number of common units owned by the Employee Partnership and (ii) the Class A Preference Return of $0.39 per unit (subject to equitable adjustment in order to reflect any equity split, equity distribution or dividend, reverse split, combination, reclassification, recapitalization or other similar event affecting such common units). To the extent that the Employee Partnership has cash remaining after making this quarterly payment to the Class A limited partner, the residual cash is distributed to the Class B limited partners on a quarterly basis. (3) Represents the total grant date fair value of the profits interest awards irrespective of how such costs will be allocated between us and EPCO and its privately held affiliates. (4) Represents our expected share of the unrecognized compensation cost at December 31, 2017. We expect to recognize our share of the unrecognized compensation cost for PubCo I, PubCo II, PubCo III and PrivCo I over a weighted-average period of 2.1 years, 3.1 years, 2.3 years and 3.1 years, respectively. The following table summarizes the assumptions we used in applying a Black-Scholes option pricing model to derive that portion of the estimated grant date fair value of the profits interest awards for each Employee Partnership: Expected Risk-Free Expected Expected Unit Employee Life Interest Distribution Price Partnership of Award Rate Yield Volatility PubCo I 4.0 years 0.9% to 1.6% 6.2% to 7.0% 29% to 40% PubCo II 5.0 years 1.1% to 1.8% 6.1% to 7.0% 27% to 40% PubCo III 4.0 years 1.0% to 1.4% 6.1% to 6.2% 31% to 40% PrivCo I 5.0 years 1.2% to 1.6% 6.1% to 6.7% 28% to 40%
Supplemental Information Regarding Phantom Unit Awards	The following table presents supplemental information regarding phantom unit awards for the periods indicated: For the Year Ended December 31, 2017 2016 2015 Cash payments made in connection with DERs $ 15.1 $ 11.7 $ 7.7 Total intrinsic value of phantom unit awards that vested during period $ 69.8 $ 40.9 $ 31.2
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 January 1, 2015 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 Vested (1,234,502 ) $ 27.45 Forfeited (43,724 ) $ 28.48 Restricted common units at December 31, 2016 682,294 $ 28.61 Vested (681,044 ) $ 28.60 Forfeited (1,250 ) $ 31.07 Restricted common units at December 31, 2017 -- N/A (1) Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued.
Supplemental Information Regarding Restricted Common Unit Awards	The following table presents supplemental information regarding restricted common unit awards for the periods indicated: For the Year Ended December 31, 2017 2016 2015 Cash distributions paid to restricted common unitholders $ 0.3 $ 1.6 $ 4.0 Total intrinsic value of restricted common unit awards that vested during period $ 18.9 $ 28.5 $ 67.3
Unit Option Activity	The following table presents unit option award activity for the period indicated: Number of Units Weighted- Average Strike Price (dollars/unit) Unit option awards at January 1, 2015 1,270,000 $ 16.14 Exercised (1,270,000 ) $ 16.14 Unit option awards at December 31, 2015 -- $ -- The following table presents supplemental information regarding unit option awards during the year ended December 31, 2015: Total intrinsic value of unit option awards exercised during period $ 21.7 Cash received from EPCO in connection with the exercise of unit option awards $ 13.1 Unit option award-related cash reimbursements to EPCO $ 21.7

Derivative Instruments, Hedgi43

Derivative Instruments, Hedging Activities and Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017: 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 1.87% Fair value hedge At December 31, 2017, our portfolio of forward starting swaps was as follows: Hedged Transaction Number and Type of Derivatives Outstanding Notional Amount Expected Settlement Date Average Rate Locked Accounting Treatment Future long-term debt offering 3 forward starting swaps $ 275.0 2/2019 2.57% Cash flow hedge The following table summarizes our portfolio of commodity derivative instruments outstanding at December 31, 2017 (volume measures as noted): Volume Accounting Derivative Purpose Current Long-Term Treatment Derivatives designated as hedging instruments: Octane enhancement: Forecasted purchase of NGLs (MMBbls) 1.1 n/a Cash flow hedge Forecasted sales of octane enhancement products (MMBbls) 1.0 n/a Cash flow hedge Natural gas marketing: Forecasted purchases of natural gas for fuel (Bcf) 1.0 n/a Cash flow hedge Natural gas storage inventory management activities (Bcf) 3.9 n/a Fair value hedge NGL marketing: Forecasted purchases of NGLs and related hydrocarbon products (MMBbls) 49.0 n/a Cash flow hedge Forecasted sales of NGLs and related hydrocarbon products (MMBbls) 64.6 n/a Cash flow hedge NGLs inventory management activities (MMBbls) 0.5 n/a Fair value hedge Refined products marketing: Forecasted purchases of refined products (MMBbls) 0.6 n/a Cash flow hedge Forecasted sales of refined products (MMBbls) 1.3 n/a Cash flow hedge Refined products inventory management activities (MMBbls) 0.5 n/a Fair value hedge Crude oil marketing: Forecasted purchases of crude oil (MMBbls) 3.7 3.3 Cash flow hedge Forecasted sales of crude oil (MMBbls) 6.9 3.3 Cash flow hedge Petrochemical marketing: Forecasted purchases of NGLs for propylene marketing activities (MMBbls) 0.8 n/a Cash flow hedge Derivatives not designated as hedging instruments: Natural gas risk management activities (Bcf) (3,4) 67.3 9.0 Mark-to-market NGL risk management activities (MMBbls) (4) 18.3 n/a Mark-to-market Refined products risk management activities (MMBbls) (4) 0.6 n/a Mark-to-market Crude oil risk management activities (MMBbls) (4) 104.0 12.2 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 2020, May 2018 and December 2020, respectively. (3) Current and long-term volumes include 21.1 Bcf and 5.3 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, 2017 December 31, 2016 December 31, 2017 December 31, 2016 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 $ -- Current assets $ 0.3 Current liabilities $ 1.5 Current liabilities $ 0.2 Interest rate derivatives Other assets 0.1 Other assets 36.2 Other liabilities 0.2 Other liabilities 0.9 Total interest rate derivatives 0.1 36.5 1.7 1.1 Commodity derivatives Current assets 109.5 Current assets 499.2 Current liabilities 104.4 Current liabilities 662.0 Commodity derivatives Other assets 6.4 Other assets -- Other liabilities 6.8 Other liabilities -- Total commodity derivatives 115.9 499.2 111.2 662.0 Total derivatives designated as hedging instruments $ 116.0 $ 535.7 $ 112.9 $ 663.1 Derivatives not designated as hedging instruments Commodity derivatives Current assets $ 43.9 Current assets $ 41.9 Current liabilities $ 62.3 Current liabilities $ 75.5 Commodity derivatives Other assets 1.9 Other assets 0.3 Other liabilities 3.4 Other liabilities 1.9 Total commodity derivatives 45.8 42.2 65.7 77.4 Total derivatives not designated as hedging instruments $ 45.8 $ 42.2 $ 65.7 $ 77.4
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, 2017: Interest rate derivatives $ 0.1 $ -- $ 0.1 $ (0.1 ) $ -- $ -- $ -- Commodity derivatives 161.7 -- 161.7 (157.8 ) -- -- 3.9 As of December 31, 2016: Interest rate derivatives $ 36.5 $ -- $ 36.5 $ (0.2 ) $ -- $ -- $ 36.3 Commodity derivatives 541.4 -- 541.4 (526.8 ) -- -- 14.6
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, 2017: Interest rate derivatives $ 1.7 $ -- $ 1.7 $ (0.1 ) $ -- $ 1.6 Commodity derivatives 176.9 -- 176.9 (157.8 ) (17.3 ) 1.8 As of December 31, 2016: Interest rate derivatives $ 1.1 $ -- $ 1.1 $ (0.2 ) $ -- $ 0.9 Commodity derivatives 739.4 -- 739.4 (526.8 ) (212.4 ) 0.2
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, 2017 2016 2015 Interest rate derivatives Interest expense $ (0.2 ) $ 0.3 $ (1.4 ) Commodity derivatives Revenue 1.1 (90.5 ) 19.1 Total $ 0.9 $ (90.2 ) $ 17.7 Derivatives in Fair Value Hedging Relationships Location Gain (Loss) Recognized in Income on Hedged Item For the Year Ended December 31, 2017 2016 2015 Interest rate derivatives Interest expense $ 0.4 $ (0.4 ) $ 1.4 Commodity derivatives Revenue 27.4 125.0 0.2 Total $ 27.8 $ 124.6 $ 1.6
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, 2017 2016 2015 Interest rate derivatives $ (5.7 ) $ 42.3 $ -- Commodity derivatives – Revenue (1) (33.7 ) (197.4 ) 217.6 Commodity derivatives – Operating costs and expenses (1) (4.8 ) 3.6 (2.7 ) Total $ (44.2 ) $ (151.5 ) $ 214.9 (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, 2017 2016 2015 Interest rate derivatives Interest expense $ (40.4 ) $ (37.4 ) $ (35.3 ) Commodity derivatives Revenue (111.6 ) (53.6 ) 231.7 Commodity derivatives Operating costs and expenses (0.6 ) 0.2 (3.5 ) Total $ (152.6 ) $ (90.8 ) $ 192.9
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, 2017 2016 2015 Commodity derivatives Revenue $ -- $ -- $ 4.7 Commodity derivatives Operating costs and expenses (1.1 ) 0.5 0.1 Total $ (1.1 ) $ 0.5 $ 4.8
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, 2017 2016 2015 Interest rate derivatives Interest expense $ -- $ -- $ -- Commodity derivatives Revenue (42.7 ) (38.4 ) 1.0 Commodity derivatives Operating costs and expenses 0.1 (0.4 ) 0.1 Total $ (42.6 ) $ (38.8 ) $ 1.1
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. The values for commodity derivatives at December 31, 2017 are presented before and after the application of CME Rule 814, which deems that financial instruments cleared by the CME are settled daily in connection with variation margin payments. As a result of this new exchange rule, CME-related derivatives are considered to have no fair value at the balance sheet date for financial reporting purposes; however, the derivatives remain outstanding and subject to future commodity price fluctuations until they are settled in accordance with their contractual terms. The rule change was effective January 1, 2017. December 31, 2017 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 $ -- $ 0.1 $ -- $ 0.1 Commodity derivatives: Value before application of CME Rule 814 47.1 184.9 2.9 234.9 Impact of CME Rule 814 change (47.1 ) (26.1 ) -- (73.2 ) Total commodity derivatives -- 158.8 2.9 161.7 Total $ -- $ 158.9 $ 2.9 $ 161.8 Financial liabilities: Liquidity Option Agreement $ -- $ -- $ 333.9 $ 333.9 Interest rate derivatives -- 1.7 -- 1.7 Commodity derivatives: Value before application of CME Rule 814 118.4 270.6 1.7 390.7 Impact of CME Rule 814 change (118.4 ) (95.4 ) -- (213.8 ) Total commodity derivatives -- 175.2 1.7 176.9 Total $ -- $ 176.9 $ 335.6 $ 512.5 December 31, 2016 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 $ -- $ 36.5 $ -- $ 36.5 Commodity derivatives 84.5 455.2 1.7 541.4 Total $ 84.5 $ 491.7 $ 1.7 $ 577.9 Financial liabilities: Liquidity Option Agreement $ -- $ -- $ 269.6 $ 269.6 Interest rate derivatives -- 1.1 -- 1.1 Commodity derivatives 136.8 602.3 0.3 739.4 Total $ 136.8 $ 603.4 $ 269.9 $ 1,010.1
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 2017 2016 Financial asset (liability) balance, net, January 1 $ (268.2 ) $ (246.7 ) Total gains (losses) included in: Net income (1) Revenue 2.3 2.2 Net income Other expense, net (64.3 ) (24.5 ) Other comprehensive income (loss) Commodity derivative instruments – changes in fair value of cash flow hedges 0.1 (0.5 ) Settlements (1) Revenue (2.4 ) (0.5 ) Transfers out of Level 3 (2) (0.2 ) 1.8 Financial liability balance, net, December 31 $ (332.7 ) $ (268.2 ) (1) There were $0.1 million of unrealized losses and $1.7 million of unrealized gains included in these amounts for the years ended December 31, 2017 and 2016, 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, 2017 and 2016.
Fair Value Measurements, Valuation Techniques	The following Fair Value At December 31, 2017 Financial Assets Financial Liabilities Valuation Techniques Unobservable Input Range Commodity derivatives – Crude oil $ 2.9 $ 1.7 Discounted cash flow Forward commodity prices $60.21-$66.05/barrel Total $ 2.9 $ 1.7 Fair Value At December 31, 2016 Financial Assets Financial Liabilities Valuation Techniques Unobservable Input Range Commodity derivatives – Crude oil $ 1.7 $ 0.3 Discounted cash flow Forward commodity prices $51.73-$54.77/barrel Total $ 1.7 $ 0.3
Asset Impairment Charges by Segment	The following table summarizes our non-cash asset impairment charges for long-lived assets by segment during each of the periods indicated: For the Year Ended December 31, 2017 2016 2015 NGL Pipelines & Services $ 11.5 $ 21.0 $ 20.8 Crude Oil Pipelines & Services 10.2 2.3 33.5 Natural Gas Pipelines & Services 14.3 12.3 21.6 Petrochemical & Refined Products Services 1.8 9.6 28.2 Offshore Pipelines & Services -- -- 58.5 Total $ 37.8 $ 45.2 $ 162.6
Nonrecurring Fair Value Measurements	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, 2017: Fair Value Measurements at the End of the Reporting Period Using Carrying Value at December 31, 2017 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 $ -- $ -- $ -- $ -- $ 16.7 Long-lived assets held and used 1.5 -- -- 1.5 15.4 Long-lived assets held for sale 2.5 -- -- 2.5 2.5 Long-lived assets disposed of by sale -- -- -- -- 3.2 Total $ 37.8 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, 2016: Fair Value Measurements at the End of the Reporting Period Using Carrying Value at December 31, 2016 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 $ -- $ -- $ -- $ -- $ 29.9 Long-lived assets held and used 8.0 8.0 -- -- 2.2 Long-lived assets disposed of by sale -- -- -- -- 13.1 Total $ 45.2 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 and the abandonment of certain natural gas and crude oil pipeline assets in Texas. The following table presents categories of long-lived assets 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 -- -- -- -- 67.0 Total $ 162.6

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 2015 Revenues – related parties: Unconsolidated affiliates $ 45.0 $ 56.7 $ 72.3 Costs and expenses – related parties: EPCO and its privately held affiliates $ 1,010.9 $ 963.2 $ 949.3 Unconsolidated affiliates 223.4 253.9 245.3 Total $ 1,234.3 $ 1,217.1 $ 1,194.6 The following table summarizes our related party accounts receivable and accounts payable balances at the dates indicated: December 31, 2017 2016 Accounts receivable - related parties: Unconsolidated affiliates $ 1.8 $ 1.1 Accounts payable - related parties: EPCO and its privately held affiliates $ 99.3 $ 88.9 Unconsolidated affiliates 28.0 16.2 Total $ 127.3 $ 105.1 At December 31, 2017, 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 689,767,023 32% 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, 2017 2016 2015 Operating costs and expenses $ 882.1 $ 840.7 $ 826.4 General and administrative expenses 110.4 105.3 105.2 Total costs and expenses $ 992.5 $ 946.0 $ 931.6

Provision for Income Taxes (Tab

Provision for Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 2015 Current: Federal $ 0.1 $ (0.5 ) $ 0.9 State 18.5 16.7 15.5 Foreign 1.0 0.6 1.7 Total current 19.6 16.8 18.1 Deferred: Federal (1.8 ) 1.1 (1.4 ) State 7.9 5.2 (19.2 ) Foreign -- 0.3 -- Total deferred 6.1 6.6 (20.6 ) Total provision for (benefit from) income taxes $ 25.7 $ 23.4 $ (2.5 )
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, 2017 2016 2015 Pre-Tax Net Book Income (“NBI”) $ 2,881.3 $ 2,576.4 $ 2,555.9 Texas Margin Tax (1) $ 26.4 $ 22.1 $ (3.7 ) State income taxes (net of federal benefit) 0.5 0.2 0.7 Federal income taxes computed by applying the federal statutory rate to NBI of corporate entities 0.1 0.8 1.1 Other permanent differences (1.3 ) 0.3 (0.6 ) Provision for (benefit from) income taxes $ 25.7 $ 23.4 $ (2.5 ) Effective income tax rate 0.9% 0.9% (0.1)% (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, 2017 2016 Deferred tax assets: Net operating loss carryovers (1) $ 0.2 $ 0.2 Accruals 1.4 1.6 Total deferred tax assets 1.6 1.8 Less: Deferred tax liabilities: Property, plant and equipment 58.0 50.5 Equity investment in partnerships 2.1 3.7 Total deferred tax liabilities 60.1 54.2 Total net deferred tax liabilities $ 58.5 $ 52.4 (1) These losses expire in various years between 2018 and 2033 and are subject to limitations on their utilization.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies [Abstract]
Summary of Contractual Obligations	The following table summarizes our various contractual obligations at December 31, 2017. A description of each type of contractual obligation follows: Payment or Settlement due by Period Contractual Obligations Total 2018 2019 2020 2021 2022 Thereafter Scheduled maturities of debt obligations $ 24,780.1 $ 2,855.7 $ 1,500.0 $ 1,500.0 $ 575.0 $ 650.0 $ 17,699.4 Estimated cash interest payments $ 23,942.0 $ 1,082.9 $ 1,022.1 $ 964.2 $ 912.1 $ 884.7 $ 19,076.0 Operating lease obligations $ 413.3 $ 57.0 $ 52.8 $ 47.2 $ 40.0 $ 31.3 $ 185.0 Purchase obligations: Product purchase commitments: Estimated payment obligations: Natural gas $ 1,911.5 $ 615.1 $ 528.6 $ 434.9 $ 332.9 $ -- $ -- NGLs $ 99.0 $ 69.6 $ 29.4 $ -- $ -- $ -- $ -- Crude oil $ 7,891.3 $ 1,352.3 $ 1,341.0 $ 945.8 $ 728.4 $ 728.4 $ 2,795.4 Petrochemicals & refined products $ 632.1 $ 411.9 $ 214.1 $ 6.1 $ -- $ -- $ -- Other $ 33.3 $ 9.3 $ 9.3 $ 7.6 $ 3.5 $ 1.4 $ 2.2 Underlying major volume commitments: Natural gas (in TBtus) 812 265 225 182 140 -- -- NGLs (in MMBbls) 7 5 2 -- -- -- -- Crude oil (in MMBbls) 471 38 55 51 47 47 233 Petrochemicals & refined products (in MMBbls) 11 7 4 -- -- -- -- Service payment commitments $ 398.0 $ 98.3 $ 84.5 $ 60.0 $ 44.8 $ 43.1 $ 67.3 Capital expenditure commitments $ 171.6 $ 171.6 $ -- $ -- $ -- $ -- $ --
Schedule of Other Liabilities	The following table summarizes the components of “Other long-term liabilities” as presented on our Consolidated Balance Sheets at the dates indicated: December 31, 2017 2016 Noncurrent portion of AROs (see Note 5) $ 81.1 $ 76.5 Deferred revenues – non-current portion (see Note 3) 135.5 137.0 Liquidity Option Agreement 333.9 269.6 Derivative liabilities 10.4 2.8 Centennial guarantees 4.5 5.3 Other 13.0 12.7 Total $ 578.4 $ 503.9

Supplemental Cash Flow Inform47

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 2015 Decrease (increase) in: Accounts receivable – trade $ (1,076.2 ) $ (679.0 ) $ 1,279.3 Accounts receivable – related parties (0.7 ) 0.4 1.3 Inventories 194.6 (871.8 ) (72.7 ) Prepaid and other current assets 226.0 (49.3 ) (59.1 ) Other assets (111.0 ) (2.0 ) (5.8 ) Increase (decrease) in: Accounts payable – trade 66.6 (21.5 ) (52.9 ) Accounts payable – related parties 56.0 21.0 (34.8 ) Accrued product payables 952.3 1,193.3 (1,342.4 ) Accrued interest 17.3 (11.4 ) 16.5 Other current liabilities (291.4 ) 189.9 (67.1 ) Other liabilities (1.3 ) 49.5 14.4 Net effect of changes in operating accounts $ 32.2 $ (180.9 ) $ (323.3 ) Cash payments for interest, net of $192.1, $168.2 and $149.1 capitalized in 2017, 2016 and 2015, respectively $ 912.1 $ 947.9 $ 911.6 Cash payments for federal and state income taxes $ 20.9 $ 18.7 $ 17.5
Schedule of Significant Acquisitions and Disposals	The following table presents our cash proceeds from asset sales for the periods indicated: For the Year Ended December 31, 2017 2016 2015 Sale of Offshore Business (see Note 10) $ -- $ -- $ 1,527.7 Cash proceeds from other asset sales 40.1 46.5 80.9 Total $ 40.1 $ 46.5 $ 1,608.6 The following table presents net gains (losses) attributable to asset sales for the periods indicated: For the Year Ended December 31, 2017 2016 2015 Sale of Offshore Business (see Note 10) $ -- $ -- $ (12.3 ) Net gains (losses) attributable to other asset sales 10.7 2.5 (3.3 ) Total $ 10.7 $ 2.5 $ (15.6 )

Quarterly Financial Informati48

Quarterly Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017: Revenues $ 7,320.4 $ 6,607.6 $ 6,886.9 $ 8,426.6 Operating income 1,031.6 938.7 879.2 1,079.4 Net income 771.0 666.0 621.3 797.3 Net income attributable to limited partners 760.7 653.7 610.9 774.0 Earnings per unit: Basic $ 0.36 $ 0.30 $ 0.28 $ 0.36 Diluted $ 0.36 $ 0.30 $ 0.28 $ 0.36 For the Year Ended December 31, 2016: Revenues $ 5,005.3 $ 5,617.8 $ 5,920.4 $ 6,478.8 Operating income 915.6 836.9 905.0 923.2 Net income 670.2 570.0 643.1 669.7 Net income attributable to limited partners 661.2 558.5 634.6 658.8 Earnings per unit: Basic $ 0.32 $ 0.27 $ 0.30 $ 0.31 Diluted $ 0.32 $ 0.27 $ 0.30 $ 0.31

Condensed Consolidating Finan49

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2017
Condensed Consolidating Financial Information [Abstract]
Condensed Consolidating Balance Sheet	Enterprise Products Partners L.P. Condensed Consolidating Balance Sheet December 31, 2017 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 $ 65.2 $ 31.5 $ (26.4 ) $ 70.3 $ -- $ -- $ 70.3 Accounts receivable – trade, net 1,382.3 2,976.6 (0.5 ) 4,358.4 -- -- 4,358.4 Accounts receivable – related parties 110.3 1,182.1 (1,289.3 ) 3.1 -- (1.3 ) 1.8 Inventories 1,038.9 572.3 (1.4 ) 1,609.8 -- -- 1,609.8 Derivative assets 110.0 43.4 -- 153.4 -- -- 153.4 Prepaid and other current assets 136.3 189.0 (12.6 ) 312.7 -- -- 312.7 Total current assets 2,843.0 4,994.9 (1,330.2 ) 6,507.7 -- (1.3 ) 6,506.4 Property, plant and equipment, net 5,622.6 29,996.3 1.5 35,620.4 -- -- 35,620.4 Investments in unconsolidated affiliates 41,616.6 4,298.0 (43,255.2 ) 2,659.4 22,881.5 (22,881.5 ) 2,659.4 Intangible assets, net 675.5 3,028.6 (13.8 ) 3,690.3 -- -- 3,690.3 Goodwill 459.5 5,285.7 -- 5,745.2 -- -- 5,745.2 Other assets 296.4 110.0 (211.0 ) 195.4 1.0 -- 196.4 Total assets $ 51,513.6 $ 47,713.5 $ (44,808.7 ) $ 54,418.4 $ 22,882.5 $ (22,882.8 ) $ 54,418.1 LIABILITIES AND EQUITY Current liabilities: Current maturities of debt $ 2,854.6 $ 0.4 $ -- $ 2,855.0 $ -- $ -- $ 2,855.0 Accounts payable – trade 290.2 537.8 (26.4 ) 801.6 0.1 -- 801.7 Accounts payable – related parties 1,320.3 112.0 (1,305.0 ) 127.3 1.3 (1.3 ) 127.3 Accrued product payables 1,825.9 2,741.7 (1.3 ) 4,566.3 -- -- 4,566.3 Accrued interest 358.0 -- -- 358.0 -- -- 358.0 Derivative liabilities 115.2 53.0 -- 168.2 -- -- 168.2 Other current liabilities 108.9 320.1 (10.8 ) 418.2 -- 0.4 418.6 Total current liabilities 6,873.1 3,765.0 (1,343.5 ) 9,294.6 1.4 (0.9 ) 9,295.1 Long-term debt 21,699.0 14.7 -- 21,713.7 -- -- 21,713.7 Deferred tax liabilities 6.7 50.2 (0.5 ) 56.4 -- 2.1 58.5 Other long-term liabilities 60.4 396.5 (212.4 ) 244.5 333.9 -- 578.4 Commitments and contingencies Equity: Partners’ and other owners’ equity 22,874.4 43,412.0 (43,433.3 ) 22,853.1 22,547.2 (22,853.1 ) 22,547.2 Noncontrolling interests -- 75.1 181.0 256.1 -- (30.9 ) 225.2 Total equity 22,874.4 43,487.1 (43,252.3 ) 23,109.2 22,547.2 (22,884.0 ) 22,772.4 Total liabilities and equity $ 51,513.6 $ 47,713.5 $ (44,808.7 ) $ 54,418.4 $ 22,882.5 $ (22,882.8 ) $ 54,418.1 Enterprise Products Partners L.P. Condensed Consolidating Balance Sheet December 31, 2016 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 $ 366.2 $ 58.9 $ (7.5 ) $ 417.6 $ -- $ -- $ 417.6 Accounts receivable – trade, net 1,499.4 1,830.3 (0.2 ) 3,329.5 -- -- 3,329.5 Accounts receivable – related parties 131.5 961.4 (1,090.7 ) 2.2 -- (1.1 ) 1.1 Inventories 1,357.5 413.5 (0.5 ) 1,770.5 -- -- 1,770.5 Derivative assets 464.8 76.6 -- 541.4 -- -- 541.4 Prepaid and other current assets 290.7 191.1 (13.7 ) 468.1 -- -- 468.1 Total current assets 4,110.1 3,531.8 (1,112.6 ) 6,529.3 -- (1.1 ) 6,528.2 Property, plant and equipment, net 4,796.5 28,495.7 0.3 33,292.5 -- -- 33,292.5 Investments in unconsolidated affiliates 39,995.5 4,227.9 (41,546.1 ) 2,677.3 22,317.1 (22,317.1 ) 2,677.3 Intangible assets, net 700.2 3,178.2 (14.3 ) 3,864.1 -- -- 3,864.1 Goodwill 459.5 5,285.7 -- 5,745.2 -- -- 5,745.2 Other assets 222.6 41.0 (177.5 ) 86.1 0.6 -- 86.7 Total assets $ 50,284.4 $ 44,760.3 $ (42,850.2 ) $ 52,194.5 $ 22,317.7 $ (22,318.2 ) $ 52,194.0 LIABILITIES AND EQUITY Current liabilities: Current maturities of debt $ 2,576.7 $ 0.1 $ -- $ 2,576.8 $ -- $ -- $ 2,576.8 Accounts payable – trade 133.1 272.1 (7.5 ) 397.7 -- -- 397.7 Accounts payable – related parties 1,071.5 139.6 (1,106.0 ) 105.1 1.1 (1.1 ) 105.1 Accrued product payables 1,944.5 1,670.3 (1.1 ) 3,613.7 -- -- 3,613.7 Accrued interest 340.7 0.1 -- 340.8 -- -- 340.8 Derivative liabilities 590.3 147.4 -- 737.7 -- -- 737.7 Other current liabilities 173.5 316.5 (12.0 ) 478.0 -- 0.7 478.7 Total current liabilities 6,830.3 2,546.1 (1,126.6 ) 8,249.8 1.1 (0.4 ) 8,250.5 Long-term debt 21,105.7 15.2 -- 21,120.9 -- -- 21,120.9 Deferred tax liabilities 5.0 45.1 (1.1 ) 49.0 -- 3.7 52.7 Other long-term liabilities 13.5 400.6 (179.8 ) 234.3 269.6 -- 503.9 Commitments and contingencies Equity: Partners’ and other owners’ equity 22,329.9 41,675.3 (41,713.4 ) 22,291.8 22,047.0 (22,291.8 ) 22,047.0 Noncontrolling interests -- 78.0 170.7 248.7 -- (29.7 ) 219.0 Total equity 22,329.9 41,753.3 (41,542.7 ) 22,540.5 22,047.0 (22,321.5 ) 22,266.0 Total liabilities and equity $ 50,284.4 $ 44,760.3 $ (42,850.2 ) $ 52,194.5 $ 22,317.7 $ (22,318.2 ) $ 52,194.0
Condensed Consolidating Statement of Operations	Enterprise Products Partners L.P. Condensed Consolidating Statement of Operations For the Year Ended December 31, 2017 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 $ 40,696.8 $ 18,451.2 $ (29,906.5 ) $ 29,241.5 $ -- $ -- $ 29,241.5 Costs and expenses: Operating costs and expenses 39,809.6 15,654.9 (29,907.0 ) 25,557.5 -- -- 25,557.5 General and administrative costs 31.4 148.0 (0.1 ) 179.3 1.8 -- 181.1 Total costs and expenses 39,841.0 15,802.9 (29,907.1 ) 25,736.8 1.8 -- 25,738.6 Equity in income of unconsolidated affiliates 2,990.1 566.8 (3,130.9 ) 426.0 2,865.4 (2,865.4 ) 426.0 Operating income 3,845.9 3,215.1 (3,130.3 ) 3,930.7 2,863.6 (2,865.4 ) 3,928.9 Other income (expense): Interest expense (982.5 ) (11.8 ) 9.7 (984.6 ) -- -- (984.6 ) Other, net 9.2 1.8 (9.7 ) 1.3 (64.3 ) -- (63.0 ) Total other expense, net (973.3 ) (10.0 ) -- (983.3 ) (64.3 ) -- (1,047.6 ) Income before income taxes 2,872.6 3,205.1 (3,130.3 ) 2,947.4 2,799.3 (2,865.4 ) 2,881.3 Provision for income taxes (12.0 ) (13.7 ) -- (25.7 ) -- -- (25.7 ) Net income 2,860.6 3,191.4 (3,130.3 ) 2,921.7 2,799.3 (2,865.4 ) 2,855.6 Net loss (income) attributable to noncontrolling interests -- (6.5 ) (55.1 ) (61.6 ) -- 5.3 (56.3 ) Net income attributable to entity $ 2,860.6 $ 3,184.9 $ (3,185.4 ) $ 2,860.1 $ 2,799.3 $ (2,860.1 ) $ 2,799.3 Enterprise Products Partners L.P. Condensed Consolidating Statement of Operations For the Year Ended December 31, 2016 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 $ 28,958.7 $ 15,296.8 $ (21,233.2 ) $ 23,022.3 $ -- $ -- $ 23,022.3 Costs and expenses: Operating costs and expenses 28,108.2 12,768.9 (21,233.6 ) 19,643.5 -- -- 19,643.5 General and administrative costs 22.5 135.3 -- 157.8 2.3 -- 160.1 Total costs and expenses 28,130.7 12,904.2 (21,233.6 ) 19,801.3 2.3 -- 19,803.6 Equity in income of unconsolidated affiliates 2,686.1 521.7 (2,845.8 ) 362.0 2,539.9 (2,539.9 ) 362.0 Operating income 3,514.1 2,914.3 (2,845.4 ) 3,583.0 2,537.6 (2,539.9 ) 3,580.7 Other income (expense): Interest expense (973.1 ) (17.3 ) 7.8 (982.6 ) -- -- (982.6 ) Other, net 8.3 2.3 (7.8 ) 2.8 (24.5 ) -- (21.7 ) Total other expense, net (964.8 ) (15.0 ) -- (979.8 ) (24.5 ) -- (1,004.3 ) Income before income taxes 2,549.3 2,899.3 (2,845.4 ) 2,603.2 2,513.1 (2,539.9 ) 2,576.4 Provision for income taxes (13.1 ) (8.2 ) -- (21.3 ) -- (2.1 ) (23.4 ) Net income 2,536.2 2,891.1 (2,845.4 ) 2,581.9 2,513.1 (2,542.0 ) 2,553.0 Net loss (income) attributable to noncontrolling interests -- (7.4 ) (37.8 ) (45.2 ) -- 5.3 (39.9 ) Net income attributable to entity $ 2,536.2 $ 2,883.7 $ (2,883.2 ) $ 2,536.7 $ 2,513.1 $ (2,536.7 ) $ 2,513.1 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 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
Condensed Consolidating Statement of Comprehensive Income	Enterprise Products Partners L.P. Condensed Consolidating Statement of Comprehensive Income For the Year Ended December 31, 2017 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 $ 2,951.7 $ 3,208.6 $ (3,130.2 ) $ 3,030.1 $ 2,907.6 $ (2,973.8 ) $ 2,963.9 Comprehensive loss (income) attributable to noncontrolling interests -- (6.5 ) (55.1 ) (61.6 ) -- 5.3 (56.3 ) Comprehensive income attributable to entity $ 2,951.7 $ 3,202.1 $ (3,185.3 ) $ 2,968.5 $ 2,907.6 $ (2,968.5 ) $ 2,907.6 Enterprise Products Partners L.P. Condensed Consolidating Statement of Comprehensive Income For the Year Ended December 31, 2016 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 $ 2,544.3 $ 2,822.1 $ (2,845.3 ) $ 2,521.1 $ 2,452.2 $ (2,481.1 ) $ 2,492.2 Comprehensive loss (income) attributable to noncontrolling interests -- (7.4 ) (37.8 ) (45.2 ) -- 5.3 (39.9 ) Comprehensive income attributable to entity $ 2,544.3 $ 2,814.7 $ (2,883.1 ) $ 2,475.9 $ 2,452.2 $ (2,475.8 ) $ 2,452.3 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
Condensed Consolidating Statement of Cash Flows	Enterprise Products Partners L.P. Condensed Consolidating Statement of Cash Flows For the Year Ended December 31, 2017 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 $ 2,860.6 $ 3,191.4 $ (3,130.3 ) $ 2,921.7 $ 2,799.3 $ (2,865.4 ) $ 2,855.6 Reconciliation of net income to net cash flows provided by operating activities: Depreciation, amortization and accretion 216.6 1,427.8 (0.4 ) 1,644.0 -- -- 1,644.0 Equity in income of unconsolidated affiliates (2,990.1 ) (566.8 ) 3,130.9 (426.0 ) (2,865.4 ) 2,865.4 (426.0 ) Distributions received on earnings from unconsolidated affiliates 1,162.8 272.7 (1,001.8 ) 433.7 3,574.6 (3,574.6 ) 433.7 Net effect of changes in operating accounts and other operating activities 2,812.2 (2,726.3 ) (19.1 ) 66.8 93.2 (1.0 ) 159.0 Net cash flows provided by operating activities 4,062.1 1,598.8 (1,020.7 ) 4,640.2 3,601.7 (3,575.6 ) 4,666.3 Investing activities: Capital expenditures, net of contributions in aid of construction costs (846.8 ) (2,255.0 ) -- (3,101.8 ) -- -- (3,101.8 ) Cash used for business combinations, net of cash received (7.3 ) (191.4 ) -- (198.7 ) -- -- (198.7 ) Proceeds from asset sales 17.0 23.1 -- 40.1 -- -- 40.1 Other investing activities (1,908.5 ) (28.0 ) 1,910.8 (25.7 ) (1,060.5 ) 1,060.5 (25.7 ) Cash used in investing activities (2,745.6 ) (2,451.3 ) 1,910.8 (3,286.1 ) (1,060.5 ) 1,060.5 (3,286.1 ) Financing activities: Borrowings under debt agreements 69,349.3 -- (34.0 ) 69,315.3 -- -- 69,315.3 Repayments of debt (68,459.5 ) (0.1 ) -- (68,459.6 ) -- -- (68,459.6 ) Cash distributions paid to partners (3,574.6 ) (1,065.3 ) 1,065.3 (3,574.6 ) (3,569.9 ) 3,574.6 (3,569.9 ) Cash payments made in connection with DERs -- -- -- -- (15.1 ) -- (15.1 ) Cash distributions paid to noncontrolling interests -- (9.6 ) (40.6 ) (50.2 ) -- 1.0 (49.2 ) Cash contributions from noncontrolling interests -- 0.1 0.3 0.4 -- -- 0.4 Net cash proceeds from issuance of common units -- -- -- -- 1,073.4 -- 1,073.4 Cash contributions from owners 1,060.5 1,900.0 (1,900.0 ) 1,060.5 -- (1,060.5 ) -- Other financing activities 6.8 -- -- 6.8 (29.6 ) -- (22.8 ) Cash provided by (used in) financing activities (1,617.5 ) 825.1 (909.0 ) (1,701.4 ) (2,541.2 ) 2,515.1 (1,727.5 ) Net change in cash, cash equivalents and restricted cash (301.0 ) (27.4 ) (18.9 ) (347.3 ) -- -- (347.3 ) Cash, cash equivalents and restricted cash, January 1 366.2 58.9 (7.5 ) 417.6 -- -- 417.6 Cash, cash equivalents and restricted cash, December 31 $ 65.2 $ 31.5 $ (26.4 ) $ 70.3 $ -- $ -- $ 70.3 Enterprise Products Partners L.P. Condensed Consolidating Statement of Cash Flows For the Year Ended December 31, 2016 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 $ 2,536.2 $ 2,891.1 $ (2,845.4 ) $ 2,581.9 $ 2,513.1 $ (2,542.0 ) $ 2,553.0 Reconciliation of net income to net cash flows provided by operating activities: Depreciation, amortization and accretion 185.4 1,367.0 (0.4 ) 1,552.0 -- -- 1,552.0 Equity in income of unconsolidated affiliates (2,686.1 ) (521.7 ) 2,845.8 (362.0 ) (2,539.9 ) 2,539.9 (362.0 ) Distributions received on earnings from unconsolidated affiliates 1,127.3 265.9 (1,012.7 ) 380.5 3,331.2 (3,331.2 ) 380.5 Net effect of changes in operating accounts and other operating activities 2,448.6 (2,568.5 ) 43.1 (76.8 ) 18.9 1.2 (56.7 ) Net cash flows provided by operating activities 3,611.4 1,433.8 (969.6 ) 4,075.6 3,323.3 (3,332.1 ) 4,066.8 Investing activities: Capital expenditures, net of contributions in aid of construction costs (1,327.4 ) (1,656.7 ) -- (2,984.1 ) -- -- (2,984.1 ) Cash used for business combinations, net of cash received -- (1,000.0 ) -- (1,000.0 ) -- -- (1,000.0 ) Proceeds from asset sales 28.8 17.7 -- 46.5 -- -- 46.5 Other investing activities (2,301.9 ) (63.2 ) 2,296.9 (68.2 ) (2,530.9 ) 2,530.9 (68.2 ) Cash used in investing activities (3,600.5 ) (2,702.2 ) 2,296.9 (4,005.8 ) (2,530.9 ) 2,530.9 (4,005.8 ) Financing activities: Borrowings under debt agreements 62,813.9 41.8 (41.8 ) 62,813.9 -- -- 62,813.9 Repayments of debt (61,672.5 ) (0.1 ) -- (61,672.6 ) -- -- (61,672.6 ) Cash distributions paid to partners (3,331.2 ) (1,089.6 ) 1,089.6 (3,331.2 ) (3,300.5 ) 3,331.2 (3,300.5 ) Cash payments made in connection with DERs -- -- -- -- (11.7 ) -- (11.7 ) Cash distributions paid to noncontrolling interests -- (8.5 ) (39.8 ) (48.3 ) -- 0.9 (47.4 ) Cash contributions from noncontrolling interests -- 20.4 -- 20.4 -- -- 20.4 Net cash proceeds from issuance of common units -- -- -- -- 2,542.8 -- 2,542.8 Cash contributions from owners 2,530.9 2,292.2 (2,292.2 ) 2,530.9 -- (2,530.9 ) -- Other financing activities (0.2 ) -- -- (0.2 ) (23.0 ) -- (23.2 ) Cash provided by (used in) financing activities 340.9 1,256.2 (1,284.2 ) 312.9 (792.4 ) 801.2 321.7 Net change in cash, cash equivalents and restricted cash 351.8 (12.2 ) 43.1 382.7 -- -- 382.7 Cash, cash equivalents and restricted cash, January 1 14.4 71.1 (50.6 ) 34.9 -- -- 34.9 Cash, cash equivalents and restricted cash, December 31 $ 366.2 $ 58.9 $ (7.5 ) $ 417.6 $ -- $ -- $ 417.6 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 on earnings 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 1,531.3 77.3 -- 1,608.6 -- -- 1,608.6 Other investing activities (1,499.0 ) (1,246.7 ) 2,579.3 (166.4 ) (1,179.8 ) 1,179.8 (166.4 ) Cash used in investing activities (2,217.6 ) (3,787.6 ) 2,579.3 (3,425.9 ) (1,179.8 ) 1,179.8 (3,425.9 ) 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, cash equivalents and restricted cash (4.3 ) 0.7 (35.9 ) (39.5 ) -- -- (39.5 ) Cash, cash equivalents and restricted cash, January 1 18.7 70.4 (14.7 ) 74.4 -- -- 74.4 Cash, cash equivalents and restricted cash, December 31 $ 14.4 $ 71.1 $ (50.6 ) $ 34.9 $ -- $ -- $ 34.9

Partnership Operations, Organ50

Partnership Operations, Organization and Basis of Presentation (Details) bbl in Millions	12 Months Ended
	Dec. 31, 2017SegmentmibblBcf	Dec. 31, 2014
Related Party Transaction [Line Items]
Number of miles of pipelines | mi	50,000
Number of barrels of storage capacity | bbl	260
Number of cubic feet of storage capacity | Bcf	14
Number of reportable segments | Segment	4
Limited partners ownership interest	100.00%
EPCO and its privately held affiliates [Member]
Related Party Transaction [Line Items]
Percentage of Total Units Outstanding	32.00%
Oiltanking Partners L.P. [Member]
Business Acquisition [Line Items]
Limited partner interests acquired		65.90%

Summary of Significant Accoun51

Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash, Cash Equivalents and Restricted Cash:
Cash and cash equivalents	$ 5.1	$ 63.1
Restricted cash	65.2	354.5
Total cash, cash equivalents and restricted cash shown in the Statements of Consolidated Cash Flows	70.3	417.6	$ 34.9	$ 74.4
Scenario, Previously Reported [Member]
Cash, Cash Equivalents and Restricted Cash:
Decrease in restricted cash		(338.6)	(15.9)
Allowance for Doubtful Accounts [Member]
Movement in valuation allowances and reserves [Roll Forward]
Balance at beginning of period	11.3	12.1	13.9
Charged to costs and expenses	2.7	2.3	0.8
Deductions	(1.9)	(3.1)	(2.6)
Balance at end of period	$ 12.1	$ 11.3	$ 12.1
Minor Investment [Member] | Minimum [Member]
Consolidation Policy [Abstract]
Equity method of ownership interest	3.00%
Minor Investment [Member] | Maximum [Member]
Consolidation Policy [Abstract]
Equity method of ownership interest	50.00%
Major Investment [Member] | Minimum [Member]
Consolidation Policy [Abstract]
Equity method of ownership interest	20.00%
Major Investment [Member] | Maximum [Member]
Consolidation Policy [Abstract]
Equity method of ownership interest	50.00%
Initial Margin Requirement [Member]
Cash, Cash Equivalents and Restricted Cash:
Restricted cash	$ 33.4
Variation Margin Requirement [Member]
Cash, Cash Equivalents and Restricted Cash:
Restricted cash	$ 31.8

Summary of Significant Accoun52

Summary of Significant Accounting Policies, Part 2 (Details)	12 Months Ended
	Dec. 31, 2017
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	5.00%
Minimum [Member]
Derivative Instruments [Abstract]
Expected offset percentage of change in fair value derivative instrument	80.00%
Maximum [Member]
Derivative Instruments [Abstract]
Expected offset percentage of change in fair value derivative instrument	125.00%

Summary of Significant Accoun53

Summary of Significant Accounting Policies, Part 3 (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Environmental Costs [Abstract]
Environmental reserves - current portion	$ 5.6	$ 5.6
Environmental Reserves [Member]
Movement in valuation allowances and reserves [Roll Forward]
Balance at beginning of period	11.9	13	$ 15.6
Charged to costs and expenses	12.1	7	6.4
Acquisition-related additions and other	1.7	0.5	1.1
Deductions	(14.1)	(8.6)	(10.1)
Balance at end of period	$ 11.6	$ 11.9	$ 13
Minimum [Member]
Impairment Testing for Goodwill [Abstract]
Reporting unit, percentage of fair value in excess of carrying amount	10.00%
Accounting Standards Update 2014-09 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Percent	1.00%

Revenue Recognition (Details)

Revenue Recognition (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Consolidated Revenues [Abstract]
Total consolidated revenues	$ 8,426.6	$ 6,886.9	$ 6,607.6	$ 7,320.4	$ 6,478.8	$ 5,920.4	$ 5,617.8	$ 5,005.3	$ 29,241.5	$ 23,022.3	$ 27,027.9
NGL Pipelines & Services [Member]
Consolidated Revenues [Abstract]
Sales of NGLs and related products									10,521.3	8,380.5	8,044.8
Midstream services									1,946.7	1,862	1,743.2
Total consolidated revenues									12,468	10,242.5	9,788
Crude Oil Pipelines & Services [Member]
Consolidated Revenues [Abstract]
Sales of crude oil									7,365.2	5,802.5	9,732.9
Midstream services									791.6	712.5	573
Total consolidated revenues									8,156.8	6,515	10,305.9
Natural Gas Pipelines & Services [Member]
Consolidated Revenues [Abstract]
Sales of natural gas									2,238.5	1,591.9	1,722.6
Midstream services									907.1	951.1	1,020.7
Total consolidated revenues									3,145.6	2,543	2,743.3
Petrochemical & Refined Products Services [Member]
Consolidated Revenues [Abstract]
Sales of petrochemicals and refined products									4,696.3	2,921.9	3,333.5
Midstream services									774.8	799.9	778.4
Total consolidated revenues									5,471.1	3,721.8	4,111.9
Offshore Pipelines And Services [Member]
Consolidated Revenues [Abstract]
Sales of crude oil									0	0	3.2
Midstream services									0	0	75.6
Total consolidated revenues									$ 0	$ 0	$ 78.8

Inventories (Details)

Inventories (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Inventory by Product Type [Abstract]
NGLs		$ 917.4	$ 1,156.1
Petrochemicals and refined products		161.5	220.7
Crude oil		516.3	360
Natural gas		14.6	33.7
Total		1,609.8	1,770.5
Summary of cost of sales and lower of cost or net realizable value adjustments [Abstract]
Cost of sales	[1]	21,487	15,710.9	$ 19,612.9
Lower of cost or net realizable value adjustments within cost of sales		$ 9.1	$ 11.5	$ 19.8
[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.

Property, Plant and Equipment56

Property, Plant and Equipment (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Property, plant and equipment and accumulated depreciation [Abstract]
Property, plant and equipment, gross		$ 46,545.2	$ 43,003.3
Less accumulated depreciation		10,924.8	9,710.8
Property, plant and equipment, net		35,620.4	33,292.5	$ 32,034.7
Summary of depreciation expense and capitalized interest [Abstract]
Depreciation expense	[1]	1,296.1	1,215.7	1,161.6
Capitalized interest	[2]	192.1	168.2	149.1
Asset Retirement Obligations [Roll Forward]
ARO liability beginning balance		85.4	58.5	98.3
Liabilities incurred		4.7	4.2	2.7
Liabilities settled		(2.2)	(5.7)	(6.3)
Revisions in estimated cash flows		(6.7)	24.6	49.7
Accretion expense		5.5	3.8	5.2
AROs related to Offshore Business sold in July 2015		0	0	(91.1)
ARO liability ending balance		86.7	85.4	$ 58.5
Capitalized costs, asset retirement costs		39.9	44.9
Forecasted accretion expense [Abstract]
2,018		5.8
2,019		6.2
2,020		6.5
2,021		6.9
2,022		7.3
Plants, pipelines and facilities [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Property, plant and equipment, gross	[3]	$ 37,132.2	35,124.6
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]	$ 3,460.9	3,326.9
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
Transportation equipment [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Property, plant and equipment, gross	[7]	$ 177.1	165.8
Transportation equipment [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life	[7]	3 years
Transportation equipment [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life	[7]	10 years
Marine vessels [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Property, plant and equipment, gross	[8]	$ 803.8	800.7
Marine vessels [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life	[8]	15 years
Marine vessels [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life	[8]	30 years
Land [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Property, plant and equipment, gross		$ 273.1	264.6
Construction in progress [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Property, plant and equipment, gross		$ 4,698.1	$ 3,320.7
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]	Transportation equipment includes tractor-trailer tank trucks and other vehicles and similar assets used in our operations.
[8]	Marine vessels include tow boats, barges and related equipment used in our marine transportation business.

Investments in Unconsolidated57

Investments in Unconsolidated Affiliates (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Schedule of Equity Method Investments [Line Items]
Investments in unconsolidated affiliates		$ 2,659.4	$ 2,677.3	$ 2,628.5
Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]
Equity in income (loss) of unconsolidated affiliates		426	362	373.6
Unamortized excess cost amounts by business segment:
Unamortized excess cost amounts		42.9	45.2
Equity method investment amortization of excess cost		2.1	2.1	4.9
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
Forecasted amortization of excess cost amounts - 2021		2.2
Forecasted amortization of excess cost amounts - 2022		2.2
Balance Sheet Data:
Current assets		288.8	199.5
Property, plant and equipment, net		5,509.7	5,644.4
Other assets		71.2	61.5
Total assets		5,869.7	5,905.4
Current liabilities		233.5	208.5
Other liabilities		84.8	112.3
Combined equity		5,551.4	5,584.6
Total liabilities and combined equity		5,869.7	5,905.4
Income Statement Data:
Revenues		1,509	1,342	1,426.6
Operating income		925.9	786.7	825.8
Net income		929.5	781.7	814.1
NGL Pipelines & Services [Member]
Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]
Equity in income (loss) of unconsolidated affiliates		73.4	61.4	57.5
Unamortized excess cost amounts by business segment:
Unamortized excess cost amounts		$ 22.9	24.1
NGL Pipelines & Services [Member] | Venice Energy Service Company, L.L.C. [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest		13.10%
Investments in unconsolidated affiliates		$ 25.7	24.8
NGL Pipelines & Services [Member] | K/D/S Promix, L.L.C. [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest		50.00%
Investments in unconsolidated affiliates		$ 30.9	33.7
NGL Pipelines & Services [Member] | Baton Rouge Fractionators LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest		32.20%
Investments in unconsolidated affiliates		$ 17	17.3
NGL Pipelines & Services [Member] | Skelly-Belvieu Pipeline Company, L.L.C. [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest		50.00%
Investments in unconsolidated affiliates		$ 37	38.9
NGL Pipelines & Services [Member] | Texas Express Pipeline LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest		35.00%
Investments in unconsolidated affiliates		$ 314.4	331.9
NGL Pipelines & Services [Member] | Texas Express Gathering LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest		45.00%
Investments in unconsolidated affiliates		$ 35.9	35.8
NGL Pipelines & Services [Member] | Front Range Pipeline LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest		33.30%
Investments in unconsolidated affiliates		$ 165.7	165.4
NGL Pipelines & Services [Member] | Delaware Basin Gas Processing LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest		50.00%
Investments in unconsolidated affiliates		$ 107.3	102.6
Crude Oil Pipelines & Services [Member]
Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]
Equity in income (loss) of unconsolidated affiliates		358.4	311.9	281.4
Unamortized excess cost amounts by business segment:
Unamortized excess cost amounts		$ 18.2	19
Crude Oil Pipelines & Services [Member] | Seaway Crude Pipeline Company LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest		50.00%
Investments in unconsolidated affiliates		$ 1,378.9	1,393.8
Crude Oil Pipelines & Services [Member] | Eagle Ford Pipeline LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest		50.00%
Investments in unconsolidated affiliates		$ 385.2	377.9
Crude Oil Pipelines & Services [Member] | Eagle Ford Terminals Corpus Christi LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest		50.00%
Investments in unconsolidated affiliates		$ 75.1	52.9
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	3.8	3.8
Natural Gas Pipelines & Services [Member] | White River Hub, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest		50.00%
Investments in unconsolidated affiliates		$ 20.8	21.7
Petrochemical & Refined Products Services [Member]
Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]
Equity in income (loss) of unconsolidated affiliates	[1]	(9.6)	(15.1)	(15.7)
Unamortized excess cost amounts by business segment:
Unamortized excess cost amounts		$ 1.8	2.1
Petrochemical & Refined Products Services [Member] | Centennial Pipeline LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest		50.00%
Investments in unconsolidated affiliates		$ 60.8	62.3
Petrochemical & Refined Products Services [Member] | Other Unconsolidated Affiliates [Member]
Schedule of Equity Method Investments [Line Items]
Investments in unconsolidated affiliates		4.7	18.3
Offshore Pipelines & Services [Member]
Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]
Equity in income (loss) of unconsolidated affiliates		$ 0	$ 0	$ 46.6	[2]
[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 market and income approaches, indicate that the fair value of this investment remains in excess of its carrying value.
[2]	Our investments in unconsolidated affiliates classified within the Offshore Pipelines & Services segment were sold in July 2015 (see Note 10).

Investments in Unconsolidated58

Investments in Unconsolidated Affiliates, Descriptions (Details)	12 Months Ended
	Dec. 31, 2017
NGL Pipelines & Services [Member] | Venice Energy Service Company, L.L.C. [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Description of Principal Activities	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.
NGL Pipelines & Services [Member] | K/D/S Promix, L.L.C. [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Description of Principal Activities	Promix owns an NGL fractionation facility 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.
NGL Pipelines & Services [Member] | Baton Rouge Fractionators LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Description of Principal Activities	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. In addition, BRF leases an NGL storage cavern.
NGL Pipelines & Services [Member] | Skelly-Belvieu Pipeline Company, L.L.C. [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Description of Principal Activities	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.
NGL Pipelines & Services [Member] | Texas Express Pipeline LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Description of Principal Activities	Texas Express owns an NGL pipeline that extends from Skellytown to our NGL fractionation and storage complex in Mont Belvieu. 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.
NGL Pipelines & Services [Member] | Texas Express Gathering LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Description of Principal Activities	TEG owns two NGL gathering systems that deliver mixed NGLs to the Texas Express Pipeline. 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.
NGL Pipelines & Services [Member] | Front Range Pipeline LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Description of Principal Activities	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 and other third party facilities in Skellytown.
NGL Pipelines & Services [Member] | Delaware Basin Gas Processing LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Description of Principal Activities	Delaware Processing, which commenced operations in August 2016, was formed with Occidental Petroleum Corporation to plan, design and construct a new 150 million cubic feet per day (“MMcf/d”) cryogenic natural gas processing plant to accommodate the growing production of NGL-rich natural gas in the Delaware Basin, in West Texas and southern New Mexico. The facility, located in Reeves County, Texas, is supported by long-term, firm contracts. We served as construction manager for the project and serve as operator of the new facility.
Crude Oil Pipelines & Services [Member] | Seaway Crude Pipeline Company LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Description of Principal Activities	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, which consists of two pipelines, provides north-to-south transportation of crude oil from the Cushing hub to Seaway’s Jones Creek terminal near Freeport, Texas and a terminal that we own located near Katy, Texas. The second of these two pipelines is referred to as the “Seaway Loop.” The Freeport System consists of a marine import and export dock, three pipelines and other related facilities that transport crude oil to and from Freeport and the Jones Creek terminal. The Texas City System consists of a marine import and export dock, storage tanks, various pipelines and other related facilities that transport crude oil to refineries in the Texas City, Texas area and to and from terminals in the Galena Park area, our Enterprise Crude Houston (“ECHO”) terminal and locations along the Houston Ship Channel. The Texas City System also receives production from certain offshore Gulf of Mexico developments.
Crude Oil Pipelines & Services [Member] | Eagle Ford Pipeline LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Description of Principal Activities	Eagle Ford Crude Oil Pipeline owns a crude oil pipeline that transports crude oil and condensate for producers in South Texas. The system consists of a crude oil and condensate pipeline system originating in Gardendale, Texas in LaSalle County to Three Rivers, Texas in Live Oak County and extending to Corpus Christi, Texas. The system also includes a pipeline segment that interconnects 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.
Crude Oil Pipelines & Services [Member] | Eagle Ford Terminals Corpus Christi LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Description of Principal Activities	Eagle Ford Corpus Christi is a joint venture formed in March 2015 to construct and operate a new deep-water marine crude oil terminal that is designed to handle a variety of ocean-going vessels. The new terminal is expected to be placed into service during the third quarter of 2018.
Natural Gas Pipelines & Services [Member] | White River Hub, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Description of Principal Activities	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 [Member] | Baton Rouge Propylene Concentrator, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Description of Principal Activities	BRPC owns a propylene fractionation facility located in south Louisiana that fractionates refinery grade propylene into chemical grade propylene.
Petrochemical & Refined Products Services [Member] | Centennial Pipeline LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Description of Principal Activities	Centennial owns an interstate refined products pipeline that extends from Beaumont, Texas, to Bourbon, Illinois. Centennial also owns a refined products storage terminal located near Creal Springs, Illinois.

Intangible Assets and Goodwill,

Intangible Assets and Goodwill, Intangible Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Identifiable intangible assets [Abstract]
Gross Value	$ 5,255.1	$ 5,267.2
Accumulated Amortization	(1,564.8)	(1,403.1)
Carrying Value	3,690.3	3,864.1	$ 4,037.2
Amortization expense	166.9	171.3	174.1
Forecasted amortization expense [Abstract]
2,018	174.5
2,019	165.8
2,020	150.7
2,021	145.6
2,022	141.6
Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Carrying Value	3,410
Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Carrying Value	285.2
NGL Pipelines & Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	728.2	727.3
Accumulated Amortization	(405.9)	(377.1)
Carrying Value	322.3	350.2
Amortization expense	28.9	30.6	33.6
NGL Pipelines & Services [Member] | Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	447.4	447.4
Accumulated Amortization	(187.5)	(172.7)
Carrying Value	259.9	274.7
NGL Pipelines & Services [Member] | Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	280.8	279.9
Accumulated Amortization	(218.4)	(204.4)
Carrying Value	62.4	75.5
Crude Oil Pipelines & Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	2,484.5	2,485.4
Accumulated Amortization	(298)	(206.4)
Carrying Value	2,186.5	2,279
Amortization expense	92.5	98.4	87.1
Crude Oil Pipelines & Services [Member] | Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	2,203.5	2,204.4
Accumulated Amortization	(127)	(84.5)
Carrying Value	2,076.5	2,119.9
Crude Oil Pipelines & Services [Member] | Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	281	281
Accumulated Amortization	(171)	(121.9)
Carrying Value	110	159.1
Natural Gas Pipelines & Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	1,815	1,815
Accumulated Amortization	(796.6)	(760.5)
Carrying Value	1,018.4	1,054.5
Amortization expense	36.2	33.2	40
Natural Gas Pipelines & Services [Member] | Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	1,350.3	1,350.3
Accumulated Amortization	(417.1)	(390)
Carrying Value	933.2	960.3
Natural Gas Pipelines & Services [Member] | Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	464.7	464.7
Accumulated Amortization	(379.5)	(370.5)
Carrying Value	85.2	94.2
Petrochemical & Refined Products Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	227.4	239.5
Accumulated Amortization	(64.3)	(59.1)
Carrying Value	163.1	180.4
Amortization expense	9.3	9.1	8.9
Petrochemical & Refined Products Services [Member] | Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	181.4	185.5
Accumulated Amortization	(45.9)	(43.9)
Carrying Value	135.5	141.6
Petrochemical & Refined Products Services [Member] | Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	46	54
Accumulated Amortization	(18.4)	(15.2)
Carrying Value	27.6	38.8
Offshore Pipelines & Services [Member]
Identifiable intangible assets [Abstract]
Amortization expense	$ 0	$ 0	$ 4.5

Intangible Assets and Goodwil60

Intangible Assets and Goodwill, Significant Intangible Assets (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Identifiable intangible assets [Abstract]
Gross Value		$ 5,255.1	$ 5,267.2
Accumulated Amortization		(1,564.8)	(1,403.1)
Carrying Value		3,690.3	$ 3,864.1	$ 4,037.2
Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Carrying Value		3,410
Customer relationship intangibles [Member] | EFS Midstream [Member]
Identifiable intangible assets [Abstract]
Gross Value	[1]	1,409.8
Accumulated Amortization	[1]	(88.8)
Carrying Value	[1]	$ 1,321
Weighted Average Remaining Amortization Period	[1]	24 years 4 months 24 days
Cash flow projections discount rate		15.00%
Customer relationship intangibles [Member] | State Line and Fairplay [Member]
Identifiable intangible assets [Abstract]
Gross Value	[2]	$ 895
Accumulated Amortization	[2]	(164.7)
Carrying Value	[2]	$ 730.3
Weighted Average Remaining Amortization Period	[2]	29 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]	(218)
Carrying Value	[3]	$ 113.3
Weighted Average Remaining Amortization Period	[3]	21 years 9 months 18 days
Customer relationship intangibles [Member] | Encinal [Member]
Identifiable intangible assets [Abstract]
Gross Value	[4]	$ 132.9
Accumulated Amortization	[4]	(98.4)
Carrying Value	[4]	$ 34.5
Weighted Average Remaining Amortization Period	[4]	9 years
Customer relationship intangibles [Member] | Oiltanking Partners L.P. [Member]
Identifiable intangible assets [Abstract]
Gross Value	[5]	$ 1,192.5
Accumulated Amortization	[5]	(57.1)
Carrying Value	[5]	$ 1,135.4
Weighted Average Remaining Amortization Period	[5]	26 years
Cash flow projections discount rate		6.50%
Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Carrying Value		$ 285.2
Contract-based intangibles [Member] | Oiltanking Partners L.P. [Member]
Identifiable intangible assets [Abstract]
Gross Value		297.4
Carrying Value		$ 118.7
Weighted Average Remaining Amortization Period		4 years 2 months 12 days
Contract-based intangibles [Member] | Jonah Gas Gathering [Member]
Identifiable intangible assets [Abstract]
Carrying Value		$ 63.9
Weighted Average Remaining Amortization Period		24 years
[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 formation in Louisiana and eastern Texas. The Fairplay system serves producers in the Cotton Valley formation 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 Goodwil61

Intangible Assets and Goodwill, Goodwill (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Changes in carrying amount of goodwill [Roll Forward]
Balance at beginning of period	$ 4,300.2
Reclassification of Oiltanking IDR balances to goodwill in connection with the cancellation of such rights and other adjustments	1,454.1
Reduction in goodwill related to the sale of assets	(84.1)
Addition to goodwill related to the acquisition of EFS Midstream	82.6
Goodwill reclassified to assets held-for-sale	(7.6)
Balance at end of period	5,745.2
Oiltanking Partners L.P. [Member]
Changes in carrying amount of goodwill [Roll Forward]
Reclassification of Oiltanking IDR balances to goodwill in connection with the cancellation of such rights and other adjustments	1,450
Balance at end of period	3,670
EFS Midstream [Member]
Changes in carrying amount of goodwill [Roll Forward]
Addition to goodwill related to the acquisition of EFS Midstream	82.6
NGL Pipelines & Services [Member]
Changes in carrying amount of goodwill [Roll Forward]
Balance at beginning of period	2,210.2
Reclassification of Oiltanking IDR balances to goodwill in connection with the cancellation of such rights and other adjustments	432.6
Reduction in goodwill related to the sale of assets	0
Addition to goodwill related to the acquisition of EFS Midstream	8.9
Goodwill reclassified to assets held-for-sale	0
Balance at end of period	2,651.7
Crude Oil Pipelines & Services [Member]
Changes in carrying amount of goodwill [Roll Forward]
Balance at beginning of period	918.7
Reclassification of Oiltanking IDR balances to goodwill in connection with the cancellation of such rights and other adjustments	850.7
Reduction in goodwill related to the sale of assets	(2.1)
Addition to goodwill related to the acquisition of EFS Midstream	73.7
Goodwill reclassified to assets held-for-sale	0
Balance at end of period	1,841
Natural Gas Pipelines & Services [Member]
Changes in carrying amount of goodwill [Roll Forward]
Balance at beginning of period	296.3
Reclassification of Oiltanking IDR balances to goodwill in connection with the cancellation of such rights and other adjustments	0
Reduction in goodwill related to the sale of assets	0
Addition to goodwill related to the acquisition of EFS Midstream	0
Goodwill reclassified to assets held-for-sale	0
Balance at end of period	296.3
Petrochemical & Refined Products Services [Member]
Changes in carrying amount of goodwill [Roll Forward]
Balance at beginning of period	793
Reclassification of Oiltanking IDR balances to goodwill in connection with the cancellation of such rights and other adjustments	170.8
Reduction in goodwill related to the sale of assets	0
Addition to goodwill related to the acquisition of EFS Midstream	0
Goodwill reclassified to assets held-for-sale	(7.6)
Balance at end of period	956.2
Offshore Pipelines & Services [Member]
Changes in carrying amount of goodwill [Roll Forward]
Balance at beginning of period	82
Reclassification of Oiltanking IDR balances to goodwill in connection with the cancellation of such rights and other adjustments	0
Reduction in goodwill related to the sale of assets	(82)
Addition to goodwill related to the acquisition of EFS Midstream	0
Goodwill reclassified to assets held-for-sale	0
Balance at end of period	$ 0

Debt Obligations (Details)

Debt Obligations (Details) - USD ($) $ in Millions		1 Months Ended		12 Months Ended
		Mar. 30, 2018	Aug. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jul. 31, 2016
Debt Instrument [Line Items]
Principal outstanding				$ 24,780.1	$ 23,901.6
Other, non-principal amounts				(211.4)	(203.9)
Less current maturities of debt				(2,855)	(2,576.8)
Total long-term debt				21,713.7	21,120.9
Debt Obligations Terms:
Repayment of debt obligations				68,459.6	61,672.6	$ 19,867.2
Letters of credit outstanding for facilities and motor fuel tax obligations				66.4
Senior Debt Obligations [Member]
Debt Instrument [Line Items]
Principal outstanding				21,605.7	22,427.2
Senior Debt Obligations [Member] | Commercial Paper Notes [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 1,755.7	1,777.2
Debt Obligations Terms:
Interest rate terms				variable
Maximum borrowing capacity				$ 2,500
Repayment of debt obligations			$ 900
Information regarding variable interest rates paid:
Weighted-average interest rate paid				1.34%
Senior Debt Obligations [Member] | Commercial Paper Notes [Member] | Minimum [Member]
Information regarding variable interest rates paid:
Variable interest rates paid				0.90%
Senior Debt Obligations [Member] | Commercial Paper Notes [Member] | Maximum [Member]
Information regarding variable interest rates paid:
Variable interest rates paid				1.80%
Senior Debt Obligations [Member] | EPO Senior Notes L [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 0	800
Debt Obligations Terms:
Interest rate terms				fixed
Interest rate, stated percentage				6.30%
Maturity date				Sep. 15, 2017
Repayment of debt obligations				$ 800
Senior Debt Obligations [Member] | EPO Senior Notes V [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 349.7	349.7
Debt Obligations Terms:
Interest rate terms				fixed
Interest rate, stated percentage				6.65%
Maturity date				Apr. 15, 2018
Senior Debt Obligations [Member] | EPO Senior Notes OO [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 750	750
Debt Obligations Terms:
Interest rate terms				fixed
Interest rate, stated percentage				1.65%
Maturity date				May 7, 2018
Senior Debt Obligations [Member] | EPO 364-Day Revolving Credit Agreement [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 0	0
Debt Obligations Terms:
Interest rate terms				variable
Maturity date				Sep. 12, 2018
Maximum borrowing capacity				$ 1,500
Maximum bank commitments increase				200
Total maximum borrowing capacity				1,700
Senior Debt Obligations [Member] | EPO Senior Notes N [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 700	700
Debt Obligations Terms:
Interest rate terms				fixed
Interest rate, stated percentage				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:
Interest rate terms				fixed
Interest rate, stated percentage				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:
Interest rate terms				fixed
Interest rate, stated percentage				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:
Interest rate terms				fixed
Interest rate, stated percentage				5.20%
Maturity date				Sep. 1, 2020
Senior Debt Obligations [Member] | EPO Senior Notes RR [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 575	575
Debt Obligations Terms:
Interest rate terms				fixed
Interest rate, stated percentage				2.85%
Maturity date				Apr. 15, 2021
Senior Debt Obligations [Member] | EPO Senior Notes CC [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 650	650
Debt Obligations Terms:
Interest rate terms				fixed
Interest rate, stated percentage				4.05%
Maturity date				Feb. 15, 2022
Senior Debt Obligations [Member] | EPO Multi-Year Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 0	0
Debt Obligations Terms:
Interest rate terms				variable
Maturity date				Sep. 13, 2022
Maximum borrowing capacity				$ 4,000
Maximum bank commitments increase				500
Total maximum borrowing capacity				$ 4,500
Information regarding variable interest rates paid:
Weighted-average interest rate paid				2.23%
Senior Debt Obligations [Member] | EPO Multi-Year Revolving Credit Facility [Member] | Minimum [Member]
Information regarding variable interest rates paid:
Variable interest rates paid				2.23%
Senior Debt Obligations [Member] | EPO Multi-Year Revolving Credit Facility [Member] | Maximum [Member]
Information regarding variable interest rates paid:
Variable interest rates paid				2.23%
Senior Debt Obligations [Member] | EPO Senior Notes HH [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 1,250	1,250
Debt Obligations Terms:
Interest rate terms				fixed
Interest rate, stated percentage				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:
Interest rate terms				fixed
Interest rate, stated percentage				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:
Interest rate terms				fixed
Interest rate, stated percentage				3.75%
Maturity date				Feb. 15, 2025
Senior Debt Obligations [Member] | EPO Senior Notes PP [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 875	875
Debt Obligations Terms:
Interest rate terms				fixed
Interest rate, stated percentage				3.70%
Maturity date				Feb. 15, 2026
Senior Debt Obligations [Member] | EPO Senior Notes SS [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 575	575
Debt Obligations Terms:
Interest rate terms				fixed
Interest rate, stated percentage				3.95%
Maturity date				Feb. 15, 2027
Senior Debt Obligations [Member] | EPO Senior Notes D [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 500	500
Debt Obligations Terms:
Interest rate terms				fixed
Interest rate, stated percentage				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:
Interest rate terms				fixed
Interest rate, stated percentage				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:
Interest rate terms				fixed
Interest rate, stated percentage				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:
Interest rate terms				fixed
Interest rate, stated percentage				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:
Interest rate terms				fixed
Interest rate, stated percentage				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:
Interest rate terms				fixed
Interest rate, stated percentage				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:
Interest rate terms				fixed
Interest rate, stated percentage				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:
Interest rate terms				fixed
Interest rate, stated percentage				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:
Interest rate terms				fixed
Interest rate, stated percentage				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:
Interest rate terms				fixed
Interest rate, stated percentage				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:
Interest rate terms				fixed
Interest rate, stated percentage				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:
Interest rate terms				fixed
Interest rate, stated percentage				5.10%
Maturity date				Feb. 15, 2045
Senior Debt Obligations [Member] | EPO Senior Notes QQ [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 975	975
Debt Obligations Terms:
Interest rate terms				fixed
Interest rate, stated percentage				4.90%
Maturity date				May 15, 2046
Senior Debt Obligations [Member] | EPO Senior Notes NN [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 400	400
Debt Obligations Terms:
Interest rate terms				fixed
Interest rate, stated percentage				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:
Interest rate terms				fixed
Interest rate, stated percentage				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:
Interest rate terms				fixed
Interest rate, stated percentage				7.55%
Maturity date				Apr. 15, 2038
Junior Debt Obligations [Member]
Debt Obligations Terms:
Aggregate debt principal issued				$ 1,700
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes A [Member]
Debt Instrument [Line Items]
Principal outstanding	[1]			$ 521.1	521.1
Debt Obligations Terms:
Interest rate terms				variable
Interest rate, stated percentage	[2]						8.375%
Maturity date				Aug. 31, 2066
Variable annual interest rate thereafter, variable rate basis	[3]			3-month LIBOR
Variable interest rate	[3]			3.708%
Information regarding variable interest rates paid:
Weighted-average interest rate paid				4.89%
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes A [Member] | Minimum [Member]
Information regarding variable interest rates paid:
Variable interest rates paid				4.59%
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes A [Member] | Maximum [Member]
Information regarding variable interest rates paid:
Variable interest rates paid				5.08%
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes C [Member]
Debt Instrument [Line Items]
Principal outstanding	[4]			$ 256.4	256.4
Debt Obligations Terms:
Interest rate terms				fixed/variable
Interest rate, stated percentage	[5]			7.00%
Maturity date				Jun. 1, 2067
Variable annual interest rate thereafter, variable rate basis	[6]			3-month LIBOR
Variable interest rate	[6]			2.778%
Information regarding variable interest rates paid:
Weighted-average interest rate paid				4.07%
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes C [Member] | Minimum [Member]
Information regarding variable interest rates paid:
Variable interest rates paid				3.98%
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes C [Member] | Maximum [Member]
Information regarding variable interest rates paid:
Variable interest rates paid				4.26%
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes B [Member]
Debt Instrument [Line Items]
Principal outstanding	[7]			$ 682.7	682.7
Debt Obligations Terms:
Interest rate terms				fixed/variable
Interest rate, stated percentage	[8]			7.034%
Maturity date				Jan. 15, 2068
Variable annual interest rate thereafter, variable rate basis	[9]			3-month LIBOR
Variable interest rate	[9]			2.68%
Minimum variable annual interest rate	[9]			7.034%
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes B [Member] | Forecast [Member]
Debt Obligations Terms:
Repayment of debt obligations		$ 682.7
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes D [Member]
Debt Instrument [Line Items]
Principal outstanding	[10]			$ 700	0
Debt Obligations Terms:
Interest rate terms				fixed/variable
Interest rate, stated percentage	[11]			4.875%
Maturity date				Aug. 16, 2077
Aggregate debt principal issued				$ 700
Debt issued as percent of principal amount				100.00%
Variable annual interest rate thereafter, variable rate basis	[12]			3-month LIBOR
Variable interest rate	[12]			2.986%
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes E [Member]
Debt Instrument [Line Items]
Principal outstanding	[13]			$ 1,000	0
Debt Obligations Terms:
Interest rate terms				fixed/variable
Interest rate, stated percentage	[11]			5.25%
Maturity date				Aug. 16, 2077
Aggregate debt principal issued				$ 1,000
Debt issued as percent of principal amount				100.00%
Variable annual interest rate thereafter, variable rate basis	[14]			3-month LIBOR
Variable interest rate	[14]			3.033%
Junior Debt Obligations [Member] | TEPPCO Junior Subordinated Notes [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 14.2	14.2
Debt Obligations Terms:
Interest rate terms				fixed/variable
Maturity date				Jun. 1, 2067
Senior Notes [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 19,850
Debt Obligations Terms:
Aggregate debt principal issued					$ 1,250	$ 2,500
[1]	Variable rate is reset quarterly and 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, which commenced in November 2016.
[4]	Fixed rate of 7.000% through May 31, 2017; thereafter, a variable rate reset quarterly and 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, which commenced in September 2017.
[7]	Fixed rate of 7.034% through January 14, 2018; thereafter, the rate will be the greater of 7.034% or a variable rate reset quarterly and based on 3-month LIBOR plus 2.680%. These notes are expected to be redeemed in March 2018 (see Note 22).
[8]	Interest was payable semi-annually in arrears in January and July of each year, which commenced in January 2008.
[9]	Interest was payable quarterly in arrears in January, April, July and October of each year commencing in April 2018.
[10]	Fixed rate of 4.875% through August 15, 2022; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 2.986%.
[11]	Interest is payable semi-annually in arrears in February and August of each year, which commenced in February 2018.
[12]	Interest is payable quarterly in arrears in February, May, August and November of each year commencing in November 2022.
[13]	Fixed rate of 5.250% through August 15, 2027; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 3.033%.
[14]	Interest is payable quarterly in arrears in February, May, August and November of each year commencing in November 2027.

Debt Obligations, Debt Maturiti

Debt Obligations, Debt Maturities (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Scheduled Maturities of Debt [Abstract]
2,018	$ 2,855.7
2,019	1,500
2,020	1,500
2,021	575
2,022	650
Thereafter	17,699.4
Total	24,780.1	$ 23,901.6
Commercial Paper Notes [Member]
Scheduled Maturities of Debt [Abstract]
2,018	1,755.7
2,019	0
2,020	0
2,021	0
2,022	0
Thereafter	0
Total	1,755.7
Senior Notes [Member]
Scheduled Maturities of Debt [Abstract]
2,018	1,100
2,019	1,500
2,020	1,500
2,021	575
2,022	650
Thereafter	14,525
Total	19,850
Junior Subordinated Notes [Member]
Scheduled Maturities of Debt [Abstract]
2,018	0
2,019	0
2,020	0
2,021	0
2,022	0
Thereafter	3,174.4
Total	$ 3,174.4

Equity and Distributions, Summa

Equity and Distributions, Summary of Changes in Outstanding Units (Details) - shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Summary of changes in outstanding units [Roll Forward]
Common units issued in connection with employee compensation (in units)	1,176,103
Common Units (Unrestricted) [Member]
Summary of changes in outstanding units [Roll Forward]
Beginning Balance (in units)	2,116,906,120	2,010,592,504	1,933,095,027
Common units issued in connection with ATM program (in units)	21,807,726	87,867,037	25,520,424
Common units issued in connection with DRIP and EUPP (in units)	19,046,019	16,316,534	12,793,913
Common units issued in connection with Step 2 of Oiltanking acquisition (in units)			36,827,517
Common units issued in connection with the vesting and exercise of unit options (in units)			396,158
Common units issued in connection with the vesting of phantom unit awards (in units)	2,485,580	1,761,455	618,395
Common units issues in connection with the vesting of restricted common unit awards	681,044	1,234,502	2,009,970
Forfeiture of restricted common unit awards (in units)	0	0	0
Cancellation of treasury units acquired in connection with the vesting of equity-based awards (in units)	(1,027,798)	(1,000,619)	(683,954)
Common units issued in connection with employee compensation (in units)	1,176,103
Other (in units)	14,685	134,707	15,054
Ending Balance (in units)	2,161,089,479	2,116,906,120	2,010,592,504
Restricted Common Units [Member]
Summary of changes in outstanding units [Roll Forward]
Beginning Balance (in units)	682,294	1,960,520	4,229,790
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 Step 2 of Oiltanking acquisition (in units)			0
Common units issued in connection with the vesting and exercise of unit options (in units)			0
Common units issued in connection with the vesting of phantom unit awards (in units)	0	0	0
Common units issues in connection with the vesting of restricted common unit awards	(681,044)	(1,234,502)	(2,009,970)
Forfeiture of restricted common unit awards (in units)	(1,250)	(43,724)	(259,300)
Cancellation of treasury units acquired in connection with the vesting of equity-based awards (in units)	0	0	0
Common units issued in connection with employee compensation (in units)	0
Other (in units)	0	0	0
Ending Balance (in units)	0	682,294	1,960,520
Common Units [Member]
Summary of changes in outstanding units [Roll Forward]
Beginning Balance (in units)	2,117,588,414	2,012,553,024	1,937,324,817
Common units issued in connection with ATM program (in units)	21,807,726	87,867,037	25,520,424
Common units issued in connection with DRIP and EUPP (in units)	19,046,019	16,316,534	12,793,913
Common units issued in connection with Step 2 of Oiltanking acquisition (in units)			36,827,517
Common units issued in connection with the vesting and exercise of unit options (in units)			396,158
Common units issued in connection with the vesting of phantom unit awards (in units)	2,485,580	1,761,455	618,395
Common units issues in connection with the vesting of restricted common unit awards	0	0	0
Forfeiture of restricted common unit awards (in units)	(1,250)	(43,724)	(259,300)
Cancellation of treasury units acquired in connection with the vesting of equity-based awards (in units)	(1,027,798)	(1,000,619)	(683,954)
Common units issued in connection with employee compensation (in units)	1,176,103
Other (in units)	14,685	134,707	15,054
Ending Balance (in units)	2,161,089,479	2,117,588,414	2,012,553,024

Equity and Distributions, Issua

Equity and Distributions, Issuances of Equity (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Registration Statements and Equity Offerings [Line Items]
Common units issued in connection with acquisition of Oiltanking (in units)			36,827,517	54,807,352
Net Cash Proceeds from Sale of Common Units [Abstract]
Net cash proceeds from the issuance of common units	$ 1,073.4	$ 2,542.8	$ 1,188.6
Common units issued in connection with employee compensation (in units)	1,176,103
Common units issued in connection with employee compensation	$ 33.7
Restricted Common Unit Awards [Member]
Treasury Units:
Conversion of restricted units to common units (in units)	681,044
Acquisition of treasury units in connection with vesting of equity-based awards (in units)	229,910
Phantom Unit Awards [Member]
Treasury Units:
Acquisition of treasury units in connection with vesting of equity-based awards (in units)	797,888
Treasury Units [Member]
Treasury Units:
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	$ 29.5
Junior Debt Obligations [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Debt issued under universal shelf registration	1,700
Universal Shelf Registration [Member] | Senior Debt Obligations [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Debt issued under universal shelf registration		$ 1,250	$ 2,500
Universal Shelf Registration [Member] | Junior Debt Obligations [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Debt issued under universal shelf registration	1,700
At-the-Market Registration [Member]
Registration Statements and Equity Offerings [Line Items]
Maximum common units authorized for issuance	$ 2,540
Net Cash Proceeds from Sale of Common Units [Abstract]
Number of common units issued (in units)	21,807,726	87,867,037	25,520,424
Gross proceeds from the sale of common units	$ 603.1	$ 2,170	$ 825.4
Net cash proceeds from the issuance of common units	597	$ 2,160	$ 817.4
Remaining units available for issuance	$ 2,540
At-the-Market Registration [Member] | EPCO and its privately held affiliates [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Number of common units issued (in units)		3,830,256	3,225,057
Gross proceeds from the sale of common units		$ 100	$ 100
Distribution Reinvestment Plan [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Number of common units issued (in units)	18,541,355	15,809,503	12,413,351
Net cash proceeds from the issuance of common units	$ 462.9	$ 374	$ 359.8
Distribution reinvestment plan discount rate	2.50%
Remaining units available for issuance (in units)	80,717,140
Distribution Reinvestment Plan [Member] | Minimum [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Distribution reinvestment plan discount rate range	0.00%
Distribution Reinvestment Plan [Member] | Maximum [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Distribution reinvestment plan discount rate range	5.00%
Distribution Reinvestment Plan [Member] | EPCO and its privately held affiliates [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Number of common units issued (in units)	4,246,498
Gross proceeds from the sale of common units	$ 100	100	100
Net cash proceeds from the issuance of common units	$ 100	$ 100	$ 100
Employee Unit Purchase Plan [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Number of common units issued (in units)	504,664	507,031	380,562
Net cash proceeds from the issuance of common units	$ 13.5	$ 12.7	$ 11.4
Remaining units available for issuance (in units)	5,760,811

Equity and Distributions, Accum

Equity and Distributions, Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accumulated Other Comprehensive Income (Loss) [Abstract]
Beginning balance				$ (280)				$ (219.2)	$ (280)	$ (219.2)
Other comprehensive income (loss) before reclassifications									(44.3)	(151.6)
Amounts reclassified from accumulated other comprehensive loss									152.6	90.8
Total other comprehensive income (loss)									108.3	(60.8)	$ 22.4
Ending balance	$ (171.7)				$ (280)				(171.7)	(280)	(219.2)
Interest expense									984.6	982.6	961.8
Operating costs and expenses									25,557.5	19,643.5	23,668.7
Total	(797.3)	$ (621.3)	$ (666)	(771)	(669.7)	$ (643.1)	$ (570)	(670.2)	(2,855.6)	(2,553)	(2,558.4)
Gains (Losses) on Cash Flow Hedges [Member] | Commodity Derivatives [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Beginning balance				(83.8)				56.6	(83.8)	56.6
Other comprehensive income (loss) before reclassifications									(38.5)	(193.8)
Amounts reclassified from accumulated other comprehensive loss									112.2	53.4
Total other comprehensive income (loss)									73.7	(140.4)
Ending balance	(10.1)				(83.8)				(10.1)	(83.8)	56.6
Gains (Losses) on Cash Flow Hedges [Member] | Interest Rate Derivatives [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Beginning balance				(199.8)				(279.5)	(199.8)	(279.5)
Other comprehensive income (loss) before reclassifications									(5.7)	42.3
Amounts reclassified from accumulated other comprehensive loss									40.4	37.4
Total other comprehensive income (loss)									34.7	79.7
Ending balance	(165.1)				(199.8)				(165.1)	(199.8)	(279.5)
Other [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Beginning balance				$ 3.6				$ 3.7	3.6	3.7
Other comprehensive income (loss) before reclassifications									(0.1)	(0.1)
Amounts reclassified from accumulated other comprehensive loss									0	0
Total other comprehensive income (loss)									(0.1)	(0.1)
Ending balance	$ 3.5				$ 3.6				3.5	3.6	$ 3.7
Reclassification out of Accumulated Other Comprehensive Income (Loss) [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Total									152.6	90.8
Reclassification out of Accumulated Other Comprehensive Income (Loss) [Member] | Commodity Derivatives [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Revenue									111.6	53.6
Operating costs and expenses									0.6	(0.2)
Reclassification out of Accumulated Other Comprehensive Income (Loss) [Member] | Interest Rate Derivatives [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Interest expense									$ 40.4	$ 37.4

Equity and Distributions, Nonco

Equity and Distributions, Noncontrolling Interests (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Components of net income attributable to noncontrolling interests
Limited partners of Oiltanking other than EPO	$ 0	$ 0	$ 7.8
Joint venture partners	56.3	39.9	29.4
Total	56.3	39.9	37.2
Cash distributions paid to noncontrolling interests:
Limited partners of Oiltanking other than EPO	0	0	8.1
Joint venture partners	49.2	47.4	39.9
Total	49.2	47.4	48
Cash contributions from noncontrolling interests:
Joint venture partners	$ 0.4	$ 20.4	54
Oiltanking Partners L.P. [Member]
Noncontrolling Interest
Noncontrolling interests acquired			$ 1,400

Equity and Distributions, Distr

Equity and Distributions, Distributions (Details) - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Distributions to Partners [Abstract]
Number of days after quarter end to distribute available cash		45 days
Number of Designated Units excluded from distributions				35,380,000
Forecast [Member]
Distributions to Partners [Abstract]
Quarterly increase in cash distribution per unit (in dollars per unit)	$ 0.0025
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
Cash Distribution [Member] | First Quarter 2016 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)			$ 0.3950
Record Date			Apr. 29, 2016
Payment Date			May 6, 2016
Cash Distribution [Member] | Second Quarter 2016 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)			$ 0.4000
Record Date			Jul. 29, 2016
Payment Date			Aug. 5, 2016
Cash Distribution [Member] | Third Quarter 2016 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)			$ 0.4050
Record Date			Oct. 31, 2016
Payment Date			Nov. 7, 2016
Cash Distribution [Member] | Fourth Quarter 2016 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)			$ 0.4100
Record Date			Jan. 31, 2017
Payment Date			Feb. 7, 2017
Cash Distribution [Member] | First Quarter 2017 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)		$ 0.4150
Record Date		Apr. 28, 2017
Payment Date		May 8, 2017
Cash Distribution [Member] | Second Quarter 2017 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)		$ 0.4200
Record Date		Jul. 31, 2017
Payment Date		Aug. 7, 2017
Cash Distribution [Member] | Third Quarter 2017 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)		$ 0.4225
Record Date		Oct. 31, 2017
Payment Date		Nov. 7, 2017
Cash Distribution [Member] | Fourth Quarter 2017 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)		$ 0.4250
Record Date		Jan. 31, 2018
Payment Date		Feb. 7, 2018
Cash Distribution [Member] | Forecast [Member] | First Quarter 2018 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)	0.4275
Cash Distribution [Member] | Forecast [Member] | Second Quarter 2018 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)	0.4300
Cash Distribution [Member] | Forecast [Member] | Third Quarter 2018 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)	0.4325
Cash Distribution [Member] | Forecast [Member] | Fourth Quarter 2018 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)	$ 0.4350

Business Segments (Details)

Business Segments (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)SegmentFractionatormi	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Segment Reporting Information [Line Items]
Number of reportable segments | Segment	4
Number of miles of pipelines	50,000
Proceeds from disposal of assets | $	$ 40.1	$ 46.5	$ 1,608.6
Offshore Business [Member]
Segment Reporting Information [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 | $	$ 0	$ 0	$ 1,527.7
NGL Pipelines and Services [Member]
Segment Reporting Information [Line Items]
Number of miles of pipelines	19,600
Number of fractionators | Fractionator	14
Crude Oil Pipelines & Services [Member]
Segment Reporting Information [Line Items]
Number of miles of pipelines	5,800
Natural Gas Pipelines & Services [Member]
Segment Reporting Information [Line Items]
Number of miles of pipelines	19,700
Petrochemical and Refined Products Services [Member] | Propylene Operations [Member]
Segment Reporting Information [Line Items]
Number of miles of pipelines	800
Petrochemical and Refined Products Services [Member] | Refined Products Operations [Member]
Segment Reporting Information [Line Items]
Number of miles of pipelines	4,100

Business Segments, Gross Operat

Business Segments, Gross Operating Margin (Details) - USD ($) $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Business Segments [Abstract]
Income before income taxes										$ 2,881.3	$ 2,576.4	$ 2,555.9
Add total other expense, net										1,047.6	1,004.3	984.3
Operating income		$ 1,079.4	$ 879.2	$ 938.7	$ 1,031.6	$ 923.2	$ 905	$ 836.9	$ 915.6	3,928.9	3,580.7	3,540.2
Adjustments to reconcile operating income to total gross operating margin:
Add depreciation, amortization and accretion expense in operating costs and expenses										1,531.3	1,456.7	1,428.2
Add asset impairment and related charges in operating costs and expenses										49.8	52.8	162.6
Add net losses or subtract net gains attributable to asset sales in operating costs and expenses										(10.7)	(2.5)	15.6
Add general and administrative costs										181.1	160.1	192.6
Adjustments for make-up rights on certain new pipeline projects:
Add non-refundable payments received from shippers attributable to make-up rights	[1]									24.1	17.5	53.6
Subtract the subsequent recognition of revenues attributable to make-up rights	[2]									(29.9)	(34.6)	(60.7)
Total segment gross operating margin										$ 5,674.6	$ 5,230.7	$ 5,332.1
[1]	Since make-up rights entail a future performance obligation by the pipeline to the shipper, these receipts are recorded as deferred revenue for GAAP purposes; however, these receipts are included in gross operating margin in the period of receipt since they are nonrefundable to the shipper.
[2]	As deferred revenues attributable to make-up rights are subsequently recognized as revenue under GAAP, gross operating margin must be adjusted to remove such amounts to prevent duplication since the associated non-refundable payments were previously included in gross operating margin.

Business Segments, Segment Repo

Business Segments, Segment Reporting Information (Details) - USD ($) $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014
Information by business segment [Abstract]
Gross operating margin										$ 5,674.6	$ 5,230.7	$ 5,332.1
Revenues from third parties										29,196.5	22,965.6	26,955.6
Revenues from related parties										45	56.7	72.3
Intersegment and intrasegment revenues										0	0	0
Total revenues		$ 8,426.6	$ 6,886.9	$ 6,607.6	$ 7,320.4	$ 6,478.8	$ 5,920.4	$ 5,617.8	$ 5,005.3	29,241.5	23,022.3	27,027.9
Equity in income (loss) of unconsolidated affiliates										426	362	373.6
Property, plant and equipment, net		35,620.4				33,292.5				35,620.4	33,292.5	32,034.7
Investments in unconsolidated affiliates		2,659.4				2,677.3				2,659.4	2,677.3	2,628.5
Intangible assets, net		3,690.3				3,864.1				3,690.3	3,864.1	4,037.2
Goodwill		5,745.2				5,745.2				5,745.2	5,745.2	5,745.2		$ 4,300.2
Segment assets		47,715.3				45,579.1				47,715.3	45,579.1	44,445.6
NGL Pipelines and Services [Member]
Information by business segment [Abstract]
Total revenues										12,468	10,242.5	9,788
Equity in income (loss) of unconsolidated affiliates										73.4	61.4	57.5
Intangible assets, net		322.3				350.2				322.3	350.2
Goodwill		2,651.7				2,651.7				2,651.7	2,651.7	2,651.7		2,210.2
Crude Oil Pipelines & Services [Member]
Information by business segment [Abstract]
Total revenues										8,156.8	6,515	10,305.9
Equity in income (loss) of unconsolidated affiliates										358.4	311.9	281.4
Intangible assets, net		2,186.5				2,279				2,186.5	2,279
Goodwill		1,841				1,841				1,841	1,841	1,841		918.7
Natural Gas Pipelines & Services [Member]
Information by business segment [Abstract]
Total revenues										3,145.6	2,543	2,743.3
Equity in income (loss) of unconsolidated affiliates										3.8	3.8	3.8
Intangible assets, net		1,018.4				1,054.5				1,018.4	1,054.5
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										5,471.1	3,721.8	4,111.9
Equity in income (loss) of unconsolidated affiliates	[1]									(9.6)	(15.1)	(15.7)
Intangible assets, net		163.1				180.4				163.1	180.4
Goodwill		956.2				956.2				956.2	956.2	956.2		793
Offshore Pipelines And Services [Member]
Information by business segment [Abstract]
Total revenues										0	0	78.8
Equity in income (loss) of unconsolidated affiliates										0	0	46.6	[2]
Goodwill		0				0				0	0	0		$ 82
Reportable Business Segments [Member] | NGL Pipelines and Services [Member]
Information by business segment [Abstract]
Gross operating margin										3,258.3	2,990.6	2,771.6
Revenues from third parties										12,455.7	10,232.7	9,779
Revenues from related parties										12.3	9.8	9
Intersegment and intrasegment revenues										27,278.6	19,150	10,217.9
Total revenues										39,746.6	29,392.5	20,005.9
Equity in income (loss) of unconsolidated affiliates										73.4	61.4	57.5
Property, plant and equipment, net		13,831.2				14,091.5				13,831.2	14,091.5	12,909.7
Investments in unconsolidated affiliates		733.9				750.4				733.9	750.4	718.7
Intangible assets, net		322.3				350.2				322.3	350.2	380.3
Goodwill		2,651.7				2,651.7				2,651.7	2,651.7	2,651.7
Segment assets		17,539.1				17,843.8				17,539.1	17,843.8	16,660.4
Reportable Business Segments [Member] | Crude Oil Pipelines & Services [Member]
Information by business segment [Abstract]
Gross operating margin										987.2	854.6	961.9
Revenues from third parties										8,137.2	6,478.7	10,258.3
Revenues from related parties										19.6	36.3	47.6
Intersegment and intrasegment revenues										15,943	9,052	5,162
Total revenues										24,099.8	15,567	15,467.9
Equity in income (loss) of unconsolidated affiliates										358.4	311.9	281.4
Property, plant and equipment, net		5,208.4				4,216.1				5,208.4	4,216.1	3,550.3
Investments in unconsolidated affiliates		1,839.2				1,824.6				1,839.2	1,824.6	1,813.4
Intangible assets, net		2,186.5				2,279				2,186.5	2,279	2,377.5
Goodwill		1,841				1,841				1,841	1,841	1,841
Segment assets		11,075.1				10,160.7				11,075.1	10,160.7	9,582.2
Reportable Business Segments [Member] | Natural Gas Pipelines & Services [Member]
Information by business segment [Abstract]
Gross operating margin										714.5	734.9	782.6
Revenues from third parties										3,132.5	2,532.4	2,729.5
Revenues from related parties										13.1	10.6	13.8
Intersegment and intrasegment revenues										850.8	668.5	662.1
Total revenues										3,996.4	3,211.5	3,405.4
Equity in income (loss) of unconsolidated affiliates										3.8	3.8	3.8
Property, plant and equipment, net		8,375				8,403				8,375	8,403	8,620
Investments in unconsolidated affiliates		20.8				21.7				20.8	21.7	22.5
Intangible assets, net		1,018.4				1,054.5				1,018.4	1,054.5	1,087.7
Goodwill		296.3				296.3				296.3	296.3	296.3
Segment assets		9,710.5				9,775.5				9,710.5	9,775.5	10,026.5
Reportable Business Segments [Member] | Petrochemical & Refined Products Services [Member]
Information by business segment [Abstract]
Gross operating margin										714.6	650.6	718.5
Revenues from third parties										5,471.1	3,721.8	4,111.9
Revenues from related parties										0	0	0
Intersegment and intrasegment revenues										1,766.9	1,234.8	1,126
Total revenues										7,238	4,956.6	5,237.9
Equity in income (loss) of unconsolidated affiliates										(9.6)	(15.1)	(15.7)
Property, plant and equipment, net		3,507.7				3,261.2				3,507.7	3,261.2	3,060.7
Investments in unconsolidated affiliates		65.5				80.6				65.5	80.6	73.9
Intangible assets, net		163.1				180.4				163.1	180.4	191.7
Goodwill		956.2				956.2				956.2	956.2	956.2
Segment assets		4,692.5				4,478.4				4,692.5	4,478.4	4,282.5
Reportable Business Segments [Member] | Offshore Pipelines And Services [Member]
Information by business segment [Abstract]
Gross operating margin										0	0	97.5
Revenues from third parties										0	0	76.9
Revenues from related parties										0	0	1.9
Intersegment and intrasegment revenues										0	0	0.6
Total revenues										0	0	79.4
Equity in income (loss) of unconsolidated affiliates										0	0	46.6
Property, plant and equipment, net		0				0				0	0	0
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		0				0				0	0	0
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										(45,839.3)	(30,105.3)	(17,168.6)
Total revenues										(45,839.3)	(30,105.3)	(17,168.6)
Equity in income (loss) of unconsolidated affiliates										0	0	0
Property, plant and equipment, net		4,698.1				3,320.7				4,698.1	3,320.7	3,894
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		$ 4,698.1				$ 3,320.7				$ 4,698.1	$ 3,320.7	$ 3,894
[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 market and income approaches, indicate that the fair value of this investment remains in excess of its carrying value.
[2]	Our investments in unconsolidated affiliates classified within the Offshore Pipelines & Services segment were sold in July 2015 (see Note 10).

Business Segments, Consolidated

Business Segments, Consolidated Revenues and Expenses (Details) - USD ($) $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Consolidated Revenues [Abstract]
Total consolidated revenues		$ 8,426.6	$ 6,886.9	$ 6,607.6	$ 7,320.4	$ 6,478.8	$ 5,920.4	$ 5,617.8	$ 5,005.3	$ 29,241.5	$ 23,022.3	$ 27,027.9
Operating costs and expenses:
Cost of sales	[1]									21,487	15,710.9	19,612.9
Other operating costs and expenses	[2]									2,500.1	2,425.6	2,449.4
Depreciation, amortization and accretion										1,531.3	1,456.7	1,428.2
Asset impairment and related charges										49.8	52.8	162.6
Net losses (gains) attributable to asset sales										(10.7)	(2.5)	15.6
General and administrative costs										181.1	160.1	192.6
Total costs and expenses										25,738.6	$ 19,803.6	$ 23,861.3
Vitol Holding B.V. [Member]
Consolidated Revenues [Abstract]
Total consolidated revenues										$ 3,288.3
Vitol Holding B.V. [Member] | Revenues [Member]
Consolidated Revenues [Abstract]
Largest non-affiliated customer percentage										11.20%	9.90%
Shell Oil Company [Member] | Revenues [Member]
Consolidated Revenues [Abstract]
Largest non-affiliated customer percentage												7.40%
NGL Pipelines and Services [Member]
Consolidated Revenues [Abstract]
Total consolidated revenues										$ 12,468	$ 10,242.5	$ 9,788
NGL Pipelines and Services [Member] | Vitol Holding B.V. [Member]
Consolidated Revenues [Abstract]
Total consolidated revenues										2,099.1
Crude Oil Pipelines & Services [Member]
Consolidated Revenues [Abstract]
Total consolidated revenues										8,156.8	6,515	10,305.9
Crude Oil Pipelines & Services [Member] | Vitol Holding B.V. [Member]
Consolidated Revenues [Abstract]
Total consolidated revenues										625.6
Natural Gas Pipelines & Services [Member]
Consolidated Revenues [Abstract]
Total consolidated revenues										3,145.6	2,543	2,743.3
Natural Gas Pipelines & Services [Member] | Vitol Holding B.V. [Member]
Consolidated Revenues [Abstract]
Total consolidated revenues										51.1
Petrochemical and Refined Products Services [Member]
Consolidated Revenues [Abstract]
Total consolidated revenues										5,471.1	3,721.8	4,111.9
Petrochemical and Refined Products Services [Member] | Vitol Holding B.V. [Member]
Consolidated Revenues [Abstract]
Total consolidated revenues										512.5
Offshore Pipelines And Services [Member]
Consolidated Revenues [Abstract]
Total consolidated revenues										$ 0	$ 0	$ 78.8
[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 the cost of operating our plants, pipelines and other fixed assets excluding: depreciation, amortization and accretion charges; asset impairment and related charges; and net losses (or gains) attributable to asset sales.

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, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
BASIC EARNINGS PER UNIT
Net income attributable to limited partners		$ 774	$ 610.9	$ 653.7	$ 760.7	$ 658.8	$ 634.6	$ 558.5	$ 661.2	$ 2,799.3	$ 2,513.1	$ 2,521.2
Undistributed earnings allocated and cash payments on phantom unit awards	[1]									(15.9)	(12.9)	(8.7)
Net income available to common unitholders										$ 2,783.4	$ 2,500.2	$ 2,512.5
Basic weighted-average number of common units outstanding (in units)										2,145	2,081.4	1,966.6
Basic earnings per unit (in dollars per unit)		$ 0.36	$ 0.28	$ 0.30	$ 0.36	$ 0.31	$ 0.30	$ 0.27	$ 0.32	$ 1.30	$ 1.20	$ 1.28
DILUTED EARNINGS PER UNIT
Net income attributable to limited partners		$ 774	$ 610.9	$ 653.7	$ 760.7	$ 658.8	$ 634.6	$ 558.5	$ 661.2	$ 2,799.3	$ 2,513.1	$ 2,521.2
Diluted weighted-average number of units outstanding:
Distribution-bearing common units (in units)										2,145	2,081.4	1,966.6
Designated Units (in units)										0	0	26.5
Phantom units (in units)	[1]									9.3	7.7	5.4
Incremental option units (in units)										0	0	0.1
Total (in units)										2,154.3	2,089.1	1,998.6
Diluted earnings per unit (in dollars per unit)		$ 0.36	$ 0.28	$ 0.30	$ 0.36	$ 0.31	$ 0.30	$ 0.27	$ 0.32	$ 1.30	$ 1.20	$ 1.26
[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.

Business Combinations (Details)

Business Combinations (Details) - USD ($) $ in Millions	1 Months Ended	6 Months Ended	12 Months Ended				14 Months Ended
	Feb. 28, 2015	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Feb. 13, 2015
Description of Business Combinations:
Cash paid to acquire business			$ 198.7	$ 1,000	$ 1,056.5
Common units issued in connection with acquisition					36,827,517	54,807,352
Intangible assets reclassified to goodwill					$ 1,454.1
EFS Midstream Contract with Producers [Member]
Description of Business Combinations:
Contractual obligation			$ 270
Azure Midstream Partners, L.P. [Member]
Description of Business Combinations:
Business acquisition, description			The acquired business assets, which are located primarily in East Texas, include over 750 miles of natural gas gathering pipelines and two natural gas processing facilities (Panola and Fairway) with an aggregate processing capacity of 130 MMcf/d. The acquired business primarily serves production from the Haynesville Shale and Bossier, Cotton Valley and Travis Peak formations.
Total consideration for acquisition			$ 191.4
Eagle Ford Midstream Assets [Member]
Description of Business Combinations:
Business acquisition, description			The EFS Midstream System provides condensate gathering and processing services as well as gathering, treating and compression services for the associated natural gas.
Total consideration for acquisition					2,100
Cash paid to acquire business				$ 1,000	1,100
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 featuring a number of ship and barge docks and extensive crude oil and petroleum products storage capacity.
Total consideration for acquisition						$ 4,400	$ 6,020
Noncontrolling interests acquired					1,400
Intangible assets reclassified to goodwill					1,450
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
Cash paid to acquire business						$ 2,210
Common units issued in connection with acquisition						54,807,352
Cash paid to assume notes receivable						$ 228.3
Oiltanking Partners L.P. - Step 2 [Member]
Description of Business Combinations:
Common units issued in connection with acquisition	36,827,517
Common units exchanged for each Oiltanking unit (in units)	1.3
Noncontrolling interests acquired					$ 1,400
Intangible assets reclassified to goodwill	$ 1,460

Business Combinations, Purchase

Business Combinations, Purchase Price Allocation (Details) - Azure Midstream Partners, L.P. [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Apr. 30, 2017
Assets acquired in business combination:
Current assets		$ 3.1
Property, plant, and equipment		193.1
Total assets acquired		196.2
Liabilities assumed in business combination:
Current liabilities		1.4
Long-term liabilities		3.4
Total liabilities assumed		$ 4.8
Total consideration for acquisition	$ 191.4

Business Combinations, Pro Form

Business Combinations, Pro Forma Earnings Data (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Basic earnings per unit [Abstract]
As reported basic earnings per unit (in dollars per unit)	$ 0.36	$ 0.28	$ 0.30	$ 0.36	$ 0.31	$ 0.30	$ 0.27	$ 0.32	$ 1.30	$ 1.20	$ 1.28
Diluted earnings per unit [Abstract]
As reported diluted earnings per unit (in dollars per unit)	$ 0.36	$ 0.28	$ 0.30	$ 0.36	$ 0.31	$ 0.30	$ 0.27	$ 0.32	$ 1.30	$ 1.20	$ 1.26
Eagle Ford Midstream Assets [Member]
Pro forma earnings data [Abstract]
Revenues											$ 27,148.5
Costs and expenses											23,937.1
Operating income											3,585
Net income											2,594.4
Net income attributable to noncontrolling interests											37.2
Net income attributable to limited partners											$ 2,557.2
Basic earnings per unit [Abstract]
Pro forma basic earnings per unit (in dollars per unit)											$ 1.30
Diluted earnings per unit [Abstract]
Pro forma diluted earnings per unit (in dollars per unit)											$ 1.28

Equity-Based Awards (Details)

Equity-Based Awards (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Equity-based compensation expense [Abstract]
Total compensation expense	$ 99.7	$ 89.2	$ 93.2
Phantom Unit Awards [Member]
Equity-based compensation expense [Abstract]
Total compensation expense	92.8	78.6	78.3
Restricted Common Unit Awards [Member]
Equity-based compensation expense [Abstract]
Total compensation expense	0.5	4.7	14.7
Profits Interest Awards [Member]
Equity-based compensation expense [Abstract]
Total compensation expense	6	5.4	0
Liability-classified awards [Member]
Equity-based compensation expense [Abstract]
Total compensation expense	$ 0.4	$ 0.5	$ 0.2
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)	40,000,000
Remaining number of common units available to be issued as awards (in units)	19,091,065

Equity-Based Awards, Phantom Un

Equity-Based Awards, Phantom Unit Awards (Details) - USD ($) $ / shares in Units, $ in Millions		12 Months Ended
		Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
Summary of awards activity, equity instruments other than options, additional disclosures [Abstract]
Cash payments made in connection with DERs		$ 15.1		$ 11.7		$ 7.7
Phantom Unit Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting rate of phantom unit awards		25.00%
Summary of awards activity, equity instruments other than options [Roll Forward]
Beginning of period (in units)		7,767,501		5,426,949		3,342,390
Granted (in units)		4,268,920	[1]	4,508,310	[2]	3,496,140	[3]
Vested (in units)		(2,490,081)		(1,761,455)		(940,415)
Forfeited (in units)		(256,839)		(406,303)		(471,166)
End of period (in units)		9,289,501		7,767,501		5,426,949
Common units issued in connection with the vesting of phantom unit awards (in units)		1,687,692		1,170,600		618,395
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)	[4]	$ 27.20		$ 33.63		$ 33.13
Granted weighted-average grant date fair value per unit (in dollars per unit)	[4]	28.83	[1]	21.90	[2]	33.96	[3]
Vested weighted-average grant date fair value per unit (in dollars per unit)	[4]	28.30		33.10		33.14
Forfeited weighted-average grant date fair value per unit (in dollars per unit)	[4]	27.60		28.52		33.51
Weighted-average grant date fair value per unit, at end of period (in dollars per unit)	[4]	$ 27.65		$ 27.20		$ 33.63
Summary of awards activity, equity instruments other than options, additional disclosures [Abstract]
Aggregate grant date fair value		$ 123.1		$ 98.7		$ 118.7
Estimated forfeiture rate		3.80%		3.90%		3.50%
Cash payments made in connection with DERs		$ 15.1		$ 11.7		$ 7.7
Total intrinsic value of phantom unit awards that vested during period		69.8		$ 40.9		$ 31.2
Unrecognized Compensation Expense [Abstract]
Unrecognized compensation cost		$ 92.3
Recognition period for total unrecognized compensation cost		2 years 1 month 6 days
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)		$ 24.55		$ 21.86		$ 27.31
Phantom Unit Awards [Member] | Maximum [Member]
Summary of awards activity, equity instruments other than options, additional disclosures [Abstract]
Grant date market price of common units (in dollars per unit)		$ 28.87		$ 27.39		$ 34.40
Phantom Unit Awards [Member] | Enterprise [Member]
Unrecognized Compensation Expense [Abstract]
Unrecognized compensation cost		$ 77.5
[1]	The aggregate grant date fair value of phantom unit awards issued during 2017 was $123.1 million based on a grant date market price of our common units ranging from $24.55 to $28.87 per unit. An estimated annual forfeiture rate of 3.8 percent was applied to these awards.
[2]	The aggregate grant date fair value of phantom unit awards issued during 2016 was $98.7 million based on a grant date market price of our common units ranging from $21.86 to $27.39 per unit. An estimated annual forfeiture rate of 3.9 percent 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 percent was applied to these awards.
[4]	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, Profits In

Equity-Based Awards, Profits Interest Awards (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)$ / sharesshares
EPD PubCo I [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	30 days
Enterprise common units contributed to Employee Partnership by EPCO Holdings (in units) | shares	2,723,052
Class A capital base	$ 63.7	[1]
Class A preference return | $ / shares	$ 0.39	[2]
Expected vesting/liquidation date	Feb. 1, 2020
Estimated grant date fair value of profits interest awards	$ 13.2	[3]
Unrecognized Compensation Expense [Abstract]
Unrecognized compensation cost	$ 7.4	[4]
Recognition period for total unrecognized compensation cost	2 years 1 month 6 days
Estimated Grant Date Fair Value Assumptions [Abstract]
Expected life of award	4 years
EPD PubCo I [Member] | Minimum [Member]
Estimated Grant Date Fair Value Assumptions [Abstract]
Risk-free interest rate	0.90%
Expected distribution yield	6.20%
Expected unit price volatility	29.00%
EPD PubCo I [Member] | Maximum [Member]
Estimated Grant Date Fair Value Assumptions [Abstract]
Risk-free interest rate	1.60%
Expected distribution yield	7.00%
Expected unit price volatility	40.00%
EPD PubCo II [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	30 days
Enterprise common units contributed to Employee Partnership by EPCO Holdings (in units) | shares	2,834,198
Class A capital base	$ 66.3	[1]
Class A preference return | $ / shares	$ 0.39	[2]
Expected vesting/liquidation date	Feb. 1, 2021
Estimated grant date fair value of profits interest awards	$ 14.7	[3]
Unrecognized Compensation Expense [Abstract]
Unrecognized compensation cost	$ 9.3	[4]
Recognition period for total unrecognized compensation cost	3 years 1 month 6 days
Estimated Grant Date Fair Value Assumptions [Abstract]
Expected life of award	5 years
EPD PubCo II [Member] | Minimum [Member]
Estimated Grant Date Fair Value Assumptions [Abstract]
Risk-free interest rate	1.10%
Expected distribution yield	6.10%
Expected unit price volatility	27.00%
EPD PubCo II [Member] | Maximum [Member]
Estimated Grant Date Fair Value Assumptions [Abstract]
Risk-free interest rate	1.80%
Expected distribution yield	7.00%
Expected unit price volatility	40.00%
EPD PubCo III [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	30 days
Enterprise common units contributed to Employee Partnership by EPCO Holdings (in units) | shares	105,000
Class A capital base	$ 2.5	[1]
Class A preference return | $ / shares	$ 0.39	[2]
Expected vesting/liquidation date	Apr. 1, 2020
Estimated grant date fair value of profits interest awards	$ 0.6	[3]
Unrecognized Compensation Expense [Abstract]
Unrecognized compensation cost	$ 0.2	[4]
Recognition period for total unrecognized compensation cost	2 years 3 months 18 days
Estimated Grant Date Fair Value Assumptions [Abstract]
Expected life of award	4 years
EPD PubCo III [Member] | Minimum [Member]
Estimated Grant Date Fair Value Assumptions [Abstract]
Risk-free interest rate	1.00%
Expected distribution yield	6.10%
Expected unit price volatility	31.00%
EPD PubCo III [Member] | Maximum [Member]
Estimated Grant Date Fair Value Assumptions [Abstract]
Risk-free interest rate	1.40%
Expected distribution yield	6.20%
Expected unit price volatility	40.00%
EPD PrivCo I [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	30 days
Enterprise common units contributed to Employee Partnership by EPCO Holdings (in units) | shares	1,111,438
Class A capital base	$ 26	[1]
Class A preference return | $ / shares	$ 0.39	[2]
Expected vesting/liquidation date	Feb. 1, 2021
Estimated grant date fair value of profits interest awards	$ 5.8	[3]
Unrecognized Compensation Expense [Abstract]
Unrecognized compensation cost	$ 0.8	[4]
Recognition period for total unrecognized compensation cost	3 years 1 month 6 days
Estimated Grant Date Fair Value Assumptions [Abstract]
Expected life of award	5 years
EPD PrivCo I [Member] | Minimum [Member]
Estimated Grant Date Fair Value Assumptions [Abstract]
Risk-free interest rate	1.20%
Expected distribution yield	6.10%
Expected unit price volatility	28.00%
EPD PrivCo I [Member] | Maximum [Member]
Estimated Grant Date Fair Value Assumptions [Abstract]
Risk-free interest rate	1.60%
Expected distribution yield	6.70%
Expected unit price volatility	40.00%
[1]	Represents fair market value of the Enterprise common units contributed to each Employee Partnership at the applicable contribution date.
[2]	Each quarter, the Class A limited partner in each Employee Partnership is paid a cash distribution equal to the product of (i) the number of common units owned by the Employee Partnership and (ii) the Class A Preference Return of $0.39 per unit (subject to equitable adjustment in order to reflect any equity split, equity distribution or dividend, reverse split, combination, reclassification, recapitalization or other similar event affecting such common units). To the extent that the Employee Partnership has cash remaining after making this quarterly payment to the Class A limited partner, the residual cash is distributed to the Class B limited partners on a quarterly basis.
[3]	Represents the total grant date fair value of the profits interest awards irrespective of how such costs will be allocated between us and EPCO and its privately held affiliates.
[4]	Represents our expected share of the unrecognized compensation cost at December 31, 2017. We expect to recognize our share of the unrecognized compensation cost for PubCo I, PubCo II, PubCo III and PrivCo I over a weighted-average period of 2.1 years, 3.1 years, 2.3 years and 3.1 years, respectively.

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting rate of restricted common unit awards		25.00%
Summary of awards activity, equity instruments other than options [Roll Forward]
Beginning of period (in units)		682,294	1,960,520	4,229,790
Vested (in units)		(681,044)	(1,234,502)	(2,009,970)
Forfeited (in units)		(1,250)	(43,724)	(259,300)
End of period (in units)		0	682,294	1,960,520
Restricted units outstanding, weighted-average grant date fair value [Roll Forward]
Weighted-average grant date fair value per unit, at beginning of period (in dollars per unit)	[1]	$ 28.61	$ 27.88	$ 26.96
Vested weighted-average grant date fair value per unit (in dollars per unit)	[1]	28.60	27.45	26
Forfeited weighted-average grant date fair value per unit (in dollars per unit)	[1]	$ 31.07	28.48	27.53
Weighted-average grant date fair value per unit, at end of period (in dollars per unit)	[1]		$ 28.61	$ 27.88
Summary of awards activity, equity instruments other than options, additional disclosures [Abstract]
Cash distributions paid to restricted common unitholders		$ 0.3	$ 1.6	$ 4
Total intrinsic value of restricted common unit awards that vested during period		$ 18.9	$ 28.5	$ 67.3
[1]	Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued.

Equity-Based Awards, Unit Optio

Equity-Based Awards, Unit Option Awards (Details) - Unit Option Awards [Member] - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2015
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
Exercised (in units)		(1,270,000)
End of period (in units)		0
Options outstanding, weighted-average strike price [Roll Forward]
Weighted average strike price, beginning of period (in dollars per unit)		$ 16.14
Weighted average strike price, exercised (in dollars per unit)		16.14
Weighted average strike price, end of period (in dollars per unit)		$ 0
Total intrinsic value of unit option awards exercised during period		$ 21.7
Cash received from EPCO in connection with the exercise of unit option awards		13.1
Unit option award-related cash reimbursements to EPCO		$ 21.7

Derivative Instruments, Hedgi82

Derivative Instruments, Hedging Activities and Fair Value Measurements (Details) bbl in Millions, $ in Millions, ft³ in Billions		1 Months Ended	12 Months Ended
		Jan. 31, 2018USD ($)	Dec. 31, 2017USD ($)Contractbblft³	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Derivative [Line Items]
Cash gain realized to due settlement of interest rate derivative instruments | $			$ 30.6	$ 6.1	$ 0
Interest Rate Swaps Hedging Senior Notes OO [Member] | Derivatives in fair value hedging relationships [Member]
Derivative [Line Items]
Number of Derivatives Outstanding | Contract			10
Type of Derivatives Outstanding			fixed-to-floating swaps
Notional Amount | $			$ 750
Derivative, Inception Date			May 1, 2015
Expected Termination Date			May 1, 2018
Rate Swap, fixed rate			1.65%
Rate Swap, floating rate			1.87%
Forward Starting Swaps [Member] | Derivatives in cash flow hedging relationships [Member]
Derivative [Line Items]
Cash gain realized to due settlement of interest rate derivative instruments | $			$ 30.6	$ 6.1
Forward Starting Swaps [Member] | Derivatives in cash flow hedging relationships [Member] | Subsequent Event [Member]
Derivative [Line Items]
Notional amount of settled derivative instruments | $		$ 100
Cash gain realized to due settlement of interest rate derivative instruments | $		$ 1.5
Forward Starting Swaps B [Member] | Derivatives in cash flow hedging relationships [Member]
Derivative [Line Items]
Number of Derivatives Outstanding | Contract			3
Type of Derivatives Outstanding			forward starting swaps
Notional Amount | $			$ 275
Expected Termination Date			Feb. 1, 2019
Average Rate Locked			2.57%
Designated as Hedging Instrument [Member] | Octane enhancement: Forecasted purchases of NGLs [Member] | Derivatives in cash flow hedging relationships [Member]
Derivative [Line Items]
Derivative instruments, current volume	[1],[2]		1.1
Designated as Hedging Instrument [Member] | Octane enhancement: Forecasted sales of octane enhancement products [Member] | Derivatives in cash flow hedging relationships [Member]
Derivative [Line Items]
Derivative instruments, current volume	[1],[2]		1
Designated as Hedging Instrument [Member] | Natural gas marketing: Forecasted purchases of natural gas for fuel [Member] | Derivatives in cash flow hedging relationships [Member]
Derivative [Line Items]
Derivative instruments, current volume | ft³	[1],[2]		1
Designated as Hedging Instrument [Member] | Natural gas marketing: Natural gas storage inventory management activities [Member] | Derivatives in fair value hedging relationships [Member]
Derivative [Line Items]
Derivative instruments, current volume | ft³	[1],[2]		3.9
Designated as Hedging Instrument [Member] | NGL marketing: Forecasted purchases of NGLs and related hydrocarbon products [Member] | Derivatives in cash flow hedging relationships [Member]
Derivative [Line Items]
Derivative instruments, current volume	[1],[2]		49
Designated as Hedging Instrument [Member] | NGL marketing: Forecasted sales of NGLs and related hydrocarbon products [Member] | Derivatives in cash flow hedging relationships [Member]
Derivative [Line Items]
Derivative instruments, current volume	[1],[2]		64.6
Designated as Hedging Instrument [Member] | NGL marketing: NGLs inventory management activities [Member] | Derivatives in fair value hedging relationships [Member]
Derivative [Line Items]
Derivative instruments, current volume	[1],[2]		0.5
Designated as Hedging Instrument [Member] | Refined products marketing: Forecasted purchases of refined products [Member] | Derivatives in cash flow hedging relationships [Member]
Derivative [Line Items]
Derivative instruments, current volume	[1],[2]		0.6
Designated as Hedging Instrument [Member] | Refined products marketing: Forecasted sales of refined products [Member] | Derivatives in cash flow hedging relationships [Member]
Derivative [Line Items]
Derivative instruments, current volume	[1],[2]		1.3
Designated as Hedging Instrument [Member] | Refined products marketing: Refined products inventory management activities [Member] | Derivatives in fair value hedging relationships [Member]
Derivative [Line Items]
Derivative instruments, current volume	[1],[2]		0.5
Designated as Hedging Instrument [Member] | Crude oil marketing: Forecasted purchases of crude oil [Member] | Derivatives in cash flow hedging relationships [Member]
Derivative [Line Items]
Derivative instruments, current volume	[1],[2]		3.7
Derivative instruments, long-term volume	[1],[2]		3.3
Designated as Hedging Instrument [Member] | Crude oil marketing: Forecasted sales of crude oil [Member] | Derivatives in cash flow hedging relationships [Member]
Derivative [Line Items]
Derivative instruments, current volume	[1],[2]		6.9
Derivative instruments, long-term volume	[1],[2]		3.3
Designated as Hedging Instrument [Member] | Petrochemical marketing: Forecasted purchases of NGLs for propylene marketing activities [Member] | Derivatives in cash flow hedging relationships [Member]
Derivative [Line Items]
Derivative instruments, current volume	[1],[2]		0.8
Not Designated as Hedging Instrument [Member] | Natural gas risk management activities [Member] | Derivatives in mark-to-market relationships [Member]
Derivative [Line Items]
Derivative instruments, current volume | ft³	[1],[2],[3],[4]		67.3
Derivative instruments, long-term volume | ft³	[1],[2],[3],[4]		9
Current natural gas hedging volumes designated as an index plus or minus a discount | ft³			21.1
Long-term natural gas hedging volumes designated as an index plus or minus a discount | ft³			5.3
Not Designated as Hedging Instrument [Member] | NGL risk management activities [Member] | Derivatives in mark-to-market relationships [Member]
Derivative [Line Items]
Derivative instruments, current volume	[1],[2],[4]		18.3
Not Designated as Hedging Instrument [Member] | Refined products risk management activities [Member] | Derivatives in mark-to-market relationships [Member]
Derivative [Line Items]
Derivative instruments, current volume	[1],[2],[4]		0.6
Not Designated as Hedging Instrument [Member] | Crude oil risk management activities [Member] | Derivatives in mark-to-market relationships [Member]
Derivative [Line Items]
Derivative instruments, current volume	[1],[2],[4]		104
Derivative instruments, long-term volume	[1],[2],[4]		12.2
[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 2020, May 2018 and December 2020, 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 21.1 Bcf and 5.3 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, Hedgi83

Derivative Instruments, Hedging Activities and Fair Value Measurements, Derivative Fair Value Amounts (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Interest rate derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	$ 0.1	$ 36.5
Liability Derivatives	1.7	1.1
Commodity derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	161.7	541.4
Liability Derivatives	176.9	739.4
Derivatives designated as hedging instruments [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	116	535.7
Liability Derivatives	112.9	663.1
Derivatives designated as hedging instruments [Member] | Interest rate derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	0.1	36.5
Liability Derivatives	1.7	1.1
Derivatives designated as hedging instruments [Member] | Interest rate derivatives [Member] | Current assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	0	0.3
Derivatives designated as hedging instruments [Member] | Interest rate derivatives [Member] | Other assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	0.1	36.2
Derivatives designated as hedging instruments [Member] | Interest rate derivatives [Member] | Current liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	1.5	0.2
Derivatives designated as hedging instruments [Member] | Interest rate derivatives [Member] | Other liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	0.2	0.9
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	115.9	499.2
Liability Derivatives	111.2	662
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member] | Current assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	109.5	499.2
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member] | Other assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	6.4	0
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member] | Current liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	104.4	662
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member] | Other liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	6.8	0
Derivatives not designated as hedging instruments [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	45.8	42.2
Liability Derivatives	65.7	77.4
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	45.8	42.2
Liability Derivatives	65.7	77.4
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Current assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	43.9	41.9
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Other assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	1.9	0.3
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Current liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	62.3	75.5
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Other liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	$ 3.4	$ 1.9

Derivative Instruments, Hedgi84

Derivative Instruments, Hedging Activities and Fair Value Measurements, Asset Balance Sheet Offsetting (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Interest rate derivatives [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	$ 0.1	$ 36.5
Gross Amounts Offset in the Balance Sheet	0	0
Amounts of Assets Presented in the Balance Sheet	0.1	36.5
Financial Instruments	(0.1)	(0.2)
Cash Collateral Paid	0	0
Cash Collateral Received	0	0
Amounts That Would Have Been Presented On Net Basis	0	36.3
Commodity Derivatives [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	161.7	541.4
Gross Amounts Offset in the Balance Sheet	0	0
Amounts of Assets Presented in the Balance Sheet	161.7	541.4
Financial Instruments	(157.8)	(526.8)
Cash Collateral Paid	0	0
Cash Collateral Received	0	0
Amounts That Would Have Been Presented On Net Basis	$ 3.9	$ 14.6

Derivative Instruments, Hedgi85

Derivative Instruments, Hedging Activities and Fair Value Measurements, Liability Balance Sheet Offsetting (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Interest rate derivatives [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	$ 1.7	$ 1.1
Gross Amounts Offset in the Balance Sheet	0	0
Amounts of Liabilities Presented in the Balance Sheet	1.7	1.1
Financial Instruments	(0.1)	(0.2)
Cash Collateral Paid	0	0
Amounts That Would Have Been Presented On Net Basis	1.6	0.9
Commodity Derivatives [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	176.9	739.4
Gross Amounts Offset in the Balance Sheet	0	0
Amounts of Liabilities Presented in the Balance Sheet	176.9	739.4
Financial Instruments	(157.8)	(526.8)
Cash Collateral Paid	(17.3)	(212.4)
Amounts That Would Have Been Presented On Net Basis	$ 1.8	$ 0.2

Derivative Instruments, Hedgi86

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivatives in fair value hedging relationships [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Derivative		$ 0.9	$ (90.2)	$ 17.7
Gain (Loss) Recognized in Income on Hedged Item		27.8	124.6	1.6
Derivatives in fair value hedging relationships [Member] | Interest rate derivatives [Member] | Interest expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Derivative		(0.2)	0.3	(1.4)
Gain (Loss) Recognized in Income on Hedged Item		0.4	(0.4)	1.4
Derivatives in fair value hedging relationships [Member] | Commodity derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on Fair Value Hedges Recognized in Earnings		28.5	34.5
Gain (Loss) on Fair Value Hedge Ineffectiveness		1	1.1
Gain (Loss) from Components Excluded from Assessment of Fair Value Hedge Effectiveness		27.5	33.4
Derivatives in fair value hedging relationships [Member] | Commodity derivatives [Member] | Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Derivative		1.1	(90.5)	19.1
Gain (Loss) Recognized in Income on Hedged Item		27.4	125	0.2
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)		(44.2)	(151.5)	214.9
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income (Effective Portion)		(152.6)	(90.8)	192.9
Gain (Loss) Recognized in Income on Derivative (Ineffective Portion)		(1.1)	0.5	4.8
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)		(5.7)	42.3	0
Accumulated other comprehensive loss related to interest rate derivative instruments expected to be reclassified to earnings in interest expense over the next twelve months		(38.4)
Derivatives in cash flow hedging relationships [Member] | Interest rate derivatives [Member] | Interest expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income (Effective Portion)		(40.4)	(37.4)	(35.3)
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		(9.7)
Accumulated other comprehensive income (loss) related to commodity derivative instruments expected to be reclassified to revenue over the next twelve months		(9.4)
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] | Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Change in Value Recognized in Other Comprehensive Income (Loss) on Derivative (Effective Portion)	[1]	(33.7)	(197.4)	217.6
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income (Effective Portion)		(111.6)	(53.6)	231.7
Gain (Loss) Recognized in Income on Derivative (Ineffective Portion)		0	0	4.7
Derivatives in cash flow hedging relationships [Member] | Commodity derivatives [Member] | 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]	(4.8)	3.6	(2.7)
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income (Effective Portion)		(0.6)	0.2	(3.5)
Gain (Loss) Recognized in Income on Derivative (Ineffective Portion)		(1.1)	0.5	0.1
Derivatives not designated as hedging instruments [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Derivative		(42.6)	(38.8)	1.1
Derivatives not designated as hedging instruments [Member] | Interest rate derivatives [Member] | Interest expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Derivative		0	0	0
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Derivative		(42.7)	(38.4)	1
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Operating costs and expenses [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Derivative		$ 0.1	$ (0.4)	$ 0.1
[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, Hedgi87

Derivative Instruments, Hedging Activities and Fair Value Measurements, Recurring Fair Value Measurements (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
Financial liabilities [Abstract]
Liquidity option agreement		$ 333.9		$ 269.6
Total gains (losses) included in:
Unrealized gain (loss) recognized as a component of net income related to financial assets and liabilities		(22.8)		(45)		$ 18.4
Fair Value, Measurements, Recurring [Member]
Financial assets [Abstract]
Interest rate derivatives		0.1		36.5
Value before application of CME Rule 814		234.9
Impact of CME Rule 814 change		(73.2)
Total commodity derivatives		161.7		541.4
Financial assets		161.8		577.9
Financial liabilities [Abstract]
Liquidity option agreement		333.9		269.6
Interest rate derivatives		1.7		1.1
Commodity derivatives:
Value before application of CME Rule 814		390.7
Impact of CME Rule 814 change		(213.8)
Total commodity derivatives		176.9		739.4
Financial liabilities		512.5		1,010.1
Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Financial assets [Abstract]
Interest rate derivatives		0		0
Value before application of CME Rule 814		47.1
Impact of CME Rule 814 change		(47.1)
Total commodity derivatives		0		84.5
Financial assets		0		84.5
Financial liabilities [Abstract]
Liquidity option agreement		0		0
Interest rate derivatives		0		0
Commodity derivatives:
Value before application of CME Rule 814		118.4
Impact of CME Rule 814 change		(118.4)
Total commodity derivatives		0		136.8
Financial liabilities		0		136.8
Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Financial assets [Abstract]
Interest rate derivatives		0.1		36.5
Value before application of CME Rule 814		184.9
Impact of CME Rule 814 change		(26.1)
Total commodity derivatives		158.8		455.2
Financial assets		158.9		491.7
Financial liabilities [Abstract]
Liquidity option agreement		0		0
Interest rate derivatives		1.7		1.1
Commodity derivatives:
Value before application of CME Rule 814		270.6
Impact of CME Rule 814 change		(95.4)
Total commodity derivatives		175.2		602.3
Financial liabilities		176.9		603.4
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Financial assets [Abstract]
Interest rate derivatives		0		0
Value before application of CME Rule 814		2.9
Impact of CME Rule 814 change		0
Total commodity derivatives		2.9		1.7
Financial assets		2.9		1.7
Financial liabilities [Abstract]
Liquidity option agreement		333.9		269.6
Interest rate derivatives		0		0
Commodity derivatives:
Value before application of CME Rule 814		1.7
Impact of CME Rule 814 change		0
Total commodity derivatives		1.7		0.3
Financial liabilities		335.6		269.9
Reconciliation of changes in the fair value of Level 3 financial assets and liabilities [Roll Forward]
Financial liability balance, net, beginning of period		(268.2)	[1]	(246.7)
Total gains (losses) included in:
Transfers out of Level 3	[1]	(0.2)		1.8
Financial liability balance, net, end of period		(332.7)	[1]	(268.2)	[1]	$ (246.7)
Unrealized gain (loss) recognized as a component of net income related to financial assets and liabilities		(0.1)		1.7
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Other Comprehensive Income (Loss) [Member]
Total gains (losses) included in:
Other comprehensive income (loss)		0.1		(0.5)
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Revenue [Member]
Total gains (losses) included in:
Net income	[2]	2.3		2.2
Settlements	[2]	(2.4)		(0.5)
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Other Expense [Member]
Total gains (losses) included in:
Net income		$ (64.3)		$ (24.5)
[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, 2017 and 2016.
[2]	There were $0.1 million of unrealized losses and $1.7 million of unrealized gains included in these amounts for the years ended December 31, 2017 and 2016, respectively.

Derivative Instruments, Hedgi88

Derivative Instruments, Hedging Activities and Fair Value Measurements, Level 3 Recurring Valuation Techniques (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)$ / bbl	Dec. 31, 2016USD ($)$ / bbl
Asset commodity derivatives - Crude oil [Member] | Liability commodity derivatives - Crude oil [Member] | Level 3 [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair Value Measurements, Valuation Techniques	Discounted cash flow
Input description	Forward commodity prices
Asset commodity derivatives - Crude oil [Member] | Liability commodity derivatives - Crude oil [Member] | Level 3 [Member] | Minimum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, forward commodity price (in dollars per unit) | $ / bbl	60.21	51.73
Asset commodity derivatives - Crude oil [Member] | Liability commodity derivatives - Crude oil [Member] | Level 3 [Member] | Maximum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, forward commodity price (in dollars per unit) | $ / bbl	66.05	54.77
Fair Value, Measurements, Recurring [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Commodity asset derivatives	$ 161.7	$ 541.4
Commodity liability derivatives	176.9	739.4
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Commodity asset derivatives	2.9	1.7
Commodity liability derivatives	1.7	0.3
Fair Value, Measurements, Recurring [Member] | Liability commodity derivatives - Crude oil [Member] | Level 3 [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Commodity liability derivatives	1.7	0.3
Fair Value, Measurements, Recurring [Member] | Asset commodity derivatives - Crude oil [Member] | Level 3 [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Commodity asset derivatives	$ 2.9	$ 1.7

Derivative Instruments, Hedgi89

Derivative Instruments, Hedging Activities and Fair Value Measurements, Nonrecurring Fair Value Measurements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Asset Impairment Charges [Abstract]
Asset impairment and related charges	$ 49.8	$ 53.5	$ 162.6
Impairment of other current assets	12	1.2
Loss due to Pascagoula fire		7.1
Impairment of long-lived assets disposed of other than by sale	16.7	29.9	81.4
Impairment of long-lived assets held and used	15.4	2.2
Impairment of long-lived assets held for sale	2.5		14.2
Impairment of long-lived assets disposed of by sale	3.2	13.1	67
Impairment of long-lived assets	37.8	45.2	162.6
Offshore Business [Member]
Asset Impairment Charges [Abstract]
Impairment of long-lived assets disposed of by sale			54.8
Certain storage and pipeline assets in Texas [Member]
Asset Impairment Charges [Abstract]
Impairment of long-lived assets	12.4
Natural gas pipeline laterals and other pipelines in Texas [Member]
Asset Impairment Charges [Abstract]
Impairment of long-lived assets	13
NGL Pipelines and Services [Member]
Asset Impairment Charges [Abstract]
Impairment of long-lived assets	11.5	21	20.8
Crude Oil Pipelines & Services [Member]
Asset Impairment Charges [Abstract]
Impairment of long-lived assets	10.2	2.3	33.5
Natural Gas Pipelines & Services [Member]
Asset Impairment Charges [Abstract]
Impairment of long-lived assets	14.3	12.3	21.6
Petrochemical and Refined Products Services [Member]
Asset Impairment Charges [Abstract]
Impairment of long-lived assets	1.8	9.6	28.2
Offshore Pipelines And Services [Member]
Asset Impairment Charges [Abstract]
Impairment of long-lived assets	0	0	58.5
Fair Value, Measurements, Nonrecurring [Member] | Long-lived Assets Disposed of Other Than By Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value	0	0	0.4
Fair Value, Measurements, Nonrecurring [Member] | Long-lived Assets Held and Used [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value	1.5	8
Fair Value, Measurements, Nonrecurring [Member] | Long-lived Assets Held For Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value	2.5		18
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	8
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
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	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
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	0	0.4
Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Long-lived Assets Held and Used [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value	1.5	0
Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Long-lived Assets Held For Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value	2.5		18
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

Derivative Instruments, Hedgi90

Derivative Instruments, Hedging Activities and Fair Value Measurements, Other Fair Value Measurements (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Carrying Value [Member]
Financial Liabilities: [Abstract]
Fixed-rate debt obligations	$ 21,480	$ 20,850
Level 2 [Member] | Fair Value [Member]
Financial Liabilities: [Abstract]
Fixed-rate debt obligations	$ 23,470	$ 21,950

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues - related parties:
Total revenue - related parties	$ 45	$ 56.7	$ 72.3
Costs and expenses - related parties:
Operating costs and expenses	1,112.8	1,104	1,080.5
General and administrative expenses	121.5	113.1	114.1
Total costs and expenses - related parties	1,234.3	1,217.1	$ 1,194.6
Accounts receivable - related parties:
Total accounts receivable - related parties	1.8	1.1
Accounts payable - related parties:
Total accounts payable - related parties	$ 127.3	$ 105.1
At-the-Market Registration [Member]
Relationship with Affiliates [Abstract]
Number of common units issued (in units)	21,807,726	87,867,037	25,520,424
Gross proceeds from the sale of common units	$ 603.1	$ 2,170	$ 825.4
Distribution Reinvestment Plan [Member]
Relationship with Affiliates [Abstract]
Number of common units issued (in units)	18,541,355	15,809,503	12,413,351
EPCO and its privately held affiliates [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	$ 1,010.9	$ 963.2	$ 949.3
Accounts payable - related parties:
Total accounts payable - related parties	99.3	88.9
Distributions:
Total cash distributions	$ 1,120	$ 1,070	$ 948.3
Number of Designated Units excluded from distributions (in units)			35,380,000
Relationship with Affiliates [Abstract]
Number of Units (in units)	689,767,023
Percentage of Total Units Outstanding	32.00%
Enterprise common units pledged as security (in units)	81,346,154
EPCO and its privately held affiliates [Member] | At-the-Market Registration [Member]
Relationship with Affiliates [Abstract]
Number of common units issued (in units)		3,830,256	3,225,057
Gross proceeds from the sale of common units		$ 100	$ 100
EPCO and its privately held affiliates [Member] | Distribution Reinvestment Plan [Member]
Relationship with Affiliates [Abstract]
Number of common units issued (in units)	4,246,498
Gross proceeds from the sale of common units	$ 100	100	100
EPCO and its privately held affiliates [Member] | Administrative Services Agreement [Member]
Costs and expenses - related parties:
Operating costs and expenses	882.1	840.7	826.4
General and administrative expenses	110.4	105.3	105.2
Total costs and expenses - related parties	992.5	946	931.6
Unconsolidated affiliates [Member]
Revenues - related parties:
Total revenue - related parties	45	56.7	72.3
Costs and expenses - related parties:
Total costs and expenses - related parties	223.4	253.9	245.3
Accounts receivable - related parties:
Total accounts receivable - related parties	1.8	1.1
Accounts payable - related parties:
Total accounts payable - related parties	28	16.2
Unconsolidated affiliates [Member] | Seaway Crude Pipeline Company [Member]
Revenues - related parties:
Total revenue - related parties	19.6	36.3	47.7
Costs and expenses - related parties:
Total costs and expenses - related parties	98.8	161.2	175.8
Unconsolidated affiliates [Member] | K/D/S Promix, L.L.C. [Member]
Revenues - related parties:
Total revenue - related parties	7.8	7	8.8
Costs and expenses - related parties:
Total costs and expenses - related parties	27.8	27.1	24.9
Unconsolidated affiliates [Member] | Texas Express Pipeline LLC [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	29.5	22.8	6.7
Unconsolidated affiliates [Member] | Eagle Ford Pipeline LLC [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	42.8	36.2	39.4
Unconsolidated affiliates [Member] | Management/Operator Fees [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	$ (10.6)	$ (10.7)	$ (19.1)

Provision for Income Taxes (Det

Provision for Income Taxes (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current:
Federal		$ 0.1	$ (0.5)	$ 0.9
State		18.5	16.7	15.5
Foreign		1	0.6	1.7
Total current		19.6	16.8	18.1
Deferred:
Federal		(1.8)	1.1	(1.4)
State		7.9	5.2	(19.2)
Foreign		0	0.3	0
Total deferred		6.1	6.6	(20.6)
Total provision for (benefit from) income taxes		25.7	23.4	(2.5)
Reconciliation of the provision for (benefit from) income taxes [Abstract]
Pre-Tax Net Book Income ("NBI")		2,881.3	2,576.4	2,555.9
Texas Margin Tax	[1]	26.4	22.1	(3.7)
State income taxes (net of federal benefit)		0.5	0.2	0.7
Federal income taxes computed by applying the federal statutory rate to NBI of corporate entities		0.1	0.8	1.1
Other permanent differences		(1.3)	0.3	(0.6)
Total provision for (benefit from) income taxes		$ 25.7	$ 23.4	$ (2.5)
Effective income tax rate		0.90%	0.90%	(0.10%)
Deferred tax assets:
Net operating loss carryovers	[2]	$ 0.2	$ 0.2
Accruals		1.4	1.6
Total deferred tax assets		1.6	1.8
Less: Deferred tax liabilities:
Property, plant and equipment		58	50.5
Equity investment in partnerships		2.1	3.7
Total deferred tax liabilities		60.1	54.2
Total net deferred tax liabilities		$ 58.5	$ 52.4
[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 2018 and 2033 and are subject to limitations on their utilization.

Commitments and Contingencies93

Commitments and Contingencies (Details) bbl in Millions, $ in Millions, BTU in Trillions	12 Months Ended
	Dec. 31, 2017USD ($)BTUbbl	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Redelivery commitments:
Redelivery commitments of natural gas | BTU	9
Redelivery commitments of crude oil | bbl	15.8
Redelivery commitments of NGL and petrochemical products | bbl	39.3
Operating lease obligations:
Lease and rental expense included in costs and expenses	$ 103.6	$ 110.1	$ 104.3
Liabilities, Other than Long-term Debt, Noncurrent [Abstract]
Noncurrent portion of AROs	81.1	76.5
Deferred revenues - non-current portion	135.5	137
Liquidity option agreement	333.9	269.6
Derivative liabilities	10.4	2.8
Centennial guarantees	4.5	5.3
Other	13	12.7
Total	578.4	503.9
Junior Subordinated Note [Member]
Debt Instrument [Line Items]
Debt obligations	3,170
Centennial Pipeline LLC [Member]
Debt Instrument [Line Items]
Debt obligations	$ 50
Minimum [Member]
Operating lease obligations:
Term of material lease agreements	5 years
Maximum [Member]
Operating lease obligations:
Term of material lease agreements	30 years
Renewal option years for certain leases	20 years
Litigation matters [Member]
Loss Contingencies [Line Items]
Litigation accruals on an undiscounted basis	$ 4.5	$ 0.3
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				5.00%
Centennial debt guarantee [Member]
Guarantor Obligations [Line Items]
Percentage of debt obligations guaranteed	50.00%
Guarantee of debt obligations	$ 25
Fair value of debt guarantee	3.7
Centennial cash call guarantee [Member]
Guarantor Obligations [Line Items]
Cash call guarantee	50
Fair value of cash call guarantee	$ 1.6

Commitments and Contingencies,

Commitments and Contingencies, Contractual Obligations (Details) bbl in Millions, $ in Millions, BTU in Trillions	12 Months Ended
	Dec. 31, 2017USD ($)bblBTU	Dec. 31, 2016USD ($)
Scheduled maturities of debt obligations [Abstract]
2,018	$ 2,855.7
2,019	1,500
2,020	1,500
2,021	575
2,022	650
Thereafter	17,699.4
Total	24,780.1	$ 23,901.6
Estimated cash interest payments [Abstract]
2,018	1,082.9
2,019	1,022.1
2,020	964.2
2,021	912.1
2,022	884.7
Thereafter	19,076
Total	23,942
Operating lease obligations [Abstract]
2,018	57
2,019	52.8
2,020	47.2
2,021	40
2,022	31.3
Thereafter	185
Total	413.3
Natural Gas [Member]
Estimated payment obligations:
2,018	615.1
2,019	528.6
2,020	434.9
2,021	332.9
2,022	0
Thereafter	0
Total	$ 1,911.5
Underlying major volume commitments:
2018 | BTU	265
2019 | BTU	225
2020 | BTU	182
2021 | BTU	140
2022 | BTU	0
Thereafter | BTU	0
Total | BTU	812
NGLs [Member]
Estimated payment obligations:
2,018	$ 69.6
2,019	29.4
2,020	0
2,021	0
2,022	0
Thereafter	0
Total	$ 99
Underlying major volume commitments:
2018 | bbl	5
2019 | bbl	2
2020 | bbl	0
2021 | bbl	0
2022 | bbl	0
Thereafter | bbl	0
Total | bbl	7
Crude Oil [Member]
Estimated payment obligations:
2,018	$ 1,352.3
2,019	1,341
2,020	945.8
2,021	728.4
2,022	728.4
Thereafter	2,795.4
Total	$ 7,891.3
Underlying major volume commitments:
2018 | bbl	38
2019 | bbl	55
2020 | bbl	51
2021 | bbl	47
2022 | bbl	47
Thereafter | bbl	233
Total | bbl	471
Petrochemicals And Refined Products [Member]
Estimated payment obligations:
2,018	$ 411.9
2,019	214.1
2,020	6.1
2,021	0
2,022	0
Thereafter	0
Total	$ 632.1
Underlying major volume commitments:
2018 | bbl	7
2019 | bbl	4
2020 | bbl	0
2021 | bbl	0
2022 | bbl	0
Thereafter | bbl	0
Total | bbl	11
Estimated Payment Obligations Other [Member]
Estimated payment obligations:
2,018	$ 9.3
2,019	9.3
2,020	7.6
2,021	3.5
2,022	1.4
Thereafter	2.2
Total	33.3
Service Payment Commitments [Member]
Estimated payment obligations:
2,018	98.3
2,019	84.5
2,020	60
2,021	44.8
2,022	43.1
Thereafter	67.3
Total	398
Capital Expenditure Commitments [Member]
Estimated payment obligations:
2,018	171.6
2,019	0
2,020	0
2,021	0
2,022	0
Thereafter	0
Total	171.6
EFS Midstream Contract with Producers [Member]
Contractual obligation [Line Items]
Contractual obligation	270
Capital expenditures to date	$ 151
Contract term	10 years

Commitments and Contingencies95

Commitments and Contingencies, Liquidity Option Agreement (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Line Items]
Federal corporate tax rate (in hundredths)		35.00%
Liquidity Option Agreement [Abstract]
Change in fair value of Liquidity Option Agreement		$ 64.3	$ 24.5	$ 25.4
Percentage of capital stock we agreed to purchase under liquidity option agreement		100.00%
Liquidity Option exercise period		90 days
Percentage of fair market value of Enterprise units to be paid as consideration		100.00%
Trigger Event exercise period		135 days
Number of units held by limited partner (in units)		54,807,352
Liquidity Option Agreement [Member]
Liquidity Option Agreement [Abstract]
Increase in fair value of liquidity option agreement due to Tax Cuts and Jobs Act		$ 21.2
Increase in fair value of liquidity option agreement assuming retention of all units		40.2
Plan [Member]
Income Tax Disclosure [Line Items]
Federal corporate tax rate (in hundredths)	21.00%
Level 3 [Member]
Liquidity Option Agreement [Abstract]
Liquidity option agreement		$ 333.9	$ 269.6
Level 3 [Member] | Liquidity Option Agreement [Member]
Liquidity Option Agreement [Abstract]
Fair value inputs, Life of debt assumed after Liquidity option is exercised		30 years
Fair value inputs, federal and state tax rate		24.00%
Cash flow projections discount rate		7.60%
Fair value inputs, weighted-average expected ownership percentage of contributed units at beginning of option period		89.00%
Level 3 [Member] | Liquidity Option Agreement [Member] | Minimum [Member]
Liquidity Option Agreement [Abstract]
Fair value inputs, Expected life of OTA following option exercise		1 year
Fair value inputs, Estimated growth rates in Enterprise earnings before interest, taxes, depreciation and amortization		2.10%
Fair value inputs, OTA ownership interest in Enterprise common units		1.80%
Level 3 [Member] | Liquidity Option Agreement [Member] | Maximum [Member]
Liquidity Option Agreement [Abstract]
Fair value inputs, Expected life of OTA following option exercise		30 years
Fair value inputs, Estimated growth rates in Enterprise earnings before interest, taxes, depreciation and amortization		7.20%
Fair value inputs, OTA ownership interest in Enterprise common units		2.50%

Significant Risks and Uncerta96

Significant Risks and Uncertainties (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Insurance Matters [Abstract]
Insurance deductible per incident	$ 30
Minimum business interruption period	60 days
Named windstorm insurance coverage	$ 200

Supplemental Cash Flow Inform97

Supplemental Cash Flow Information (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Decrease (increase) in:
Accounts receivable - trade		$ (1,076.2)	$ (679)	$ 1,279.3
Accounts receivable - related parties		(0.7)	0.4	1.3
Inventories		194.6	(871.8)	(72.7)
Prepaid and other current assets		226	(49.3)	(59.1)
Other assets		(111)	(2)	(5.8)
Increase (decrease) in:
Accounts payable - trade		66.6	(21.5)	(52.9)
Accounts payable - related parties		56	21	(34.8)
Accrued product payables		952.3	1,193.3	(1,342.4)
Accrued interest		17.3	(11.4)	16.5
Other current liabilities		(291.4)	189.9	(67.1)
Other liabilities		(1.3)	49.5	14.4
Net effect of changes in operating accounts		32.2	(180.9)	(323.3)
Cash payments for interest, net of $192.1, $168.2 and $149.1 capitalized in 2017, 2016 and 2015, respectively		912.1	947.9	911.6
Capitalized interest	[1]	192.1	168.2	149.1
Cash payments for federal and state income taxes		20.9	18.7	17.5
Liability for construction in progress expenditures		373	124.3	472.8
Sale of Assets:
Proceeds from asset sales		40.1	46.5	1,608.6
Net gains (losses) attributable to asset sales		10.7	2.5	(15.6)
Business Acquisition [Line Items]
Cash paid to acquire business		198.7	1,000	1,056.5
Offshore Business [Member]
Sale of Assets:
Proceeds from asset sales		0	0	1,527.7
Net gains (losses) attributable to asset sales		0	0	(12.3)
Other Disposal of Assets [Member]
Sale of Assets:
Proceeds from asset sales		40.1	46.5	80.9
Net gains (losses) attributable to asset sales		$ 10.7	2.5	(3.3)
Eagle Ford Midstream Assets [Member]
Business Acquisition [Line Items]
Total consideration for acquisition				2,100
Cash paid to acquire business			$ 1,000	$ 1,100
[1]	Capitalized interest is a component of "Interest expense" as presented on our Statements of Consolidated Operations.

Quarterly Financial Informati98

Quarterly Financial Information (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Information (Unaudited) [Abstract]
Revenues	$ 8,426.6	$ 6,886.9	$ 6,607.6	$ 7,320.4	$ 6,478.8	$ 5,920.4	$ 5,617.8	$ 5,005.3	$ 29,241.5	$ 23,022.3	$ 27,027.9
Operating income	1,079.4	879.2	938.7	1,031.6	923.2	905	836.9	915.6	3,928.9	3,580.7	3,540.2
Net income	797.3	621.3	666	771	669.7	643.1	570	670.2	2,855.6	2,553	2,558.4
Net income attributable to limited partners	$ 774	$ 610.9	$ 653.7	$ 760.7	$ 658.8	$ 634.6	$ 558.5	$ 661.2	$ 2,799.3	$ 2,513.1	$ 2,521.2
Earnings per unit:
Basic earnings per unit (in dollars per unit)	$ 0.36	$ 0.28	$ 0.30	$ 0.36	$ 0.31	$ 0.30	$ 0.27	$ 0.32	$ 1.30	$ 1.20	$ 1.28
Diluted earnings per unit (in dollars per unit)	$ 0.36	$ 0.28	$ 0.30	$ 0.36	$ 0.31	$ 0.30	$ 0.27	$ 0.32	$ 1.30	$ 1.20	$ 1.26

Condensed Consolidating Finan99

Condensed Consolidating Financial Information, Balance Sheets (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash, cash equivalents and restricted cash	$ 70.3	$ 417.6	$ 34.9	$ 74.4
Accounts receivable - trade, net	4,358.4	3,329.5
Accounts receivable - related parties	1.8	1.1
Inventories	1,609.8	1,770.5
Derivative assets	153.4	541.4
Prepaid and other current assets	312.7	468.1
Total current assets	6,506.4	6,528.2
Property, plant and equipment, net	35,620.4	33,292.5	32,034.7
Investments in unconsolidated affiliates	2,659.4	2,677.3	2,628.5
Intangible assets, net	3,690.3	3,864.1	4,037.2
Goodwill	5,745.2	5,745.2	5,745.2	4,300.2
Other assets	196.4	86.7
Total assets	54,418.1	52,194
Current liabilities:
Current maturities of debt	2,855	2,576.8
Accounts payable - trade	801.7	397.7
Accounts payable - related parties	127.3	105.1
Accrued product payables	4,566.3	3,613.7
Accrued interest	358	340.8
Derivative liabilities	168.2	737.7
Other current liabilities	418.6	478.7
Total current liabilities	9,295.1	8,250.5
Long-term debt	21,713.7	21,120.9
Deferred tax liabilities	58.5	52.7
Other long-term liabilities	578.4	503.9
Commitments and contingencies
Equity:
Partners' and other owners' equity	22,547.2	22,047
Noncontrolling interests	225.2	219
Total equity	22,772.4	22,266	20,501.1	19,692.2
Total liabilities and equity	54,418.1	52,194
Eliminations and Adjustments [Member]
Current assets:
Cash, cash equivalents and restricted cash	0	0	0	0
Accounts receivable - trade, net	0	0
Accounts receivable - related parties	(1.3)	(1.1)
Inventories	0	0
Derivative assets	0	0
Prepaid and other current assets	0	0
Total current assets	(1.3)	(1.1)
Property, plant and equipment, net	0	0
Investments in unconsolidated affiliates	(22,881.5)	(22,317.1)
Intangible assets, net	0	0
Goodwill	0	0
Other assets	0	0
Total assets	(22,882.8)	(22,318.2)
Current liabilities:
Current maturities of debt	0	0
Accounts payable - trade	0	0
Accounts payable - related parties	(1.3)	(1.1)
Accrued product payables	0	0
Accrued interest	0	0
Derivative liabilities	0	0
Other current liabilities	0.4	0.7
Total current liabilities	(0.9)	(0.4)
Long-term debt	0	0
Deferred tax liabilities	2.1	3.7
Other long-term liabilities	0	0
Commitments and contingencies
Equity:
Partners' and other owners' equity	(22,853.1)	(22,291.8)
Noncontrolling interests	(30.9)	(29.7)
Total equity	(22,884)	(22,321.5)
Total liabilities and equity	(22,882.8)	(22,318.2)
Subsidiary Issuer (EPO) [Member]
Current assets:
Cash, cash equivalents and restricted cash	65.2	366.2	14.4	18.7
Accounts receivable - trade, net	1,382.3	1,499.4
Accounts receivable - related parties	110.3	131.5
Inventories	1,038.9	1,357.5
Derivative assets	110	464.8
Prepaid and other current assets	136.3	290.7
Total current assets	2,843	4,110.1
Property, plant and equipment, net	5,622.6	4,796.5
Investments in unconsolidated affiliates	41,616.6	39,995.5
Intangible assets, net	675.5	700.2
Goodwill	459.5	459.5
Other assets	296.4	222.6
Total assets	51,513.6	50,284.4
Current liabilities:
Current maturities of debt	2,854.6	2,576.7
Accounts payable - trade	290.2	133.1
Accounts payable - related parties	1,320.3	1,071.5
Accrued product payables	1,825.9	1,944.5
Accrued interest	358	340.7
Derivative liabilities	115.2	590.3
Other current liabilities	108.9	173.5
Total current liabilities	6,873.1	6,830.3
Long-term debt	21,699	21,105.7
Deferred tax liabilities	6.7	5
Other long-term liabilities	60.4	13.5
Commitments and contingencies
Equity:
Partners' and other owners' equity	22,874.4	22,329.9
Noncontrolling interests	0	0
Total equity	22,874.4	22,329.9
Total liabilities and equity	51,513.6	50,284.4
Other Subsidiaries (Non-guarantor) [Member]
Current assets:
Cash, cash equivalents and restricted cash	31.5	58.9	71.1	70.4
Accounts receivable - trade, net	2,976.6	1,830.3
Accounts receivable - related parties	1,182.1	961.4
Inventories	572.3	413.5
Derivative assets	43.4	76.6
Prepaid and other current assets	189	191.1
Total current assets	4,994.9	3,531.8
Property, plant and equipment, net	29,996.3	28,495.7
Investments in unconsolidated affiliates	4,298	4,227.9
Intangible assets, net	3,028.6	3,178.2
Goodwill	5,285.7	5,285.7
Other assets	110	41
Total assets	47,713.5	44,760.3
Current liabilities:
Current maturities of debt	0.4	0.1
Accounts payable - trade	537.8	272.1
Accounts payable - related parties	112	139.6
Accrued product payables	2,741.7	1,670.3
Accrued interest	0	0.1
Derivative liabilities	53	147.4
Other current liabilities	320.1	316.5
Total current liabilities	3,765	2,546.1
Long-term debt	14.7	15.2
Deferred tax liabilities	50.2	45.1
Other long-term liabilities	396.5	400.6
Commitments and contingencies
Equity:
Partners' and other owners' equity	43,412	41,675.3
Noncontrolling interests	75.1	78
Total equity	43,487.1	41,753.3
Total liabilities and equity	47,713.5	44,760.3
Consolidated EPO and Subsidiaries [Member]
Current assets:
Cash, cash equivalents and restricted cash	70.3	417.6	34.9	74.4
Accounts receivable - trade, net	4,358.4	3,329.5
Accounts receivable - related parties	3.1	2.2
Inventories	1,609.8	1,770.5
Derivative assets	153.4	541.4
Prepaid and other current assets	312.7	468.1
Total current assets	6,507.7	6,529.3
Property, plant and equipment, net	35,620.4	33,292.5
Investments in unconsolidated affiliates	2,659.4	2,677.3
Intangible assets, net	3,690.3	3,864.1
Goodwill	5,745.2	5,745.2
Other assets	195.4	86.1
Total assets	54,418.4	52,194.5
Current liabilities:
Current maturities of debt	2,855	2,576.8
Accounts payable - trade	801.6	397.7
Accounts payable - related parties	127.3	105.1
Accrued product payables	4,566.3	3,613.7
Accrued interest	358	340.8
Derivative liabilities	168.2	737.7
Other current liabilities	418.2	478
Total current liabilities	9,294.6	8,249.8
Long-term debt	21,713.7	21,120.9
Deferred tax liabilities	56.4	49
Other long-term liabilities	244.5	234.3
Commitments and contingencies
Equity:
Partners' and other owners' equity	22,853.1	22,291.8
Noncontrolling interests	256.1	248.7
Total equity	23,109.2	22,540.5
Total liabilities and equity	54,418.4	52,194.5
Consolidated EPO and Subsidiaries [Member] | Eliminations and Adjustments [Member]
Current assets:
Cash, cash equivalents and restricted cash	(26.4)	(7.5)	(50.6)	(14.7)
Accounts receivable - trade, net	(0.5)	(0.2)
Accounts receivable - related parties	(1,289.3)	(1,090.7)
Inventories	(1.4)	(0.5)
Derivative assets	0	0
Prepaid and other current assets	(12.6)	(13.7)
Total current assets	(1,330.2)	(1,112.6)
Property, plant and equipment, net	1.5	0.3
Investments in unconsolidated affiliates	(43,255.2)	(41,546.1)
Intangible assets, net	(13.8)	(14.3)
Goodwill	0	0
Other assets	(211)	(177.5)
Total assets	(44,808.7)	(42,850.2)
Current liabilities:
Current maturities of debt	0	0
Accounts payable - trade	(26.4)	(7.5)
Accounts payable - related parties	(1,305)	(1,106)
Accrued product payables	(1.3)	(1.1)
Accrued interest	0	0
Derivative liabilities	0	0
Other current liabilities	(10.8)	(12)
Total current liabilities	(1,343.5)	(1,126.6)
Long-term debt	0	0
Deferred tax liabilities	(0.5)	(1.1)
Other long-term liabilities	(212.4)	(179.8)
Commitments and contingencies
Equity:
Partners' and other owners' equity	(43,433.3)	(41,713.4)
Noncontrolling interests	181	170.7
Total equity	(43,252.3)	(41,542.7)
Total liabilities and equity	(44,808.7)	(42,850.2)
Enterprise Products Partners L.P. (Guarantor) [Member]
Current assets:
Cash, cash equivalents and restricted cash	0	0	$ 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	22,881.5	22,317.1
Intangible assets, net	0	0
Goodwill	0	0
Other assets	1	0.6
Total assets	22,882.5	22,317.7
Current liabilities:
Current maturities of debt	0	0
Accounts payable - trade	0.1	0
Accounts payable - related parties	1.3	1.1
Accrued product payables	0	0
Accrued interest	0	0
Derivative liabilities	0	0
Other current liabilities	0	0
Total current liabilities	1.4	1.1
Long-term debt	0	0
Deferred tax liabilities	0	0
Other long-term liabilities	333.9	269.6
Commitments and contingencies
Equity:
Partners' and other owners' equity	22,547.2	22,047
Noncontrolling interests	0	0
Total equity	22,547.2	22,047
Total liabilities and equity	$ 22,882.5	$ 22,317.7

Condensed Consolidating Fina100

Condensed Consolidating Financial Information, Statements of Operations (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Condensed Consolidating Statement of Operations
Revenues	$ 8,426.6	$ 6,886.9	$ 6,607.6	$ 7,320.4	$ 6,478.8	$ 5,920.4	$ 5,617.8	$ 5,005.3	$ 29,241.5	$ 23,022.3	$ 27,027.9
Costs and expenses:
Operating costs and expenses									25,557.5	19,643.5	23,668.7
General and administrative costs									181.1	160.1	192.6
Total costs and expenses									25,738.6	19,803.6	23,861.3
Equity in income of unconsolidated affiliates									426	362	373.6
Operating income	1,079.4	879.2	938.7	1,031.6	923.2	905	836.9	915.6	3,928.9	3,580.7	3,540.2
Other income (expense):
Interest expense									(984.6)	(982.6)	(961.8)
Other, net									(63)	(21.7)	(22.5)
Total other expense, net									(1,047.6)	(1,004.3)	(984.3)
Income before income taxes									2,881.3	2,576.4	2,555.9
Benefit from (provision for) income taxes									(25.7)	(23.4)	2.5
Net income	797.3	621.3	666	771	669.7	643.1	570	670.2	2,855.6	2,553	2,558.4
Net income attributable to noncontrolling interests									(56.3)	(39.9)	(37.2)
Net income attributable to limited partners	$ 774	$ 610.9	$ 653.7	$ 760.7	$ 658.8	$ 634.6	$ 558.5	$ 661.2	2,799.3	2,513.1	2,521.2
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									(2,865.4)	(2,539.9)	(2,548.7)
Operating income									(2,865.4)	(2,539.9)	(2,548.7)
Other income (expense):
Interest expense									0	0	0
Other, net									0	0	0
Total other expense, net									0	0	0
Income before income taxes									(2,865.4)	(2,539.9)	(2,548.7)
Benefit from (provision for) income taxes									0	(2.1)	(1.5)
Net income									(2,865.4)	(2,542)	(2,550.2)
Net income attributable to noncontrolling interests									5.3	5.3	4.8
Net income attributable to limited partners									(2,860.1)	(2,536.7)	(2,545.4)
Subsidiary Issuer (EPO) [Member]
Condensed Consolidating Statement of Operations
Revenues									40,696.8	28,958.7	20,104.8
Costs and expenses:
Operating costs and expenses									39,809.6	28,108.2	19,283.7
General and administrative costs									31.4	22.5	38.2
Total costs and expenses									39,841	28,130.7	19,321.9
Equity in income of unconsolidated affiliates									2,990.1	2,686.1	2,718.4
Operating income									3,845.9	3,514.1	3,501.3
Other income (expense):
Interest expense									(982.5)	(973.1)	(952.9)
Other, net									9.2	8.3	5.2
Total other expense, net									(973.3)	(964.8)	(947.7)
Income before income taxes									2,872.6	2,549.3	2,553.6
Benefit from (provision for) income taxes									(12)	(13.1)	(8.7)
Net income									2,860.6	2,536.2	2,544.9
Net income attributable to noncontrolling interests									0	0	0
Net income attributable to limited partners									2,860.6	2,536.2	2,544.9
Other Subsidiaries (Non-guarantor) [Member]
Condensed Consolidating Statement of Operations
Revenues									18,451.2	15,296.8	19,087
Costs and expenses:
Operating costs and expenses									15,654.9	12,768.9	16,549.3
General and administrative costs									148	135.3	152.3
Total costs and expenses									15,802.9	12,904.2	16,701.6
Equity in income of unconsolidated affiliates									566.8	521.7	417.5
Operating income									3,215.1	2,914.3	2,802.9
Other income (expense):
Interest expense									(11.8)	(17.3)	(12)
Other, net									1.8	2.3	0.8
Total other expense, net									(10)	(15)	(11.2)
Income before income taxes									3,205.1	2,899.3	2,791.7
Benefit from (provision for) income taxes									(13.7)	(8.2)	12.7
Net income									3,191.4	2,891.1	2,804.4
Net income attributable to noncontrolling interests									(6.5)	(7.4)	0.9
Net income attributable to limited partners									3,184.9	2,883.7	2,805.3
Consolidated EPO and Subsidiaries [Member]
Condensed Consolidating Statement of Operations
Revenues									29,241.5	23,022.3	27,027.9
Costs and expenses:
Operating costs and expenses									25,557.5	19,643.5	23,668.7
General and administrative costs									179.3	157.8	190.5
Total costs and expenses									25,736.8	19,801.3	23,859.2
Equity in income of unconsolidated affiliates									426	362	373.6
Operating income									3,930.7	3,583	3,542.3
Other income (expense):
Interest expense									(984.6)	(982.6)	(961.8)
Other, net									1.3	2.8	2.9
Total other expense, net									(983.3)	(979.8)	(958.9)
Income before income taxes									2,947.4	2,603.2	2,583.4
Benefit from (provision for) income taxes									(25.7)	(21.3)	4
Net income									2,921.7	2,581.9	2,587.4
Net income attributable to noncontrolling interests									(61.6)	(45.2)	(42)
Net income attributable to limited partners									2,860.1	2,536.7	2,545.4
Consolidated EPO and Subsidiaries [Member] | Eliminations and Adjustments [Member]
Condensed Consolidating Statement of Operations
Revenues									(29,906.5)	(21,233.2)	(12,163.9)
Costs and expenses:
Operating costs and expenses									(29,907)	(21,233.6)	(12,164.3)
General and administrative costs									(0.1)	0	0
Total costs and expenses									(29,907.1)	(21,233.6)	(12,164.3)
Equity in income of unconsolidated affiliates									(3,130.9)	(2,845.8)	(2,762.3)
Operating income									(3,130.3)	(2,845.4)	(2,761.9)
Other income (expense):
Interest expense									9.7	7.8	3.1
Other, net									(9.7)	(7.8)	(3.1)
Total other expense, net									0	0	0
Income before income taxes									(3,130.3)	(2,845.4)	(2,761.9)
Benefit from (provision for) income taxes									0	0	0
Net income									(3,130.3)	(2,845.4)	(2,761.9)
Net income attributable to noncontrolling interests									(55.1)	(37.8)	(42.9)
Net income attributable to limited partners									(3,185.4)	(2,883.2)	(2,804.8)
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									1.8	2.3	2.1
Total costs and expenses									1.8	2.3	2.1
Equity in income of unconsolidated affiliates									2,865.4	2,539.9	2,548.7
Operating income									2,863.6	2,537.6	2,546.6
Other income (expense):
Interest expense									0	0	0
Other, net									(64.3)	(24.5)	(25.4)
Total other expense, net									(64.3)	(24.5)	(25.4)
Income before income taxes									2,799.3	2,513.1	2,521.2
Benefit from (provision for) income taxes									0	0	0
Net income									2,799.3	2,513.1	2,521.2
Net income attributable to noncontrolling interests									0	0	0
Net income attributable to limited partners									$ 2,799.3	$ 2,513.1	$ 2,521.2

Condensed Consolidating Fina101

Condensed Consolidating Financial Information, Statements of Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Condensed Consolidating Statement of Comprehensive Income
Comprehensive income	$ 2,963.9	$ 2,492.2	$ 2,580.8
Comprehensive loss (income) attributable to noncontrolling interests	(56.3)	(39.9)	(37.2)
Comprehensive income attributable to entity	2,907.6	2,452.3	2,543.6
Eliminations and Adjustments [Member]
Condensed Consolidating Statement of Comprehensive Income
Comprehensive income	(2,973.8)	(2,481.1)	(2,572.6)
Comprehensive loss (income) attributable to noncontrolling interests	5.3	5.3	4.8
Comprehensive income attributable to entity	(2,968.5)	(2,475.8)	(2,567.8)
Subsidiary Issuer (EPO) [Member]
Condensed Consolidating Statement of Comprehensive Income
Comprehensive income	2,951.7	2,544.3	2,578.6
Comprehensive loss (income) attributable to noncontrolling interests	0	0	0
Comprehensive income attributable to entity	2,951.7	2,544.3	2,578.6
Other Subsidiaries (Non-guarantor) [Member]
Condensed Consolidating Statement of Comprehensive Income
Comprehensive income	3,208.6	2,822.1	2,793.1
Comprehensive loss (income) attributable to noncontrolling interests	(6.5)	(7.4)	0.9
Comprehensive income attributable to entity	3,202.1	2,814.7	2,794
Consolidated EPO and Subsidiaries [Member]
Condensed Consolidating Statement of Comprehensive Income
Comprehensive income	3,030.1	2,521.1	2,609.8
Comprehensive loss (income) attributable to noncontrolling interests	(61.6)	(45.2)	(42)
Comprehensive income attributable to entity	2,968.5	2,475.9	2,567.8
Consolidated EPO and Subsidiaries [Member] | Eliminations and Adjustments [Member]
Condensed Consolidating Statement of Comprehensive Income
Comprehensive income	(3,130.2)	(2,845.3)	(2,761.9)
Comprehensive loss (income) attributable to noncontrolling interests	(55.1)	(37.8)	(42.9)
Comprehensive income attributable to entity	(3,185.3)	(2,883.1)	(2,804.8)
Enterprise Products Partners L.P. (Guarantor) [Member]
Condensed Consolidating Statement of Comprehensive Income
Comprehensive income	2,907.6	2,452.2	2,543.6
Comprehensive loss (income) attributable to noncontrolling interests	0	0	0
Comprehensive income attributable to entity	$ 2,907.6	$ 2,452.2	$ 2,543.6

Condensed Consolidating Fina102

Condensed Consolidating Financial Information, Statements of Cash Flows (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating activities:
Net income	$ 797.3	$ 621.3	$ 666	$ 771	$ 669.7	$ 643.1	$ 570	$ 670.2	$ 2,855.6	$ 2,553	$ 2,558.4
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion									1,644	1,552	1,516
Equity in income of unconsolidated affiliates									(426)	(362)	(373.6)
Distributions received on earnings from unconsolidated affiliates									433.7	380.5	462.1
Net effect of changes in operating accounts and other operating activities									159	(56.7)	(160.5)
Net cash flows provided by operating activities									4,666.3	4,066.8	4,002.4
Investing activities:
Capital expenditures, net of contributions in aid of construction costs									(3,101.8)	(2,984.1)	(3,811.6)
Cash used for business combinations, net of cash received									(198.7)	(1,000)	(1,056.5)
Proceeds from asset sales and insurance recoveries									40.1	46.5	1,608.6
Other investing activities									(25.7)	(68.2)	(166.4)
Cash used in investing activities									(3,286.1)	(4,005.8)	(3,425.9)
Financing activities:
Borrowings under debt agreements									69,315.3	62,813.9	21,081.1
Repayments of debt									(68,459.6)	(61,672.6)	(19,867.2)
Cash distributions paid to owners									(3,569.9)	(3,300.5)	(2,943.7)
Cash payments made in connection with DERs									(15.1)	(11.7)	(7.7)
Cash distributions paid to noncontrolling interests									(49.2)	(47.4)	(48)
Cash contributions from noncontrolling interests									0.4	20.4	54
Net cash proceeds from the issuance of common units									1,073.4	2,542.8	1,188.6
Cash contributions from owners									0	0	0
Other financing activities									(22.8)	(23.2)	(73.1)
Cash provided by (used in) financing activities									(1,727.5)	321.7	(616)
Net change in cash and cash equivalents									(347.3)	382.7	(39.5)
Cash, cash equivalents and restricted cash, January 1				417.6				34.9	417.6	34.9	74.4
Cash, cash equivalents and restricted cash, December 31	70.3				417.6				70.3	417.6	34.9
Eliminations and Adjustments [Member]
Operating activities:
Net income									(2,865.4)	(2,542)	(2,550.2)
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									2,865.4	2,539.9	2,548.7
Distributions received on earnings from unconsolidated affiliates									(3,574.6)	(3,331.2)	(3,000.2)
Net effect of changes in operating accounts and other operating activities									(1)	1.2	1.5
Net cash flows provided by operating activities									(3,575.6)	(3,332.1)	(3,000.2)
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	0
Proceeds from asset sales and insurance recoveries									0	0	0
Other investing activities									1,060.5	2,530.9	1,179.8
Cash used in investing activities									1,060.5	2,530.9	1,179.8
Financing activities:
Borrowings under debt agreements									0	0	0
Repayments of debt									0	0	0
Cash distributions paid to owners									3,574.6	3,331.2	3,000.2
Cash payments made in connection with DERs									0	0	0
Cash distributions paid to noncontrolling interests									1	0.9	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									(1,060.5)	(2,530.9)	(1,179.8)
Other financing activities									0	0	0
Cash provided by (used in) financing activities									2,515.1	801.2	1,820.4
Net change in cash and cash equivalents									0	0	0
Cash, cash equivalents and restricted cash, January 1				0				0	0	0	0
Cash, cash equivalents and restricted cash, December 31	0				0				0	0	0
Subsidiary Issuer (EPO) [Member]
Operating activities:
Net income									2,860.6	2,536.2	2,544.9
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion									216.6	185.4	144.9
Equity in income of unconsolidated affiliates									(2,990.1)	(2,686.1)	(2,718.4)
Distributions received on earnings from unconsolidated affiliates									1,162.8	1,127.3	1,989.6
Net effect of changes in operating accounts and other operating activities									2,812.2	2,448.6	882.8
Net cash flows provided by operating activities									4,062.1	3,611.4	2,843.8
Investing activities:
Capital expenditures, net of contributions in aid of construction costs									(846.8)	(1,327.4)	(1,180)
Cash used for business combinations, net of cash received									(7.3)	0	(1,069.9)
Proceeds from asset sales and insurance recoveries									17	28.8	1,531.3
Other investing activities									(1,908.5)	(2,301.9)	(1,499)
Cash used in investing activities									(2,745.6)	(3,600.5)	(2,217.6)
Financing activities:
Borrowings under debt agreements									69,349.3	62,813.9	21,081.1
Repayments of debt									(68,459.5)	(61,672.5)	(19,867.2)
Cash distributions paid to owners									(3,574.6)	(3,331.2)	(3,000.2)
Cash payments made in connection with DERs									0	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									1,060.5	2,530.9	1,179.8
Other financing activities									6.8	(0.2)	(24)
Cash provided by (used in) financing activities									(1,617.5)	340.9	(630.5)
Net change in cash and cash equivalents									(301)	351.8	(4.3)
Cash, cash equivalents and restricted cash, January 1				366.2				14.4	366.2	14.4	18.7
Cash, cash equivalents and restricted cash, December 31	65.2				366.2				65.2	366.2	14.4
Other Subsidiaries (Non-guarantor) [Member]
Operating activities:
Net income									3,191.4	2,891.1	2,804.4
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion									1,427.8	1,367	1,371.5
Equity in income of unconsolidated affiliates									(566.8)	(521.7)	(417.5)
Distributions received on earnings from unconsolidated affiliates									272.7	265.9	307.7
Net effect of changes in operating accounts and other operating activities									(2,726.3)	(2,568.5)	(1,031)
Net cash flows provided by operating activities									1,598.8	1,433.8	3,035.1
Investing activities:
Capital expenditures, net of contributions in aid of construction costs									(2,255)	(1,656.7)	(2,631.6)
Cash used for business combinations, net of cash received									(191.4)	(1,000)	13.4
Proceeds from asset sales and insurance recoveries									23.1	17.7	77.3
Other investing activities									(28)	(63.2)	(1,246.7)
Cash used in investing activities									(2,451.3)	(2,702.2)	(3,787.6)
Financing activities:
Borrowings under debt agreements									0	41.8	133.9
Repayments of debt									(0.1)	(0.1)	0
Cash distributions paid to owners									(1,065.3)	(1,089.6)	(1,882.4)
Cash payments made in connection with DERs									0	0	0
Cash distributions paid to noncontrolling interests									(9.6)	(8.5)	(0.8)
Cash contributions from noncontrolling interests									0.1	20.4	54.4
Net cash proceeds from the issuance of common units									0	0	0
Cash contributions from owners									1,900	2,292.2	2,445
Other financing activities									0	0	3.1
Cash provided by (used in) financing activities									825.1	1,256.2	753.2
Net change in cash and cash equivalents									(27.4)	(12.2)	0.7
Cash, cash equivalents and restricted cash, January 1				58.9				71.1	58.9	71.1	70.4
Cash, cash equivalents and restricted cash, December 31	31.5				58.9				31.5	58.9	71.1
Consolidated EPO and Subsidiaries [Member]
Operating activities:
Net income									2,921.7	2,581.9	2,587.4
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion									1,644	1,552	1,516
Equity in income of unconsolidated affiliates									(426)	(362)	(373.6)
Distributions received on earnings from unconsolidated affiliates									433.7	380.5	462.1
Net effect of changes in operating accounts and other operating activities									66.8	(76.8)	(184.1)
Net cash flows provided by operating activities									4,640.2	4,075.6	4,007.8
Investing activities:
Capital expenditures, net of contributions in aid of construction costs									(3,101.8)	(2,984.1)	(3,811.6)
Cash used for business combinations, net of cash received									(198.7)	(1,000)	(1,056.5)
Proceeds from asset sales and insurance recoveries									40.1	46.5	1,608.6
Other investing activities									(25.7)	(68.2)	(166.4)
Cash used in investing activities									(3,286.1)	(4,005.8)	(3,425.9)
Financing activities:
Borrowings under debt agreements									69,315.3	62,813.9	21,081.1
Repayments of debt									(68,459.6)	(61,672.6)	(19,867.2)
Cash distributions paid to owners									(3,574.6)	(3,331.2)	(3,000.2)
Cash payments made in connection with DERs									0	0	0
Cash distributions paid to noncontrolling interests									(50.2)	(48.3)	(48)
Cash contributions from noncontrolling interests									0.4	20.4	54
Net cash proceeds from the issuance of common units									0	0	0
Cash contributions from owners									1,060.5	2,530.9	1,179.8
Other financing activities									6.8	(0.2)	(20.9)
Cash provided by (used in) financing activities									(1,701.4)	312.9	(621.4)
Net change in cash and cash equivalents									(347.3)	382.7	(39.5)
Cash, cash equivalents and restricted cash, January 1				417.6				34.9	417.6	34.9	74.4
Cash, cash equivalents and restricted cash, December 31	70.3				417.6				70.3	417.6	34.9
Consolidated EPO and Subsidiaries [Member] | Eliminations and Adjustments [Member]
Operating activities:
Net income									(3,130.3)	(2,845.4)	(2,761.9)
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion									(0.4)	(0.4)	(0.4)
Equity in income of unconsolidated affiliates									3,130.9	2,845.8	2,762.3
Distributions received on earnings from unconsolidated affiliates									(1,001.8)	(1,012.7)	(1,835.2)
Net effect of changes in operating accounts and other operating activities									(19.1)	43.1	(35.9)
Net cash flows provided by operating activities									(1,020.7)	(969.6)	(1,871.1)
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	0
Proceeds from asset sales and insurance recoveries									0	0	0
Other investing activities									1,910.8	2,296.9	2,579.3
Cash used in investing activities									1,910.8	2,296.9	2,579.3
Financing activities:
Borrowings under debt agreements									(34)	(41.8)	(133.9)
Repayments of debt									0	0	0
Cash distributions paid to owners									1,065.3	1,089.6	1,882.4
Cash payments made in connection with DERs									0	0	0
Cash distributions paid to noncontrolling interests									(40.6)	(39.8)	(47.2)
Cash contributions from noncontrolling interests									0.3	0	(0.4)
Net cash proceeds from the issuance of common units									0	0	0
Cash contributions from owners									(1,900)	(2,292.2)	(2,445)
Other financing activities									0	0	0
Cash provided by (used in) financing activities									(909)	(1,284.2)	(744.1)
Net change in cash and cash equivalents									(18.9)	43.1	(35.9)
Cash, cash equivalents and restricted cash, January 1				(7.5)				(50.6)	(7.5)	(50.6)	(14.7)
Cash, cash equivalents and restricted cash, December 31	(26.4)				(7.5)				(26.4)	(7.5)	(50.6)
Enterprise Products Partners L.P. (Guarantor) [Member]
Operating activities:
Net income									2,799.3	2,513.1	2,521.2
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									(2,865.4)	(2,539.9)	(2,548.7)
Distributions received on earnings from unconsolidated affiliates									3,574.6	3,331.2	3,000.2
Net effect of changes in operating accounts and other operating activities									93.2	18.9	22.1
Net cash flows provided by operating activities									3,601.7	3,323.3	2,994.8
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	0
Proceeds from asset sales and insurance recoveries									0	0	0
Other investing activities									(1,060.5)	(2,530.9)	(1,179.8)
Cash used in investing activities									(1,060.5)	(2,530.9)	(1,179.8)
Financing activities:
Borrowings under debt agreements									0	0	0
Repayments of debt									0	0	0
Cash distributions paid to owners									(3,569.9)	(3,300.5)	(2,943.7)
Cash payments made in connection with DERs									(15.1)	(11.7)	(7.7)
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									1,073.4	2,542.8	1,188.6
Cash contributions from owners									0	0	0
Other financing activities									(29.6)	(23)	(52.2)
Cash provided by (used in) financing activities									(2,541.2)	(792.4)	(1,815)
Net change in cash and cash equivalents									0	0	0
Cash, cash equivalents and restricted cash, January 1				$ 0				$ 0	0	0	0
Cash, cash equivalents and restricted cash, December 31	$ 0				$ 0				$ 0	$ 0	$ 0

Subsequent Event (Details)

Subsequent Event (Details) - USD ($) $ in Millions		1 Months Ended		12 Months Ended
		Mar. 30, 2018	Feb. 15, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Debt Obligations [Abstract]
Repayment of debt obligations				$ 68,459.6	$ 61,672.6	$ 19,867.2
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes B [Member]
Debt Obligations [Abstract]
Maturity date				Jan. 15, 2068
Interest rate terms				fixed/variable
Interest rate, stated percentage	[1]			7.034%
Variable annual interest rate thereafter, variable rate basis	[2]			3-month LIBOR
Variable interest rate	[2]			2.68%
Forecast [Member] | Junior Debt Obligations [Member]
Debt Obligations [Abstract]
Estimated annual interest expense savings		$ 11.3
Forecast [Member] | Junior Debt Obligations [Member] | EPO Junior Subordinated Notes B [Member]
Debt Obligations [Abstract]
Repayment of debt obligations		$ 682.7
Subsequent Event [Member]
Debt Obligations [Abstract]
Aggregate debt principal issued			$ 2,700
Subsequent Event [Member] | Senior Debt Obligations [Member]
Debt Obligations [Abstract]
Aggregate debt principal issued			2,000
Subsequent Event [Member] | Senior Debt Obligations [Member] | EPO Senior Notes TT [Member]
Debt Obligations [Abstract]
Aggregate debt principal issued			$ 750
Maturity date			Feb. 15, 2021
Interest rate terms			fixed
Interest rate, stated percentage			2.80%
Debt issued as percent of principal amount			99.946%
Subsequent Event [Member] | Senior Debt Obligations [Member] | EPO Senior Notes UU [Member]
Debt Obligations [Abstract]
Aggregate debt principal issued			$ 1,250
Maturity date			Feb. 15, 2048
Interest rate terms			fixed
Interest rate, stated percentage			4.25%
Debt issued as percent of principal amount			99.865%
Subsequent Event [Member] | Junior Debt Obligations [Member]
Debt Obligations [Abstract]
Aggregate debt principal issued			$ 700
Subsequent Event [Member] | Junior Debt Obligations [Member] | EPO Junior Subordinated Notes F [Member]
Debt Obligations [Abstract]
Aggregate debt principal issued			$ 700
Maturity date			Feb. 15, 2078
Interest rate terms			fixed/variable
Interest rate, stated percentage			5.375%
Variable annual interest rate thereafter, variable rate basis			3-month LIBOR
Variable interest rate			2.57%
Debt issued as percent of principal amount			100.00%
[1]	Interest was payable semi-annually in arrears in January and July of each year, which commenced in January 2008.
[2]	Interest was payable quarterly in arrears in January, April, July and October of each year commencing in April 2018.