Enterprise Products Partners (EPD) 10-K 27 Feb 20 2019 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Jan. 31, 2020	Jun. 28, 2019
Cover [Abstract]
Document Type	10-K
Amendment Flag	false
Document Annual Report	true
Document Period End Date	Dec. 31, 2019
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity Registrant Name	ENTERPRISE PRODUCTS PARTNERS L.P.
Entity Incorporation, State or Country Code	DE
Entity File Number	1-14323
Entity Tax Identification Number	76-0568219
Entity Address, Address Line One	1100 Louisiana Street, 10th Floor
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002
City Area Code	713
Local Phone Number	381-6500
Entity Filer Category	Large Accelerated Filer
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Small Business	false
Entity Common Stock, Shares Outstanding		2,189,226,130
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Entity Central Index Key	0001061219
Title of 12(b) Security	Common Units
Trading Symbol	EPD
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Public Float			$ 43,040

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 334.7	$ 344.8
Restricted cash	75.3	65.3
Accounts receivable - trade, net of allowance for doubtful accounts of $12.4 at December 31, 2019 and $11.5 at December 31, 2018	4,873.6	3,659.1
Accounts receivable - related parties	2.5	3.5
Inventories	2,091.4	1,522.1
Derivative assets	127.2	154.4
Prepaid and other current assets	358.2	311.5
Total current assets	7,862.9	6,060.7
Property, plant and equipment, net	41,603.4	38,737.6
Investments in unconsolidated affiliates	2,600.2	2,615.1
Intangible assets, net of accumulated amortization of $1,687.5 at December 31, 2019 and $1,735.1 at December 31, 2018	3,449	3,608.4
Goodwill	5,745.2	5,745.2
Other assets	472.5	202.8
Total assets	61,733.2	56,969.8
Current liabilities:
Current maturities of debt	1,981.9	1,500.1
Accounts payable - trade	1,004.5	1,102.8
Accounts payable - related parties	162.3	140.2
Accrued product payables	4,915.7	3,475.8
Accrued interest	431.7	395.6
Derivative liabilities	122.4	148.2
Other current liabilities	511.2	404.8
Total current liabilities	9,129.7	7,167.5
Long-term debt	25,643.2	24,678.1
Deferred tax liabilities	100.4	80.4
Other long-term liabilities	1,032.4	751.6
Commitments and contingencies
Limited partners:
Common units (2,189,226,130 units issued and outstanding at December 31, 2019 and 2,184,869,029 units issued and outstanding at December 31, 2018)	24,692.6	23,802.6
Accumulated other comprehensive income	71.4	50.9
Total partners' equity	24,764	23,853.5
Noncontrolling interests	1,063.5	438.7
Total equity	25,827.5	24,292.2
Total liabilities and equity	$ 61,733.2	$ 56,969.8

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
ASSETS
Accounts receivable, allowance for doubtful accounts	$ 12.4	$ 11.5
Intangible assets, accumulated amortization	$ 1,687.5	$ 1,735.1
Limited partners:
Common units outstanding (in units)	2,189,226,130	2,184,869,029

STATEMENTS OF CONSOLIDATED OPER

STATEMENTS OF CONSOLIDATED OPERATIONS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Revenues:
Third parties	$ 32,721.9		$ 36,426.5		$ 29,196.5
Related parties	67.3		107.7		45
Total revenues	32,789.2	[1]	36,534.2	[1]	29,241.5	[2]
Operating costs and expenses:
Third parties	25,649.8		29,991.2		24,444.7
Related parties	1,412		1,406.1		1,112.8
Total operating costs and expenses	27,061.8		31,397.3		25,557.5
General and administrative costs:
Third parties	75.3		77.4		59.6
Related parties	136.4		130.9		121.5
Total general and administrative costs	211.7		208.3		181.1
Total costs and expenses	27,273.5		31,605.6		25,738.6
Equity in income of unconsolidated affiliates	563		480		426
Operating income	6,078.7		5,408.6		3,928.9
Other income (expense):
Interest expense	(1,243)		(1,096.7)		(984.6)
Change in fair market value of Liquidity Option	(119.6)		(56.1)		(64.3)
Gain on step acquisition of unconsolidated affiliate	0		39.4		0
Interest income	11.6		3.6		1.3
Other, net	5		0		0
Total other expense, net	(1,346)		(1,109.8)		(1,047.6)
Income before income taxes	4,732.7		4,298.8		2,881.3
Provision for income taxes	(45.6)		(60.3)		(25.7)
Net income	4,687.1		4,238.5		2,855.6
Net income attributable to noncontrolling interests	(95.8)		(66.1)		(56.3)
Net income attributable to limited partners	$ 4,591.3		$ 4,172.4		$ 2,799.3
Earnings per unit:
Basic earnings per unit (in dollars per unit)	$ 2.09		$ 1.91		$ 1.30
Diluted earnings per unit (in dollars per unit)	$ 2.09		$ 1.91		$ 1.30
[1]	Revenues are accounted for under ASC 606.
[2]	Revenues are accounted for under ASC 605.

STATEMENTS OF CONSOLIDATED COMP

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
Net income	$ 4,687.1	$ 4,238.5	$ 2,855.6
Commodity hedging derivative instruments:
Change in fair value of cash flow hedges	44.1	293.2	(38.5)
Reclassification of losses (gains) to net income	(141.7)	(130.4)	112.2
Interest rate hedging derivative instruments:
Change in fair value of cash flow hedges	81.4	22.2	(5.7)
Reclassification of losses to net income	37.3	38.1	40.4
Total cash flow hedges	21.1	223.1	108.4
Other	(0.6)	(0.5)	(0.1)
Total other comprehensive income	20.5	222.6	108.3
Comprehensive income	4,707.6	4,461.1	2,963.9
Comprehensive income attributable to noncontrolling interests	(95.8)	(66.1)	(56.3)
Comprehensive income attributable to limited partners	$ 4,611.8	$ 4,395	$ 2,907.6

STATEMENTS OF CONSOLIDATED CASH

STATEMENTS OF CONSOLIDATED CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating activities:
Net income	$ 4,687.1	$ 4,238.5	$ 2,855.6
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion	1,949.3	1,791.6	1,644
Asset impairment and related charges	132.8	50.5	49.8
Equity in income of unconsolidated affiliates	(563)	(480)	(426)
Distributions received from unconsolidated affiliates attributable to earnings	568	479.4	433.7
Net gains attributable to asset sales	(5.7)	(28.7)	(10.7)
Deferred income tax expense	20	21.4	6.1
Change in fair market value of derivative instruments	27.2	17.8	22.8
Change in fair market value of Liquidity Option	119.6	56.1	64.3
Gain on step acquisition of unconsolidated affiliate	0	(39.4)	0
Non-cash expense related to long-term operating leases	42.8	0	0
Net effect of changes in operating accounts	(457.4)	16.2	32.2
Other operating activities	(0.2)	2.9	(5.5)
Net cash flows provided by operating activities	6,520.5	6,126.3	4,666.3
Investing activities:
Capital expenditures	(4,531.7)	(4,223.2)	(3,101.8)
Cash used for business combinations, net of cash received	0	(150.6)	(198.7)
Investments in unconsolidated affiliates	(111.6)	(113.6)	(50.5)
Distributions received from unconsolidated affiliates attributable to return of capital	63.3	50	49.3
Proceeds from asset sales	20.6	161.2	40.1
Other investing activities	(16.1)	(5.4)	(24.5)
Cash used in investing activities	(4,575.5)	(4,281.6)	(3,286.1)
Financing activities:
Borrowings under debt agreements	58,172.6	79,588.7	69,315.3
Repayments of debt	(56,716.5)	(77,957.1)	(68,459.6)
Debt issuance costs	(27.6)	(49.1)	(24.1)
Monetization of interest rate derivative instruments	0	22.1	30.6
Cash distributions paid to limited partners	(3,839.8)	(3,726.9)	(3,569.9)
Cash payments made in connection with distribution equivalent rights	(22.1)	(17.7)	(15.1)
Cash distributions paid to noncontrolling interests	(106.2)	(81.6)	(49.2)
Cash contributions from noncontrolling interests	632.8	238.1	0.4
Net cash proceeds from the issuance of common units	82.2	538.4	1,073.4
Repurchase of common units under buyback programs	(81.1)	(30.8)	0
Other financing activities	(39.4)	(29)	(29.3)
Cash provided by (used in) financing activities	(1,945.1)	(1,504.9)	(1,727.5)
Net change in cash and cash equivalents, including restricted cash	(0.1)	339.8	(347.3)
Cash and cash equivalents, including restricted cash, at beginning of period	410.1	70.3	417.6
Cash and cash equivalents, including restricted cash, at end of period	$ 410	$ 410.1	$ 70.3

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, 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, net	(29.9)	(0.1)	(1.3)	(28.5)
Balance at Dec. 31, 2017	22,772.4	(171.7)	225.2	22,718.9
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	4,238.5	0	66.1	4,172.4
Cash distributions paid to limited partners	(3,726.9)	0	0	(3,726.9)
Cash payments made in connection with distribution equivalent rights	(17.7)	0	0	(17.7)
Cash distributions paid to noncontrolling interests	(81.6)	0	(81.6)	0
Cash contributions from noncontrolling interests	238.1	0	238.1	0
Net cash proceeds from the issuance of common units	538.4	0	0	538.4
Common units issued in connection with employee compensation	39.1	0	0	39.1
Common units issued in connection with land acquisition	30	0	0	30
Repurchase of common units under buyback program	(30.8)	0	0	(30.8)
Amortization of fair value of equity-based awards	104.7	0	0	104.7
Cash flow hedges	223.1	223.1	0	0
Other, net	(35.1)	(0.5)	(9.1)	(25.5)
Balance at Dec. 31, 2018	24,292.2	50.9	438.7	23,802.6
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	4,687.1	0	95.8	4,591.3
Cash distributions paid to limited partners	(3,839.8)	0	0	(3,839.8)
Cash payments made in connection with distribution equivalent rights	(22.1)	0	0	(22.1)
Cash distributions paid to noncontrolling interests	(106.2)	0	(106.2)	0
Cash contributions from noncontrolling interests	632.8	0	632.8	0
Net cash proceeds from the issuance of common units	82.2	0	0	82.2
Common units issued in connection with employee compensation	45.6	0	0	45.6
Repurchase of common units under buyback program	(81.1)	0	0	(81.1)
Amortization of fair value of equity-based awards	143.3	0	0	143.3
Cash flow hedges	21.1	21.1	0	0
Other, net	(27.6)	(0.6)	2.4	(29.4)
Balance at Dec. 31, 2019	$ 25,827.5	$ 71.4	$ 1,063.5	$ 24,692.6

Partnership Operations, Organiz

Partnership Operations, Organization and Basis of Presentation	12 Months Ended
	Dec. 31, 2019
Partnership Operations, Organization and Basis of Presentation [Abstract]
Partnership Operations, Organization and Basis of Presentation	KEY REFERENCES USED IN THESE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Unless the context requires otherwise, references to “we,” “us,” “our” or “Enterprise” are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries. References to “EPD” or the “Partnership” mean Enterprise Products Partners L.P. on a standalone basis. References to “EPO” mean Enterprise Products Operating LLC, which is an indirect wholly owned subsidiary of EPD, and its consolidated subsidiaries, through which EPD 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, who is also an advisory director of Enterprise GP. 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 the Co-Chief Executive Officer and Chief Financial Officer 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 Financial Officer of EPCO. EPCO, together with its privately held affiliates, owned approximately 32% of EPD’s limited partner common units at December 31, 2019. Note 1. Partnership Organization and Operations 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 United States (“U.S.”), Canada and the Gulf of Mexico with domestic consumers and international markets. Our midstream energy operations currently include: natural gas gathering, treating, processing, transportation and storage; NGL transportation, fractionation, storage, and 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 EPD’s 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 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, 2019
Summary of Significant Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 2. Summary of Significant Accounting Policies Our consolidated financial statements are prepared on the accrual basis of accounting in accordance with U.S. generally accepted accounting principles (“GAAP”). 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 years indicated: For the Year Ended December 31, 2019 2018 2017 Balance at beginning of period $ 11.5 $ 12.1 $ 11.3 Charged to costs and expenses 1.2 0.7 2.7 Deductions (0.3 ) (1.3 ) (1.9 ) Balance at end of period $ 12.4 $ 11.5 $ 12.1 See “Credit Risk” in Note 18 for additional information. In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-13, “ Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments 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 primarily 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. See Note 14 for information regarding our derivative instruments and hedging activities. 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, 2019 2018 Cash and cash equivalents $ 334.7 $ 344.8 Restricted cash 75.3 65.3 Total cash, cash equivalents and restricted cash shown in the Statements of Consolidated Cash Flows $ 410.0 $ 410.1 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 8 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 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 change in the fair value of the hedge is reported in other comprehensive income (loss) and is reclassified to 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. 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, 2019, 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 years indicated: For the Year Ended December 31, 2019 2018 2017 Balance at beginning of period $ 6.9 $ 11.6 $ 11.9 Charged to costs and expenses 12.3 8.2 12.1 Acquisition-related additions and other 2.5 1.7 1.7 Deductions (14.5 ) (14.6 ) (14.1 ) Balance at end of period $ 7.2 $ 6.9 $ 11.6 At December 31, 2019 and 2018, $5.8 million and $3.2 million, respectively, of our environmental reserves were classified as current liabilities. Estimates Preparing our consolidated financial statements in conformity with U.S. GAAP requires us to make estimates that affect amounts presented in the financial statements. Our most significant estimates relate to (i) the useful lives and depreciation/amortization methods used for fixed and identifiable intangible assets; (ii) measurement of fair value and projections used in impairment testing of fixed and intangible assets (including goodwill); (iii) contingencies; and (iv) revenue and expense accruals. Actual results could differ materially from our estimates. On an ongoing basis, we review our estimates based on currently available information. Any changes in the facts and circumstances underlying our estimates may require us to update such estimates, which could have a material impact on our consolidated financial statements. 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 third-party yield curves 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 the following commodity derivative instruments which are used to hedge our various inventories and transportation capacities: (i) NGL-based contracts with terms greater than one year; (ii) crude, natural gas and refined products-based contracts with terms greater than 36 months; (iii) over-the-counter options; and (iv) exchange traded options with terms greater than one year. 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. Impairment Testing for Goodwill See Note 6 for information regarding our annual goodwill impairment test. Impairment Testing for Long-Lived Assets Long-lived assets, which consist of 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 estimated 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 when there are events or changes in circumstances that indicate there is a potential 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 value of an investment is not recoverable due to an other than temporary decline, we record a non-cash impairment charge to adjust the carrying value of the investment to its estimated fair value. There were no impairment charges related to our equity method investments during the years ended December 31, and . In 2019, we recorded a $ See Note 5 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 3 for additional information regarding our inventories. Leases In February 2016, the FASB issued Accounting Standards Codification (“ASC”) 842, Leases Leases The new standard introduces two lessee accounting models, which results in a lease being classified as either a “finance” or “operating” lease based on 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 ASC 840 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 right-of-use (“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. For finance leases, a lessee will amortize the ROU asset (generally on a straight-line basis in a manner similar to depreciation) and accrete the lease liability (as a component of interest expense) using the . Operating leases will result in the recognition of a single lease expense amount that is recorded on a straight-line basis. ASC 842 resulted in changes to the way our operating leases are recorded, presented and disclosed in our consolidated financial statements. Upon adoption of ASC 842 on January 1, 2019, we recognized a ROU asset and a corresponding lease liability based on the present value of then existing long-term operating lease obligations. In addition, we elected to apply several practical expedients and made accounting policy elections upon adoption of ASC 842 including: • We do not recognize ROU assets and lease liabilities for short-term leases and instead record them in a manner similar to operating leases under legacy lease accounting guidelines. A short term lease is one with a maximum lease term of 12 months or less and does not include a purchase option the lessee is reasonably certain to exercise. • We did not reassess whether any expired or existing contracts as of January 1, 2019 contained leases or the lease classification for any such existing or expired leases. • The impact of adopting ASC 842 was prospective beginning January 1, 2019. We did not recast prior periods presented in our consolidated financial statements to reflect the new lease accounting guidance. • We combine lease and nonlease components relating to our office and warehouse leases, as applicable. See Note 17 for our disclosures regarding operating lease obligations. 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 over the remaining portion of the fiscal year in which the maintenance occurred. 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 4 for additional information regarding our property, plant and equipment and AROs. Revenues For periods prior to January 1, 2018, we accounted for our revenue streams using ASC 605, Revenue Recognition We adopted ASC 606, Revenue from Contracts with Customers, on January 1, 2018 using a modified retrospective approach that applied the new revenue recognition standard to existing contracts at the implementation date and any future revenue contracts. As such, our consolidated revenues and related financial information for periods prior to January 1, 2018 were not adjusted and continue to be reported in accordance with ASC 605. We did not record a cumulative effect adjustment upon initially applying ASC 606 since there was no impact on partners’ equity upon adoption; however, the extent of our revenue-related disclosures has increased under the new standard. The core principle of ASC 606 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. We apply this core principle by following five key steps outlined in ASC 606: (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 judgment and an analysis of the contract’s material terms and conditions. Substantially all of our revenues are accounted for under ASC 606; however, to a limited extent, some revenues are accounted for under other guidance such as ASC 842, Leases, Nonmonetary Transactions, Derivatives and Hedging Activities Under ASC 606, we recognize revenue when or as we satisfy our performance obligation to the customer. In situations where we have recognized revenue, but have a conditional right to consideration (based on something other than the passage of time) from the customer, we recognize unbilled revenue (a contract asset) on our consolidated balance sheet. Unbilled revenue is reclassified to accounts receivable when we have an unconditional right of payment from the customer. Payments received from customers in advance of the period in which we satisfy a performance obligation are recorded as deferred revenue (a contract liability) on our consolidated balance sheet. Our revenue streams are derived from the sale of products and providing midstream services. Revenues from the sale of products are recognized at a point in time, which represents the transfer of control (and the satisfaction of our performance obligation under the contract) to the customer. From that point forward, the customer is able to direct the use of, and obtain substantially all the benefits from, its use of the products. With respect to midstream services (e.g., interruptible transportation), we satisfy our performance obligations over time and recognize revenues when the services are provided and the customer receives the benefits based on an output measure of volumes redelivered. We believe this measure is a faithful depiction of the transfer of control for midstream services since there is (i) an insignificant period of time between the receipt of customers’ volumes and their subsequent redelivery, and (ii) it is not possible to individually track and differentiate customers’ inventories as they traverse our facilities. For stand-ready performance obligations (e.g., a storage capacity reservation contract), we recognize revenues over time on a straight-line basis as time elapses over the term of the contract. We believe that these approaches accurately depict the transfer of benefits to the customer. Customers are invoiced for products purchased or services rendered when we have an unconditional right to consideration under the associated contract. The consideration we are entitled to invoice may be either fixed, variable or a combination of both. Examples of fixed consideration would be fixed payments from customers under take-or-pay arrangements, storage capacity reservation agreements and firm transportation contracts. Variable consideration represents payments from customers that are based on factors that fluctuate (or vary) based on volumes, prices or both. Examples of variable consideration include interruptible transportation agreements, market-indexed pr

Inventories

Inventories	12 Months Ended
	Dec. 31, 2019
Inventories [Abstract]
Inventories	Note 3. Inventories Our inventory amounts by product type were as follows at the dates indicated: December 31, 2019 2018 NGLs $ 1,094.9 $ 647.7 Petrochemicals and refined products 311.5 264.7 Crude oil 674.2 593.4 Natural gas 10.8 16.3 Total $ 2,091.4 $ 1,522.1 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 years indicated: For the Year Ended December 31, 2019 2018 2017 Cost of sales (1) $ 22,065.8 $ 26,789.8 $ 21,487.0 Lower of cost or net realizable value adjustments recognized in cost of sales 22.7 11.5 9.1 (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, 2019
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Note 4. 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 2019 2018 Plants, pipelines and facilities (1) 3-45 (5) $ 47,201.2 $ 42,371.0 Underground and other storage facilities (2) 5-40 (6) 3,965.5 3,624.2 Transportation equipment (3) 3-10 198.9 187.1 Marine vessels (4) 15-30 905.9 828.6 Land 372.3 359.5 Construction in progress 2,641.2 3,526.8 Total 55,285.0 50,897.2 Less accumulated depreciation 13,681.6 12,159.6 Property, plant and equipment, net $ 41,603.4 $ 38,737.6 (1) Plants, pipelines and facilities include processing plants; NGL, natural gas, crude oil and petrochemical and refined products pipelines; terminal loading and unloading facilities; buildings; office furniture and equipment; laboratory and shop equipment and related assets. (2) Underground and other storage facilities include underground product storage caverns; above ground storage tanks; water wells and related assets. (3) 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 years indicated: For the Year Ended December 31, 2019 2018 2017 Depreciation expense (1) $ 1,562.6 $ 1,436.2 $ 1,296.1 Capitalized interest (2) 143.8 147.9 192.1 (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 property 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, 2019 and 2018 includes $69.6 million and $72.5 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 years indicated: For the Year Ended December 31, 2019 2018 2017 ARO liability beginning balance $ 126.3 $ 86.7 $ 85.4 Liabilities incurred 5.0 24.4 4.7 Liabilities settled (2.3 ) (2.5 ) (2.2 ) Revisions in estimated cash flows (4.8 ) 11.5 (6.7 ) Accretion expense 7.9 6.2 5.5 ARO liability ending balance $ 132.1 $ 126.3 $ 86.7 The following table presents our forecast of ARO-related accretion expense for the years indicated: 2020 2021 2022 2023 2024 $ 8.2 $ 8.6 $ 9.1 $ 9.6 $ 10.3

Investments in Unconsolidated A

Investments in Unconsolidated Affiliates	12 Months Ended
	Dec. 31, 2019
Investments in Unconsolidated Affiliates [Abstract]
Investments in Unconsolidated Affiliates	Note 5. 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, December 31, 2019 2019 2018 NGL Pipelines & Services: Venice Energy Service Company, L.L.C. (“VESCO”) 13.1% $ 23.2 $ 24.1 K/D/S Promix, L.L.C. (“Promix”) 50% 25.7 28.9 Baton Rouge Fractionators LLC (“BRF”) 32.2% 15.6 16.3 Skelly-Belvieu Pipeline Company, L.L.C. (“Skelly-Belvieu”) 50% 33.1 35.6 Texas Express Pipeline LLC (“Texas Express”) 35% 358.1 337.6 Texas Express Gathering LLC (“TEG”) 45% 41.1 43.6 Front Range Pipeline LLC (“Front Range”) 33.3% 207.0 175.9 Crude Oil Pipelines & Services: Seaway Crude Holdings LLC (“Seaway”) 50% 1,353.1 1,369.7 Eagle Ford Pipeline LLC (“Eagle Ford Crude Oil Pipeline”) 50% 386.5 388.7 Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Corpus Christi”) 50% 126.9 109.1 Natural Gas Pipelines & Services: White River Hub, LLC (“White River Hub”) 50% 19.1 20.1 Old Ocean Pipeline, LLC (“Old Ocean”) 50% 8.2 2.7 Petrochemical & Refined Products Services: Centennial Pipeline LLC (“Centennial”) (1) 50% – 59.1 Baton Rouge Propylene Concentrator LLC (“BRPC”) 30% 2.0 3.2 Transport 4, LLC (“Transport 4”) 25% 0.6 0.5 Total $ 2,600.2 $ 2,615.1 (1) The investment in Centennial was written off in December 2019. NGL Pipelines & Services The principal business activity of each investee included in our NGL Pipelines & Services segment is described as follows: • VESCO • Promix • BRF • Skelly-Belvieu • Texas Express • TEG • Front Range Crude Oil Pipelines & Services The principal business activity of each investee included in our Crude Oil Pipelines & Services segment is described as follows: • Seaway • Eagle Ford Crude Oil Pipeline • Eagle Ford Corpus Christi Natural Gas Pipelines & Services The principal business activity of each investee included in our Natural Gas Pipelines & Services segment is described as follows: • White River Hub • Old Ocean owns a natural gas pipeline that extends from near Maypearl, Texas to Sweeny, Texas. Petrochemical & Refined Products Services The principal business activity of each investee included in our Petrochemical & Refined Products Services segment is described as follows: • BRPC • Transport 4 Centennial In December 2019, we recorded a $ The Centennial assets were idled in 2013 while management investigated multiple capital project opportunities to repurpose the pipeline. As a result of losses incurred following idling of the pipeline, we tested our equity method investment in Centennial for impairment in each of the last three fiscal years. Our valuation estimates, which were based on a combination of market and income approaches, indicated that the fair value of our investment was in excess of its carrying value during the years ended December 31, 2018 and 2017 and that no impairment was indicated. However, due to recent declines in the viability of potential commercial transactions involving the pipeline, we concluded that our investment was not recoverable and had no fair value at December 31, 2019. We continue to own a 50% equity interest in the Centennial Pipeline, which is being maintained in an idled state in accordance with governmental regulations. Equity Earnings The following table presents our equity in income (loss) of unconsolidated affiliates by business segment for the years indicated: For the Year Ended December 31, 2019 2018 2017 NGL Pipelines & Services $ 114.5 $ 117.0 $ 73.4 Crude Oil Pipelines & Services 449.2 365.4 358.4 Natural Gas Pipelines & Services 6.3 6.8 3.8 Petrochemical & Refined Products Services (1) (7.0 ) (9.2 ) (9.6 ) Total $ 563.0 $ 480.0 $ 426.0 (1) The losses recorded for this segment are primarily due to protection, maintenance and pipeline integrity costs of the idled Centennial Pipeline, which was purged and filled with nitrogen in 2013. Although we wrote off our investment in Centennial in 2019, we, as a 50% owner of Centennial, have a continuing obligation to fund the pipeline’s costs in its idled state. 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, 2019 2018 NGL Pipelines & Services $ 20.5 $ 21.7 Crude Oil Pipelines & Services 16.6 17.4 Petrochemical & Refined Products Services – 1.7 Total $ 37.1 $ 40.8 In total, amortization of excess cost amounts were $2.1 million for each of the years ended December 31, 2019, 2018 and 2017. We forecast that our amortization of excess cost amount will approximate $2.0 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, 2019 2018 Balance Sheet Data: Current assets $ 358.1 $ 350.2 Property, plant and equipment, net 5,379.7 5,359.1 Other assets 68.7 80.4 Total assets $ 5,806.5 $ 5,789.7 Current liabilities $ 230.9 $ 220.6 Other liabilities 69.6 77.9 Combined equity 5,506.0 5,491.2 Total liabilities and combined equity $ 5,806.5 $ 5,789.7 For the Year Ended December 31, 2019 2018 2017 Income Statement Data: Revenues $ 1,950.2 $ 1,721.3 $ 1,509.0 Operating income 1,250.4 1,074.6 925.9 Net income 1,251.8 1,069.1 929.5

Intangible Assets and Goodwill

Intangible Assets and Goodwill	12 Months Ended
	Dec. 31, 2019
Intangible Assets and Goodwill [Abstract]
Intangible Assets and Goodwill	Note 6. Intangible Assets and Goodwill Identifiable Intangible Assets The following table summarizes our intangible assets by business segment at the dates indicated: December 31, 2019 December 31, 2018 Gross Value Accumulated Amortization Carrying Value Gross Value Accumulated Amortization Carrying Value NGL Pipelines & Services: Customer relationship intangibles $ 447.8 $ (206.3 ) $ 241.5 $ 457.3 $ (201.9 ) $ 255.4 Contract-based intangibles 162.6 (43.9 ) 118.7 363.4 (238.7 ) 124.7 Segment total 610.4 (250.2 ) 360.2 820.7 (440.6 ) 380.1 Crude Oil Pipelines & Services: Customer relationship intangibles 2,203.5 (243.5 ) 1,960.0 2,203.5 (174.1 ) 2,029.4 Contract-based intangibles 276.9 (235.0 ) 41.9 276.9 (211.7 ) 65.2 Segment total 2,480.4 (478.5 ) 2,001.9 2,480.4 (385.8 ) 2,094.6 Natural Gas Pipelines & Services: Customer relationship intangibles 1,350.3 (481.6 ) 868.7 1,350.3 (447.8 ) 902.5 Contract-based intangibles 468.0 (395.5 ) 72.5 464.7 (387.9 ) 76.8 Segment total 1,818.3 (877.1 ) 941.2 1,815.0 (835.7 ) 979.3 Petrochemical & Refined Products Services: Customer relationship intangibles 181.4 (57.5 ) 123.9 181.4 (51.8 ) 129.6 Contract-based intangibles 46.0 (24.2 ) 21.8 46.0 (21.2 ) 24.8 Segment total 227.4 (81.7 ) 145.7 227.4 (73.0 ) 154.4 Total intangible assets $ 5,136.5 $ (1,687.5 ) $ 3,449.0 $ 5,343.5 $ (1,735.1 ) $ 3,608.4 The following table presents the amortization expense of our intangible assets by business segment for the years indicated: For the Year Ended December 31, 2019 2018 2017 NGL Pipelines & Services $ 31.9 $ 34.7 $ 28.9 Crude Oil Pipelines & Services 92.7 87.8 92.5 Natural Gas Pipelines & Services 41.4 39.1 36.2 Petrochemical & Refined Products Services 8.7 8.7 9.3 Total $ 174.7 $ 170.3 $ 166.9 The following table presents our forecast of amortization expense associated with existing intangible assets for the years indicated: 2020 2021 2022 2023 2024 $ 164.8 $ 167.0 $ 164.0 $ 162.4 $ 158.9 Customer relationship intangible assets Customer relationship intangible assets represent the estimated economic value assigned to commercial relationships acquired in connection with business combinations. Our customer relationship intangible assets are classified as either (i) basin-specific or (ii) general. Basin-specific customer relationships represent access to customers associated with a defined resource basin (e.g., customers using a natural gas gathering system serving a specific production field) and is analogous to having a franchise in a particular area. General customer relationships are associated with customers whose hydrocarbon volumes are not attributable to specific resource basins (e.g. customers at a marine terminal that handles volumes originating from multiple sources). The estimated fair value of each customer relationship intangible asset was determined at the time of acquisition using a discounted cash flow analysis, which incorporates various assumptions regarding the acquired business. The assumptions may include 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, resource base depletion rates and expected customer attrition rates. The recognition of customer relationships are supported by a variety of factors. In general, midstream infrastructure requires a significant investment, both in terms of initial construction costs and ongoing maintenance, and is generally supported by long-term contracts that establish a customer base. The level of expenditures and regulatory requirements involved in constructing new midstream asset networks can create significant economic barriers to entry that may limit potential competition. Furthermore, efficient, continuous operation of the acquired fixed assets not only supports the commercial relationships existing at the time of the acquisition, but it provides us with opportunities to establish new ones. These factors support the long-term value attributed to our customer relationship intangible assets. With respect to amortization periods, the duration of a basin-specific customer relationship is limited to the estimated economic life of the associated resource basin. The duration of our other customer relationships is typically limited to the term of the underlying service contracts, including assumed renewals. Amortization expense attributable to customer relationships is recorded in a manner that closely resembles the pattern in which we expect to benefit from such relationships. At December 31, 2019, the carrying value of our portfolio of customer relationship intangible assets was $3.2 billion, the principal components of which were as follows: a Weighted Average Remaining Amortization Period December 31, 2019 Gross Value Accumulated Amortization Carrying Value Basin-specific customer relationships: EFS Midstream (acquired 2015) 22.4 years $ 1,409.8 $ (160.1) $ 1,249.7 State Line and Fairplay (acquired 2010) 27.2 years 895.0 (205.1) 689.9 San Juan Gathering (acquired 2004) 19.8 years 331.3 (236.8) 94.5 General customer relationships: Oiltanking (acquired 2014) 24.0 years 1,192.5 (122.2) 1,070.3 • The EFS Midstream . The EFS Midstream System provides condensate gathering and processing services along with gathering, treating and compression services for associated natural gas. • The State Line and Fairplay The Haynesville Gathering System gathers and treats natural gas produced from the Haynesville and Bossier Shale supply basins and the Cotton Valley and Taylor Sand formations in Louisiana and East Texas. The Fairplay Gathering System gathers natural gas produced from the Cotton Valley formation in East Texas. • The San Juan Gathering • The Oiltanking Contract-based intangible assets Contract-based intangible assets represent specific commercial rights we acquired in connection with business combinations. These intangible assets are typically valued using an income approach that incorporate the terms of the agreements. At December 31, 2019, the carrying value of our portfolio of contract-based intangible assets was $254.9 million, the principal components of which were as follows: a Weighted Average Remaining Amortization Period December 31, 2019 Gross Value Accumulated Amortization Carrying Value Oiltanking customer contracts 3.6 years $ 293.3 $ (245.9) $ 47.4 Jonah natural gas gathering agreements 22.0 years 224.4 (171.4) 53.0 Delaware Basin natural gas processing contracts 7.0 years 82.6 (15.0) 67.6 • The Oiltanking customer contracts • The Jonah natural gas gathering agreements • The Delaware Basin natural gas processing contracts Goodwill At December 31, 2019 and 2018, our goodwill balance was $5.75 billion. 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, we evaluate goodwill for impairment on December 31 of each year or when impairment indicators (e.g., the loss of a significant customer, adverse long-term supply or demand trends, or technological obsolescence of assets) are present. Testing goodwill for impairment involves a two-step process. As Step 1 of the process, if impairment indicators are present, the estimated fair value of a reporting unit to which goodwill is assigned is determined and compared to its carrying value. As Step 2 of the process, if the fair value of the reporting unit is less than its carrying value (including associated goodwill), a non-cash impairment charge to earnings is recorded to reduce the carrying value of the goodwill to its implied fair value. The results of our December 31, 2019 annual goodwill impairment test indicated that the estimated fair value of each applicable reporting unit exceeded its carrying value. Our fair value estimates are primarily based on the income approach to fair value, which relies on the use of discounted cash flows. he estimated fair values incorporate assumptions regarding the future economic prospects of the assets and operations that comprise each reporting unit including: (i) discrete financial forecasts for the assets classified within the reporting unit, which, in turn, rely on management’s estimates of long-term 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 that the assumptions we use in estimating reporting unit fair values are consistent with those that market participants would use in their fair value estimation process. We did not record any goodwill impairment charges, or reclassify any goodwill amounts between business segments, during the years ended December 31, 2019, 2018 or 2017. See Note 10 for our goodwill by segment balances. In January 2017, the FASB issued ASU 2017-04, “ Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.

Debt Obligations

Debt Obligations	12 Months Ended
	Dec. 31, 2019
Debt Obligations [Abstract]
Debt Obligations	Note 7. Debt Obligations The following table presents our consolidated debt obligations (arranged by company and maturity date) at the dates indicated: December 31, 2019 2018 EPO senior debt obligations: Commercial Paper Notes, variable-rates $ 482.0 $ – Senior Notes N, 6.50% fixed-rate, due January 2019 – 700.0 Senior Notes LL, 2.55% fixed-rate, due October 2019 – 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 1,000.0 364-Day Revolving Credit Agreement, variable-rate, due September 2020 – – Senior Notes TT, 2.80% fixed-rate, due February 2021 750.0 750.0 Senior Notes RR, 2.85% fixed-rate, due April 2021 575.0 575.0 Senior Notes VV, 3.50% fixed-rate, due February 2022 750.0 750.0 Senior Notes CC, 4.05% fixed-rate, due February 2022 650.0 650.0 Senior Notes HH, 3.35% fixed-rate, due March 2023 1,250.0 1,250.0 Senior Notes JJ, 3.90% fixed-rate, due February 2024 850.0 850.0 Multi-Year Revolving Credit Agreement, variable-rate, due September 2024 – – 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 WW, 4.15% fixed-rate, due October 2028 1,000.0 1,000.0 Senior Notes YY, 3.125% fixed-rate, due July 2029 1,250.0 – 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 UU, 4.25% fixed-rate, due February 2048 1,250.0 1,250.0 Senior Notes XX, 4.80% fixed-rate, due February 2049 1,250.0 1,250.0 Senior Notes ZZ, 4.20% fixed-rate, due January 2050 1,250.0 – Senior Notes NN, 4.95% fixed-rate, due October 2054 400.0 400.0 TEPPCO senior debt obligations: TEPPCO Senior Notes, 7.55% fixed-rate, due April 2038 0.4 0.4 Total principal amount of senior debt obligations 25,232.0 23,750.0 EPO Junior Subordinated Notes C, variable-rate, due June 2067 232.2 256.4 EPO Junior Subordinated Notes D, fixed/variable-rate, due August 2077 700.0 700.0 EPO Junior Subordinated Notes E, fixed/variable-rate, due August 2077 1,000.0 1,000.0 EPO Junior Subordinated Notes F, fixed/variable-rate, due February 2078 700.0 700.0 TEPPCO Junior Subordinated Notes, variable-rate, due June 2067 14.2 14.2 Total principal amount of senior and junior debt obligations 27,878.4 26,420.6 Other, non-principal amounts (253.3 ) (242.4 ) Less current maturities of debt (1,981.9 ) (1,500.1 ) Total long-term debt $ 25,643.2 $ 24,678.1 (1) Variable rate is reset quarterly and based on 3-month London Interbank Offered Rate ("LIBOR") plus 2.778%. (2) Fixed rate of 4.875% through August 15, 2022; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 2.986%. (3) Fixed rate of 5.250% through August 15, 2027; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 3.033%. (4) Fixed rate of 5.375% through February 14, 2028; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 2.57%. References to “TEPPCO” mean TEPPCO Partners, L.P. prior to its merger with one of our wholly owned subsidiaries in October 2009. 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, 2019: Range of Interest Rates Paid Weighted-Average Interest Rate Paid Commercial Paper Notes 1.79% to 2.80% 2.61% EPO Junior Subordinated Notes C and TEPPCO Junior Subordinated Notes 4.68% to 5.52% 5.22% Amounts borrowed under our 364-Day and Multi-Year Revolving Credit Agreements bear interest, at our election, equal to: (i) LIBOR, plus an additional variable spread; or (ii) an alternate base rate, which is the greater of (a) the Prime Rate in effect on such day, (b) the Federal Funds Effective Rate in effect on such day plus 0.5%, or (c) the LIBO Market Index Rate in effect on such day plus 1% and a variable spread. The applicable spreads are determined based on our debt ratings. The following table presents the scheduled contractual maturities of principal amounts of our consolidated debt obligations at December 31, 2019 for the next five years, and in total thereafter: Scheduled Maturities of Debt Total 2020 2021 2022 2023 2024 Thereafter Commercial Paper Notes $ 482.0 $ 482.0 $ – $ – $ – $ – $ – Senior Notes 24,750.0 1,500.0 1,325.0 1,400.0 1,250.0 850.0 18,425.0 Junior Subordinated Notes 2,646.4 – – – – – 2,646.4 Total $ 27,878.4 $ 1,982.0 $ 1,325.0 $ 1,400.0 $ 1,250.0 $ 850.0 $ 21,071.4 Parent-Subsidiary Guarantor Relationships EPD 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, EPD would be responsible for full and unconditional repayment of that obligation. EPO Debt Obligations Commercial Paper Notes EPO maintains a commercial paper program under which it may issue (and have outstanding at any time) up to $3.0 billion in aggregate principal amount of short-term notes. As a back-stop to the program, we intend to maintain a minimum available borrowing capacity under EPO’s Multi-Year Revolving Credit Agreement equal to the aggregate amount outstanding under our commercial paper notes. All commercial paper notes issued under the program are senior unsecured obligations of EPO that are unconditionally guaranteed by EPD. 364-Day Credit Agreement In September 2019, EPO entered into a new 364-Day Revolving Credit Agreement that replaced its prior 364-day credit facility. The new 364-Day Revolving Credit Agreement matures in September 2020. There are currently no principal amounts outstanding under this revolving 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 up to 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 non-revolving term loans for a period of one additional year, payable in September 2021. Borrowings under this revolving credit agreement may be used for working capital, capital expenditures, acquisitions and general company purposes. The new 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, EPD, 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 new 364-Day Revolving Credit Agreement are not secured by any collateral; however, they are guaranteed by EPD. Multi-Year Revolving Credit Agreement In September 2019, EPO entered into an amendment (the “First Amendment”) to its revolving credit agreement dated September 13, 2017 (the “Multi-Year Revolving Credit Agreement”). The First Amendment reduces the borrowing capacity under the Multi-Year Revolving Credit Agreement from $4.0 billion to $3.5 billion (which may be increased by up to $500 million to $4.0 billion at EPO’s election provided certain conditions are met) and extends the maturity date to September 10, 2024, although the maturity date may be extended further at EPO’s request by up to two years, with the consent of required lenders as set forth under the credit agreement. Borrowings under this revolving credit agreement may be used for working capital, capital expenditures, acquisitions and general company purposes. The Multi-Year 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 Multi-Year Revolving Credit Agreement also restricts EPO’s ability to pay cash distributions to its parent, EPD, 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 Multi-Year Revolving Credit Agreement are not secured by any collateral; however, they are guaranteed by EPD. Senior Notes EPO’s fixed-rate senior notes are unsecured obligations of EPO that rank equal with its existing and future unsecured and unsubordinated indebtedness. They are senior to any existing and future subordinated indebtedness of EPO. EPO’s senior notes are subject to make-whole redemption rights and were issued under indentures containing certain covenants, which generally restrict its ability (with certain exceptions) to incur debt secured by liens and engage in sale and leaseback transactions. In total, EPO issued $2.5 billion and $5.0 billion of senior notes during the years ended December 31, 2019 and 2018, respectively. In July 2019, EPO issued $ billion aggregate principal amount of senior notes comprised of $ billion principal amount of senior notes due July 2029 (“Senior Notes YY”) and $ billion principal amount of senior notes due January 2050 (“Senior Notes ZZ”). See Note 22, Subsequent Events EPO Junior Subordinated Notes EPO’s payment obligations under its junior notes are subordinated to all of its current and future senior indebtedness (as defined in the related indenture agreement). EPD guarantees repayment of amounts due under these junior notes through an unsecured and subordinated guarantee. The indenture agreement governing these notes allows EPO to defer interest payments on one or more occasions for up to ten consecutive years subject to certain conditions. Subject to certain exceptions, during any period in which interest payments are deferred, neither we nor EPO can declare or make any distributions on any of our respective equity securities or make any payments on indebtedness or other obligations that rank equal In connection with the issuance of EPO’s Junior Subordinated Notes C, EPO entered into a Replacement Capital Covenant in favor of covered debt holders (as defined in the underlying documents) pursuant to which EPO agreed, for the benefit of such debt holders, that it would not redeem or repurchase such junior notes unless such redemption or repurchase is made using proceeds from the issuance of certain securities. During the second quarter of 2019, EPO repurchased and retired $24.2 million in principal amount of its Junior Subordinated Notes C. A $1.5 million gain on the extinguishment of these debt obligations is included in “Other, net” on our Statements of Consolidated Operations with respect to the year ended December 31, 2019. Letters of Credit At December 31, 2019, EPO had $101.4 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, 2019.

Equity and Distributions

Equity and Distributions	12 Months Ended
	Dec. 31, 2019
Equity and Distributions [Abstract]
Equity and Distributions	Note 8. Equity and Distributions Partners Equity Partners’ equity reflects the classes of our limited partner interests outstanding. 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 following table summarizes changes in the number of our units issued and outstanding since December 31, 2016: Common Units (Unrestricted) Restricted Common Units Total Common Units Number of units issued and 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 issued and outstanding at December 31, 2017 2,161,089,479 – 2,161,089,479 Common unit repurchases under Legacy Buyback Program (1,236,800 ) – (1,236,800 ) Common units issued in connection with DRIP and EUPP 19,861,951 – 19,861,951 Common units issued in connection with the vesting of phantom unit awards 3,479,958 – 3,479,958 Cancellation of treasury units acquired in connection with the vesting of equity-based awards (1,037,522 ) – (1,037,522 ) Common units issued in connection with employee compensation 1,443,586 – 1,443,586 Common units issued in connection with land acquisition 1,223,242 – 1,223,242 Other 45,135 – 45,135 Number of units issued and outstanding at December 31, 2018 2,184,869,029 – 2,184,869,029 Common unit repurchases under 2019 Buyback Program (2,909,128 ) – (2,909,128 ) Common units issued in connection with DRIP and EUPP 2,897,990 – 2,897,990 Common units issued in connection with the vesting of phantom unit awards 3,895,049 – 3,895,049 Cancellation of treasury units acquired in connection with the vesting of equity-based awards (1,174,446 ) – (1,174,446 ) Common units issued in connection with employee compensation 1,626,041 – 1,626,041 Other 21,595 – 21,595 Number of units issued and outstanding at December 31, 2019 2,189,226,130 – 2,189,226,130 The net cash proceeds we received from the issuance of common units during the year ended December 31, 2019 were used to temporarily reduce amounts outstanding under EPO’s commercial paper program and for general partnership purposes. Common unit repurchases under buyback programs In January 2019, we announced that the Board of Enterprise GP had approved a $2.0 billion multi-year unit buyback program (the “2019 Buyback Program”), which provides EPD with an additional method to return capital to investors. The 2019 Buyback Program authorizes EPD to repurchase its common units from time to time, including through open market purchases and negotiated transactions. The timing and pace of buy backs under the program will be determined by a number of factors including (i) our financial performance and flexibility, (ii) organic growth and acquisition opportunities with higher potential returns on investment, (iii) EPD’s unit price and implied cash flow yield and (iv) maintaining targeted financial leverage with a debt-to-normalized adjusted EBITDA (earnings before interest, taxes, depreciation and amortization) ratio of approximately 3.5 times. No time limit has been set for completion of the program, and it may be suspended or discontinued at any time. EPD repurchased 2019 Buyback Program through open market purchases during the year ended . The total purchase price of these repurchases was $ 2019 Buyback Program was $ In December 1998, we announced a common unit buyback program whereby we, together with certain affiliates, could repurchase up to EPD common units on the open market (the “Legacy Buyback Program”). EPD purchased the remaining authorized amount of common units in December 2018 for $ million. Distribution reinvestment plan and employee unit purchase plan We have a registration statement on file with the SEC in connection with our distribution reinvestment plan (“DRIP”). The DRIP provides unitholders of record and beneficial owners of our common units a voluntary means by which they can increase the number of our common units they own by reinvesting the quarterly cash distributions they receive from us into the purchase of additional common units at a discount ranging from 0% to 5.0%. Beginning with the distribution declared with respect to the fourth quarter of 2017 and paid in February 2018, the discount was reduced from 5.0% to 2.5%. Likewise, beginning with the distribution declared with respect to the fourth quarter of 2018 and paid in February 2019, the discount was reduced from 2.5% to 0%. We have the sole discretion to determine whether common units purchased under the DRIP will come from our authorized but unissued common units or from common units purchased on the open market by the DRIP administrator. Activity under our DRIP for the last three years was as follows: 2,601,727 new common units issued during 2019, which generated net cash proceeds of $73.7 million; 19,316,781 new common units issued during 2018, which generated net cash proceeds of $523.3 million; and 18,541,355 new common units issued during 2017, which generated net cash proceeds of $462.9 million. Privately held affiliates of EPCO reinvested $29 million, $213 million and $100 million through the DRIP in each of the years ended December 31, 2019, 2018 and 2017, respectively (this amount being a component of the net cash proceeds presented for each period). After taking into account the number of common units delivered under the DRIP through December 31, 2019, we have the capacity to deliver an additional 56,320,229 common units under this plan. In addition to the DRIP, we have registration statements on file with the SEC in connection with our employee unit purchase plan (“EUPP”). Activity under our EUPP for the last three years was as follows: 296,263 new common units issued during 2019, which generated net cash proceeds of $8.5 million; 545,170 new common units issued during 2018, which generated net cash proceeds of $15.1 million; and 504,664 new common units issued during 2017, which generated net cash proceeds of $13.5 million. After taking into account the number of common units delivered under the EUPP through December 31, 2019, we have the capacity to deliver an additional 4,596,585 common units under this plan. In July 2019, EPD announced that, beginning with the quarterly distribution paid in August 2019, it would use common units purchased on the open market, rather than issuing new common units, to satisfy its delivery obligations under the DRIP and EUPP. This election is subject to change in future quarters depending on the Partnership’s need for equity capital. During 2019, a total of million Phantom unit vestings and related treasury unit transactions During the year ended December 31, 2019, a total of 3,895,049 phantom units vested and 1,174,446 units were sold back to us by employees to cover withholding tax requirements in connection with the vestings. During the year ended December 31, 2018, a total of 3,479,958 phantom units vested and 1,037,522 units were sold back to us. During the year ended December 31, 2017, an aggregate 3,166,624 phantom and restricted unit awards vested and 1,027,798 units were sold back to us. We cancelled such treasury units immediately upon acquisition. The total cost of these treasury unit purchases was $33.7 million, $27.3 million and $29.5 million for the years ended December 31, 2019, 2018 and 2017, respectively. These amounts are reflected as a component of “Other, net” as presented on our Statements of Consolidated Equity. See Note 13 for additional information regarding our equity-based awards. Common units issued in connection with employee compensation In February 2019, 2018 and 2017, certain employees of EPCO received discretionary bonus payments, less any retirement plan deductions and applicable withholding taxes, for work performed on our behalf during the prior fiscal year (e.g., the bonus paid in February 2019 was with respect to the year ended December 31, 2018). The net dollar value of the bonus amounts was remitted to employees through the issuance of an equivalent value of newly issued EPD common units under EPCO’s 2008 Enterprise Products Long-Term Incentive Plan (Third Amendment and Restatement) (referred to as the “2008 Plan”). In February 2019, we issued 1,626,041 common units, which had a value of $45.6 million, in connection with the employee bonus awards. In February 2018, we issued 1,443,586 common units, which had a value of $39.1 million, in connection with the employee bonus awards. In February 2017, we issued 1,176,103 common units, which had a value of $33.7 million. The compensation expense associated with each bonus award was recognized during the year in which the work was performed. Common units issued in connection with land acquisition In April 2018, we acquired land in the Houston, Texas area for $85.2 million. The consideration paid consisted of $55.2 million in cash with the balance funded by the issuance of 1,223,242 EPD common units. At-the-Market (“ATM”) Program In November 2017, we filed an amended registration statement with the SEC covering the issuance of up to $2.54 billion of our common units in amounts, at prices and on terms to be determined by market conditions and other factors at the time of such offerings in connection with our ATM program. Pursuant to this program, we may sell common units under an equity distribution agreement between EPD and certain broker-dealers from time-to-time by means of ordinary brokers’ transactions through the NYSE at market prices, in block transactions or as otherwise agreed to with the broker-dealer parties to the agreement. We did not issue any common units under the ATM program during 2019 or 2018. 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. After taking into account the aggregate sales price of common units sold under the ATM program through December 31, 2019, we have the capacity to issue additional common units under the ATM program up to an aggregate sales price of $2.54 billion. Universal shelf registration statement We have a universal shelf registration statement (the “2019 Shelf”) on file with the SEC which allows EPD and EPO (each on a standalone basis) to issue an unlimited amount of equity and debt securities, respectively. The 2019 Shelf replaced our prior universal shelf registration statement, which expired in May 2019. EPO used the 2019 Shelf to issue $2.5 billion aggregate principal amount of senior notes during the year ended December 31, 2019 (see Note 7). In addition, EPO used the 2019 Shelf to issue $3.0 billion aggregate principal amount of senior notes in January 2020 (see Note 22). We may issue additional equity and debt securities in the future to assist us in meeting our funding and liquidity requirements, including those related to capital investments. Accumulated Other Comprehensive Income (Loss) Accumulated other comprehensive income (loss) primarily reflects cumulative gain or loss on derivative instruments designated and qualified as cash flow hedges from inception less gains or losses previously reclassified from accumulated other comprehensive income (loss) into earnings. 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: Cash Flow Hedges Commodity Derivative Instruments Interest Rate Derivative Instruments Other Total Accumulated Other Comprehensive Income (Loss), December 31, 2017 $ (10.1 ) $ (165.1 ) $ 3.5 $ (171.7 ) Other comprehensive income (loss) for period, before reclassifications 293.2 22.2 (0.5 ) 314.9 Reclassification of losses (gains) to net income during period (130.4 ) 38.1 – (92.3 ) Total other comprehensive income (loss) for period 162.8 60.3 (0.5 ) 222.6 Accumulated Other Comprehensive Income (Loss), December 31, 2018 152.7 (104.8 ) 3.0 50.9 Other comprehensive income (loss) for period, before reclassifications 44.1 81.4 (0.6 ) 124.9 Reclassification of losses (gains) to net income during period (141.7 ) 37.3 – (104.4 ) Total other comprehensive income (loss) for period (97.6 ) 118.7 (0.6 ) 20.5 Accumulated Other Comprehensive Income (Loss), December 31, 2019 $ 55.1 $ 13.9 $ 2.4 $ 71.4 The following table presents reclassifications of (income) loss out of accumulated other comprehensive income (loss) into net income during the years indicated: For the Year Ended December 31, Losses (gains) on cash flow hedges: Location 2019 2018 Interest rate derivatives Interest expense $ 37.3 $ 38.1 Commodity derivatives Revenue (152.4 ) (131.7 ) Commodity derivatives Operating costs and expenses 10.7 1.3 Total $ (104.4 ) $ (92.3 ) For information regarding our interest rate and commodity derivative instruments, see Note 14. Noncontrolling Interests Noncontrolling interests represent third party ownership interests in our consolidated subsidiaries. Breviloba LLC In July 2019, Altus Midstream Processing LP acquired a noncontrolling 33% equity interest in our consolidated subsidiary, Breviloba LLC, Pascagoula Gas Processing LLC In June 2019, an affiliate of Third Coast Midstream, LLC acquired a noncontrolling 25% equity interest in our consolidated subsidiary, Pascagoula Gas Processing LLC, that owns the Pascagoula natural gas processing plant for $36.0 million in cash. Baymark Pipeline LLC In May 2019, we formed a new business venture with Lavaca Pipe Line Company (“Lavaca”) to construct and own an ethylene pipeline in South Texas. Whitethorn Pipeline Company LLC In June 2018, an affiliate of Western Gas Partners, LP acquired a noncontrolling 20% equity interest in our subsidiary, Whitethorn Pipeline Company LLC (“Whitethorn”), for $189.6 million in cash. Whitethorn owns the majority of our Midland-to-ECHO 1 pipeline. Enterprise Navigator Ethylene Terminal LLC In January 2018, we formed a new business venture with Navigator Ethylene Terminals LLC (“Navigator”) to construct and own an ethylene export terminal, which is located at Morgan’s Point on the Houston Ship Channel. 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 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 2018: 1st Quarter $ 0.4275 4/30/2018 5/8/2018 2nd Quarter $ 0.4300 7/31/2018 8/8/2018 3rd Quarter $ 0.4325 10/31/2018 11/8/2018 4th Quarter $ 0.4350 1/31/2019 2/8/2019 2019: 1st Quarter $ 0.4375 4/30/2019 5/13/2019 2nd Quarter $ 0.4400 7/31/2019 8/13/2019 3rd Quarter $ 0.4425 10/31/2019 11/12/2019 4th Quarter $ 0.4450 1/31/2020 2/12/2020 In January 2020, based on current expectations, management announced its plans to continue to recommend to the Board an increase of $0.0025 per unit per quarter to our cash distribution rate with respect to 2020. The anticipated rate of increase would result in distributions for 2020 (of $1.8050 per unit) being 2.3% higher than those paid for 2019 (of $1.7650 per unit). 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.

Revenues

Revenues	12 Months Ended
	Dec. 31, 2019
Revenues [Abstract]
Revenues [Text Block]	Note 9. Revenues We classify our revenues into sales of products and midstream services. Product sales relate primarily to our various marketing activities whereas midstream services represent our other integrated businesses (i.e., gathering, processing, transportation, fractionation, storage and terminaling). The following table presents our revenues by business segment, and further by revenue type, for the years indicated: For the Year Ended December 31, 2019 2018 2017 NGL Pipelines & Services: Sales of NGLs and related products $ 10,934.3 $ 12,920.9 $ 10,521.3 Segment midstream services: Natural gas processing and fractionation 1,069.9 1,341.0 719.1 Transportation 1,054.3 1,007.0 891.7 Storage and terminals 412.2 380.0 335.9 Total segment midstream services 2,536.4 2,728.0 1,946.7 Total NGL Pipelines & Services 13,470.7 15,648.9 12,468.0 Crude Oil Pipelines & Services: Sales of crude oil 9,007.8 10,001.2 7,365.2 Segment midstream services: Transportation 801.8 676.5 473.9 Storage and terminals 477.7 364.9 317.7 Total segment midstream services 1,279.5 1,041.4 791.6 Total Crude Oil Pipelines & Services 10,287.3 11,042.6 8,156.8 Natural Gas Pipelines & Services: Sales of natural gas 2,075.4 2,411.7 2,238.5 Segment midstream services: Transportation 1,094.0 1,042.7 907.1 Total segment midstream services 1,094.0 1,042.7 907.1 Total Natural Gas Pipelines & Services 3,169.4 3,454.4 3,145.6 Petrochemical & Refined Products Services: Sales of petrochemicals and refined products 4,985.2 5,535.4 4,696.3 Segment midstream services: Fractionation and isomerization 166.6 188.3 156.3 Transportation, including marine logistics 539.4 481.8 430.7 Storage and terminals 170.6 182.8 187.8 Total segment midstream services 876.6 852.9 774.8 Total Petrochemical & Refined Products Services 5,861.8 6,388.3 5,471.1 Total consolidated revenues $ 32,789.2 $ 36,534.2 $ 29,241.5 (1) Revenues are accounted for under ASC 606. (2) Revenues are accounted for under ASC 605. Substantially all of our revenues are derived from contracts with customers as defined within ASC 606. The following information describes the nature of our significant revenue streams by segment and type: NGL Pipelines & Services Sales of NGLs and related products NGL marketing activities generate revenues from spot and term sales of NGLs and related products that 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 service contracts that are either fee-based, commodity-based or a combination of the two. When a cash fee for natural gas processing services is stipulated by a contract, we record revenue when a producer’s natural gas has been processed and redelivered. Our commodity-based contracts include keepwhole, margin-band, percent-of-liquids, percent-of-proceeds and contracts featuring a combination of commodity and fee-based terms. We recognize midstream service revenues in connection with the equity NGLs we receive under commodity-based contracts (once the processing service has been performed and we are entitled to such volumes). The value assigned to this non-cash consideration and related inventory is based on the market value of the equity NGLs at the time the services are performed. As noted previously, we also recognize product sales revenue, along with a corresponding cost of sales, when these NGLs are delivered and sold to downstream customers under NGL marketing contracts. Prior to the adoption of ASC 606, we did not recognize revenue in connection with the receipt of equity NGL volumes. We only recognized product sales revenue when the associated NGLs were delivered and sold to downstream customers under NGL marketing contracts. Following adoption of ASC 606, the additional midstream service revenue recognized for this non-cash consideration increased our total consolidated revenues by approximately 2% for the year ended December 31, 2018 when compared to the amount of revenues we would have recognized in 2018 if we had applied ASC 605. Furthermore, due to NGL pipeline transportation contracts and tariffs generate revenue based on a fixed fee per gallon 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 with a provision that allows the shipper to make-up any volume shortfalls over an agreed-upon period (referred to as “make-up rights”). Revenue attributable to such agreements is initially deferred and subsequently recognized at the earlier of when the deficiency volume is shipped, when the likelihood of the shipper’s ability to meet the minimum volume commitment becomes remote, or when the pipeline is otherwise released from its performance obligation. NGL fractionation generates revenue using fee-based arrangements. These fees are contractually subject to adjustment for changes in certain fractionation expenses (e.g., fuel costs) and are recognized in the period services are provided. NGL and related product storage contracts generate revenue from capacity reservations where we collect a fee for reserving storage capacity for customers in our underground storage wells and above-ground storage tanks. Under these agreements, revenue is recognized on a straight-line basis over the 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 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 attributable to such agreements is initially deferred and subsequently recognized at the earlier of when the deficiency volume is shipped, when the likelihood of the shipper’s ability to meet the minimum volume commitment becomes remote, or when the pipeline is otherwise released from its performance obligation. Crude oil storage contracts generate revenue from capacity reservations 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 reservation period. In addition, customers are billed a fee per unit of volume handled at our terminals. Revenue is recognized as the terminaling service is provided. 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, natural gas processing facilities, 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. Revenues under transportation contracts are recognized when the volumes are transported and delivered to customers. In addition, 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. Revenues are recognized when the firm capacity services are provided to the shipper. Petrochemical & Refined Products Services Sales of petrochemicals and refined products Our petrochemical and refined products marketing activities generate revenue from the sale and delivery of products to customers at market-based prices. The products handled by these marketing groups include polymer grade propylene, octane additives, high purity isobutylene and various refined products. Midstream services Propylene fractionation units and butane isomerization facilities generate revenue through fee-based tolling arrangements with customers. Revenue 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 from capacity reservations 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 reservation period. In addition, customers are billed a fee per unit of volume handled at our terminals. Revenue is recognized as the terminaling service is 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 the costs of fuel and other operating costs that are directly reimbursed by our marine customers. Unbilled Revenue and Deferred Revenue The following table provides information regarding our contract assets and contract liabilities at the dates indicated: December 31, Contract Asset Location 2019 2018 Unbilled revenue (current amount) Prepaid and other current assets $ 17.6 $ 13.3 Total $ 17.6 $ 13.3 December 31, Contract Liability Location 2019 2018 Deferred revenue (current amount) Other current liabilities $ 117.9 $ 80.9 Deferred revenue (noncurrent) Other long-term liabilities 197.0 210.3 Total $ 314.9 $ 291.2 The following table presents significant changes in our unbilled revenue and deferred revenue balances during the years indicated: Unbilled Revenue Deferred Revenue Balance at January 1, 2018 (upon adoption of ASC 606) $ – $ 224.7 Amount included in opening balance transferred to other accounts during period (1) – (90.8 ) Amount recorded during period 321.7 432.5 Amounts recorded during period transferred to other accounts (1) (310.6 ) (274.8 ) Amount recorded in connection with business combination 2.2 – Other changes – (0.4 ) Balance at December 31, 2018 $ 13.3 $ 291.2 Amount included in opening balance transferred to other accounts during period (1) (13.3 ) (126.4 ) Amount recorded during period 340.0 539.8 Amounts recorded during period transferred to other accounts (1) (322.4 ) (384.8 ) Amount recorded in connection with business combination – – Other changes – (4.9 ) Balance at December 31, 2019 $ 17.6 $ 314.9 (1) Unbilled revenues are transferred to accounts receivable once we have an unconditional right to consideration from the customer. Deferred revenues are recognized as revenue upon satisfaction of our performance obligation to the customer. Remaining Performance Obligations The following table presents estimated fixed future consideration from revenue contracts that contain minimum volume commitments, deficiency and similar fees and the term of the contracts exceeds one year. These amounts represent the revenues we expect to recognize in future periods from these contracts as of December 31, 2019. For a significant portion of our revenue, we bill customers a contractual rate for the services provided multiplied by the amount of volume handled in a given period. We have the right to invoice the customer in the amount that corresponds directly with the value of our performance completed to date. Therefore, we are not required to disclose information about the variable consideration of remaining performance obligations since we recognize revenue equal to the amount that we have the right to invoice. Period Fixed Consideration One Year Ended December 31, 2020 $ 3,654.6 One Year Ended December 31, 2021 3,363.9 One Year Ended December 31, 2022 3,062.7 One Year Ended December 31, 2023 2,857.8 One Year Ended December 31, 2024 2,743.8 Thereafte r 14,106.7 Total $ 29,789.5 Major Customer Information Our largest non-affiliated customer for the years ended December 31, 2019, 2018 and 2017 was Vitol Holding B.V. and its affiliates (collectively, “Vitol”), which accounted for approximately 10.1%, 7.8% and 11.2%, respectively, of our consolidated revenues. Vitol is a global energy and commodity trading company.

Business Segments

Business Segments	12 Months Ended
	Dec. 31, 2019
Business Segments [Abstract]
Business Segments	Note 10. Business Segments and Related Information 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 co-chief operating decision makers in deciding how to allocate resources and in assessing our operating and financial performance. The co-principal executive officers 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 assets and operations of each business segment (mileage and other statistics are unaudited): • Our NGL Pipelines & Services business segment currently includes natural gas processing facilities and associated NGL marketing activities; approximately 19,900 miles of NGL pipelines; NGL and related product storage facilities; and NGL fractionators. This segment also includes our NGL marine terminals and related operations. • Our Crude Oil Pipelines & Services business segment currently includes approximately 5,300 miles of crude oil pipelines, crude oil storage and marine terminals, and associated crude oil marketing activities. • Our Natural Gas Pipelines & Services business segment currently includes approximately 19,400 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 currently includes (i) propylene production facilities, which include propylene fractionation units and a PDH facility, approximately 800 miles of pipelines, and associated marketing operations; (ii) a butane isomerization complex and related deisobutanizer units; (iii) isobutane dehydrogenation, octane enhancement and high purity isobutylene production facilities; (iv) refined products pipelines aggregating approximately 3,300 miles, terminals and associated marketing activities; (v) an ethylene export terminal and related operations, and (v) marine transportation. Our plants, pipelines and other fixed assets are located in the U.S. 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. Our calculation of gross operating margin may or may not be comparable to similarly titled measures used by other companies. The following table presents our measurement of total segment gross operating margin for the years indicated. The GAAP financial measure most directly comparable to total segment gross operating margin is operating income. For the Year Ended December 31, 2019 2018 2017 Operating income $ 6,078.7 $ 5,408.6 $ 3,928.9 Adjustments to reconcile operating income to total gross operating margin (addition or subtraction indicated by sign): Depreciation, amortization and accretion expense in operating costs and expenses 1,848.3 1,687.0 1,531.3 Asset impairment and related charges in operating costs and expenses 132.7 50.5 49.8 Net gains attributable to asset sales in operating costs and expenses (5.7 ) (28.7 ) (10.7 ) General and administrative costs 211.7 208.3 181.1 Non-refundable payments received from shippers attributable to make-up rights (1) 47.0 21.5 24.1 Subsequent recognition of revenues attributable to make-up rights (2) (22.9 ) (56.2 ) (29.9 ) Total segment gross operating margin $ 8,289.8 $ 7,291.0 $ 5,674.6 (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 is initially deferred and subsequently recognized under GAAP at the earlier of when the deficiency volume is shipped, when the likelihood of the shipper’s ability to meet the minimum volume commitment becomes remote, or when the pipeline is otherwise released from its performance obligation. However, management includes deferred transportation revenues relating to the “make-up rights” of committed shippers when reviewing the financial results of certain pipelines (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 pipelines, 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 years indicated: For the Year Ended December 31, 2019 2018 2017 Gross operating margin by segment: NGL Pipelines & Services $ 4,069.8 $ 3,830.7 $ 3,258.3 Crude Oil Pipelines & Services 2,087.8 1,511.3 987.2 Natural Gas Pipelines & Services 1,062.6 891.2 714.5 Petrochemical & Refined Products Services 1,069.6 1,057.8 714.6 Total segment gross operating margin $ 8,289.8 $ 7,291.0 $ 5,674.6 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 Adjustments and Eliminations Consolidated Total Revenues from third parties: Year ended December 31, 2019 $ 13,460.8 $ 10,244.6 $ 3,154.7 $ 5,861.8 $ – $ 32,721.9 Year ended December 31, 2018 15,630.5 10,968.2 3,439.5 6,388.3 – 36,426.5 Year ended December 31, 2017 12,455.7 8,137.2 3,132.5 5,471.1 – 29,196.5 Revenues from related parties: Year ended December 31, 2019 9.9 42.7 14.7 – – 67.3 Year ended December 31, 2018 18.4 74.4 14.9 – – 107.7 Year ended December 31, 2017 12.3 19.6 13.1 – – 45.0 Intersegment and intrasegment revenues: Year ended December 31, 2019 20,840.4 34,613.0 624.7 2,481.3 (58,559.4 ) – Year ended December 31, 2018 26,453.6 35,490.4 721.9 2,917.5 (65,583.4 ) – Year ended December 31, 2017 27,278.6 15,943.0 850.8 1,766.9 (45,839.3 ) – Total revenues: Year ended December 31, 2019 34,311.1 44,900.3 3,794.1 8,343.1 (58,559.4 ) 32,789.2 Year ended December 31, 2018 42,102.5 46,533.0 4,176.3 9,305.8 (65,583.4 ) 36,534.2 Year ended December 31, 2017 39,746.6 24,099.8 3,996.4 7,238.0 (45,839.3 ) 29,241.5 Equity in income (loss) of unconsolidated affiliates: Year ended December 31, 2019 114.5 449.2 6.3 (7.0 ) – 563.0 Year ended December 31, 2018 117.0 365.4 6.8 (9.2 ) – 480.0 Year ended December 31, 2017 73.4 358.4 3.8 (9.6 ) – 426.0 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 unconsolidated affiliates) 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 gathering pipeline, natural gas processing facility, a crude oil pipeline or terminal, an NGL fractionator, an NGL storage facility or an NGL gathering or transportation pipeline. The assets of many of our equity investees are included within our integrated midstream network. For example, we use the Front Range Pipeline and Texas Express Pipeline to transport mixed NGLs to our Mont Belvieu NGL fractionation and storage complex and the Seaway Pipeline to transport crude oil to our terminals in the Houston, Texas area. Given the integral nature of these 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 Adjustments and Eliminations Consolidated Total Property, plant and equipment, net: At December 31, 2019 $ 16,652.1 $ 6,324.4 $ 8,432.5 $ 7,553.2 $ 2,641.2 $ 41,603.4 At December 31, 2018 14,845.4 5,847.7 8,303.8 6,213.9 3,526.8 38,737.6 At December 31, 2017 13,831.2 5,208.4 8,375.0 3,507.7 4,698.1 35,620.4 Investments in unconsolidated affiliates: At December 31, 2019 703.8 1,866.5 27.3 2.6 – 2,600.2 At December 31, 2018 662.0 1,867.5 22.8 62.8 – 2,615.1 At December 31, 2017 733.9 1,839.2 20.8 65.5 – 2,659.4 Intangible assets, net: At December 31, 2019 360.2 2,001.9 941.2 145.7 – 3,449.0 At December 31, 2018 380.1 2,094.6 979.3 154.4 – 3,608.4 At December 31, 2017 322.3 2,186.5 1,018.4 163.1 – 3,690.3 Goodwill: At December 31, 2019 2,651.7 1,841.0 296.3 956.2 – 5,745.2 At December 31, 2018 2,651.7 1,841.0 296.3 956.2 – 5,745.2 At December 31, 2017 2,651.7 1,841.0 296.3 956.2 – 5,745.2 Segment assets: At December 31, 2019 20,367.8 12,033.8 9,697.3 8,657.7 2,641.2 53,397.8 At December 31, 2018 18,539.2 11,650.8 9,602.2 7,387.3 3,526.8 50,706.3 At December 31, 2017 17,539.1 11,075.1 9,710.5 4,692.5 4,698.1 47,715.3 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 (a component of property, plant and equipment) does 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). Supplemental Revenue and Expense Information The following table presents additional information regarding our consolidated revenues and costs and expenses for the years indicated: For the Year Ended December 31, 2019 2018 2017 Consolidated revenues: NGL Pipelines & Services $ 13,470.7 $ 15,648.9 $ 12,468.0 Crude Oil Pipelines & Services 10,287.3 11,042.6 8,156.8 Natural Gas Pipelines & Services 3,169.4 3,454.4 3,145.6 Petrochemical & Refined Products Services 5,861.8 6,388.3 5,471.1 Total consolidated revenues $ 32,789.2 $ 36,534.2 $ 29,241.5 Consolidated costs and expenses: Operating costs and expenses: Cost of sales $ 22,065.8 $ 26,789.8 $ 21,487.0 Other operating costs and expenses (1) 3,020.7 2,898.7 2,500.1 Depreciation, amortization and accretion 1,848.3 1,687.0 1,531.3 Asset impairment and related charges 132.7 50.5 49.8 Ne t g (5.7 ) (28.7 ) (10.7 ) General and administrative costs 211.7 208.3 181.1 Total consolidated costs and expenses $ 27,273.5 $ 31,605.6 $ 25,738.6 (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 are lower. The same type of correlation would be true in the case of higher energy commodity sales prices and purchase costs.

Earnings Per Unit

Earnings Per Unit	12 Months Ended
	Dec. 31, 2019
Earnings Per Unit [Abstract]
Earnings Per Unit	Note 11. Earnings Per Unit The following table presents our calculation of basic and diluted earnings per unit for the years indicated: For the Year Ended December 31, 2019 2018 2017 BASIC EARNINGS PER UNIT Net income attributable to limited partners $ 4,591.3 $ 4,172.4 $ 2,799.3 Earnings allocated to phantom unit awards (1) (27.7 ) (21.5 ) (15.9 ) Net income available to common unitholders $ 4,563.6 $ 4,150.9 $ 2,783.4 Basic weighted-average number of common units outstanding 2,188.6 2,176.5 2,145.0 Basic earnings per unit $ 2.09 $ 1.91 $ 1.30 DILUTED EARNINGS PER UNIT Net income attributable to limited partners $ 4,591.3 $ 4,172.4 $ 2,799.3 Diluted weighted-average number of units outstanding: Distribution-bearing common units 2,188.6 2,176.5 2,145.0 Phantom units (1) 13.1 10.5 9.3 Total 2,201.7 2,187.0 2,154.3 Diluted earnings per unit $ 2.09 $ 1.91 $ 1.30 (1) Phantom units are considered participating securities for purposes of computing basic earnings per unit. See Note 13 for information regarding our phantom units.

Business Combinations

Business Combinations	12 Months Ended
	Dec. 31, 2019
Business Combinations [Abstract]
Business Combinations	Note 12. Business Combinations Acquisition of Delaware Processing In March 2018, we acquired the remaining 50% member interest in our former Delaware Processing joint venture for $151 million in cash, net of $3.9 million of cash held by the venture. As a result, Delaware Processing became a wholly-owned consolidated subsidiary of ours. Delaware Processing owns a cryogenic natural gas processing facility having a capacity of 150 million cubic feet per day (“MMcf/d”). The facility, which is located in Reeves County, Texas and entered service in August 2016, serves producers in the Delaware Basin in West Texas and southern New Mexico. The following table presents the final fair value allocation of assets acquired and liabilities assumed in the Delaware Processing acquisition. Purchase price for remaining 50% equity interest in Delaware Processing $ 154.5 Fair value of our 50% equity interest in Delaware Processing held before the acquisition 146.4 Total $ 300.9 Recognized amounts of identifiable assets acquired and liabilities assumed: Assets acquired in business combination: Current assets, including cash of $3.9 million $ 10.8 Property, plant and equipment 200.0 Contract-based intangible assets 82.6 Customer relationship intangible assets 9.9 Total assets acquired $ 303.3 Liabilities assumed in business combination: Current liabilities $ (1.8 ) Long-term liabilities (0.6 ) Total liabilities assumed $ (2.4 ) Total identifiable net assets $ 300.9 Goodwill $ – Prior to this acquisition, we accounted for our investment using the equity method. On a historical pro forma basis, our consolidated 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, 2018 and 2017 would not have differed materially from those we reported had the acquisition been completed on January 1, 2017 rather than March 29, 2018. At March 29, 2018, our 50% equity investment in Delaware Processing was recorded at $107.0 million. Upon acquisition of the remaining 50% member interest, our existing equity investment was remeasured to fair value resulting in the recognition of a non-cash $39.4 million gain, which is presented within “Other income (expense)” on our Consolidated Statement of Operations for the year ended December 31, 2018. The results for this business are reported under the NGL Pipelines & Services business segment. Acquisition of Azure Midstream In April 2017, we acquired a midstream energy business from Azure Midstream Partners, LP and its operating subsidiaries (collectively, “Azure”) for $191.4 million in cash. The acquired business consists of approximately 750 miles of natural gas gathering pipelines and two natural gas processing facilities located in East Texas. These assets serve producers working in 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 basis, our consolidated revenues, costs and expenses, operating income, net income attributable to Enterprise Products Partners L.P., and earnings per unit amounts for the year ended December 31, 2017 would not have differed materially from those we reported had the acquisition been completed on January 1, 2017 rather than April 30, 2017. The following table presents the final fair value allocation of assets acquired and liabilities assumed in the Azure acquisition. 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 identifiable net assets $ 191.4 The contribution of this acquired business to our consolidated revenues and net income was not material for the year ended December 31, 2017.

Equity-Based Awards

Equity-Based Awards	12 Months Ended
	Dec. 31, 2019
Equity-based Awards [Abstract]
Equity-based Awards	Note 13. 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 years indicated: For the Year Ended December 31, 2019 2018 2017 Equity-classified awards: Phantom unit awards $ 132.2 $ 99.7 $ 92.8 Profits interest awards 11.6 6.1 6.0 Restricted common unit awards – – 0.5 Liability-classified awards 0.1 0.3 0.4 Total $ 143.9 $ 106.1 $ 99.7 The fair value of equity-classified awards is amortized to 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. Phantom Unit Awards Subject to customary forfeiture provisions, phantom unit awards allow recipients to acquire EPD common units once a defined vesting period expires (at no cost to the recipient apart from fulfilling required service and other conditions). We expect phantom units to result in the issuance of common units upon vesting; therefore, these grants are accounted for as equity-classified awards. 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. The grant date fair value of a phantom unit award is based on the market price per unit of EPD 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 years indicated: Number of Units Weighted- Average Grant Date Fair Value per Unit Phantom unit awards at December 31, 2016 7,767,501 $ 27.20 Granted (2) 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 Granted (3) 5,006,181 $ 26.82 Vested (3,479,958 ) $ 28.57 Forfeited (482,447 ) $ 26.88 Phantom unit awards at December 31, 2018 10,333,277 $ 26.97 Granted (4) 6,854,920 $ 27.75 Vested (3,895,049 ) $ 27.53 Forfeited (318,464 ) $ 27.21 Phantom unit awards at December 31, 2019 12,974,684 $ 27.21 (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 2017 was $123.1 million based on a grant date market price of EPD common units ranging from $24.55 to $28.87 per unit. An estimated annual forfeiture rate of 3.8% was applied to these awards. (3) The aggregate grant date fair value of phantom unit awards issued during 2018 was $134.3 million based on a grant date market price of EPD common units ranging from $25.40 to $29.22 per unit. An estimated annual forfeiture rate of 3.2% was applied to these awards. (4) The aggregate grant date fair value of phantom unit awards issued during 2019 was $190.2 million based on a grant date market price of EPD common units ranging from $26.32 to $29.29 per unit. An estimated annual forfeiture rate of 3.0% was applied to these awards. The phantom unit awards were granted under the 2008 Plan, which 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 phantom units, options, restricted common units, unit appreciation rights, 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 EPD common units authorized for issuance under the 2008 Plan was 50,000,000 at December 31, 2019. This amount automatically increased under the terms of the 2008 Plan by 5,000,000 common units on January 1, 2020 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 (i) the time that all available common units under the 2008 Plan have been delivered to participants or (ii) the time of termination of the 2008 Plan by the Board of Directors of EPCO or by the Incentive Plan Administration Subcommittee of the Governance Committee of Enterprise GP. After giving effect to awards granted under the 2008 Plan through December 31, 2019, a total of 17,106,486 additional common units were available for issuance. After taking into account tax withholding requirements, we issued 2,720,603, 2,442,436 and 1,687,692 common units in connection with the vesting of phantom unit awards in the years ended December 31, 2019, 2018 and 2017, 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 by EPD to its 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 years indicated: For the Year Ended December 31, 2019 2018 2017 Cash payments made in connection with DERs $ 22.1 $ 17.7 $ 15.1 Total intrinsic value of phantom unit awards that vested during period $ 111.1 $ 90.7 $ 69.8 For the EPCO group of companies, the unrecognized compensation cost associated with phantom unit awards was $138.1 million at December 31, 2019, of which our share of such cost is currently estimated to be $113.3 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 2016 and 2018, EPCO Holdings Inc. (“EPCO Holdings”), a privately held affiliate of EPCO, contributed a portion of the EPD common units it owned to form limited partnerships (referred to as “Employee Partnerships”) that serve as long-term incentive arrangements for key employees of EPCO by providing them a “profits interest” in an Employee Partnership. The Employee Partnerships named (i) EPD PubCo Unit I L.P. (“PubCo I”), (ii) EPD PubCo Unit II L.P. (“PubCo II”), and (iii) EPD PrivCo Unit I L.P. (“PrivCo I”) were formed by EPCO Holdings in 2016. The Employee Partnerships named (i) EPD 2018 Unit IV L.P. (“EPD IV”) and (ii) EPCO Unit II L.P. (“EPCO II”) were formed by EPCO Holdings in 2018. In exchange for the contributions of EPD common units, 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. Each quarter, the Employee Partnerships, as owners of EPD common units, receive a cash distribution from EPD as do EPD’s other common unitholders. The cash received by the Employee Partnership is first used to pay the Class A limited partner a cash distribution equal to the product of (i) the number of EPD common units owned by the Employee Partnership and (ii) the Class A Preference Return (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 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, 2019: Employee Partnership EPD 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 0.3900 February 2020 $12.9 million $0.8 million PubCo II 2,834,198 $66.3 million 0.3900 February 2021 $14.9 million $4.0 million PrivCo I 1,111,438 $26.0 million 0.3900 February 2021 $5.8 million $0.3 million EPD IV 6,400,000 $172.9 million 0.4325 December 2023 $26.7 million $18.4 million EPCO II 1,600,000 $43.2 million 0.4325 December 2023 $6.6 million $0.5 million (1) Represents the fair market value of EPD common units contributed to each Employee Partnership at the applicable contribution date. (2) Represents the total grant date fair value of the profits interest awards awarded to the Class B limited partners of each Employee Partnership irrespective of how such costs will be allocated between us and EPCO and its privately held affiliates. (3) Represents our expected share of the unrecognized compensation cost at December 31, 2019. We expect to recognize our share of the unrecognized compensation cost for PubCo II, PrivCo I, EPD IV and EPCO II over a weighted-average period of 1.1 years, 1.1 years, 3.9 years and 3.9 years, respectively. The Class B limited partner interests of PubCo I vested on February 22, 2020. 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 2.7% 5.9% to 7.0% 15% to 40% PubCo II 5.0 years 1.1% to 3.0% 5.9% to 7.0% 19% to 40% PrivCo I 5.0 years 1.2% to 1.6% 6.1% to 6.7% 28% to 40% EPD IV 5.0 years 2.8% 6.5% 27% EPCO II 5.0 years 1.6% to 2.8% 6.3% to 6.8% 24% to 27% 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 allowed recipients to acquire EPD common units (at no cost to the recipient apart from fulfilling service and other conditions) once a defined vesting period expired, subject to customary forfeiture provisions. There have been no restricted common unit awards outstanding since 2017.

Derivative Instruments, Hedging

Derivative Instruments, Hedging Activities and Fair Value Measurements	12 Months Ended
	Dec. 31, 2019
Derivative Instruments, Hedging Activities and Fair Value Measurements [Abstract]
Derivative Instruments, Hedging Activities and Fair Value Measurements	Note 14. 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, options to enter into forward-starting swaps (“swaptions”), 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. Swaptions In 2019 and 2018, we sold options to be put into forward-starting swaps, or swaptions, if the market rate of interest fell below the strike rate of the option upon expiration of the derivative instrument. The premiums we realized upon sale of the swaptions are reflected as a $23.1 million and $29.4 million reduction in interest expense for the year ended December 31, 2019 and 2018, respectively. Due to declining interest rates, the counterparties to swaptions we sold in July 2019 exercised their right to put us into forward-starting swaps on September 30, 2019 having an aggregate notional value of $ billion. Since the swaptions were not designated as hedging instruments and were subject to mark-to-market accounting, we incurred an unrealized, mark-to-market loss at inception of the forward-starting swaps totaling $ million that is reflected as an increase in interest expense for the year ended December 31, 2019. The forward-starting swaps resulting from the swaption exercise on September 30, 2019 were designated as hedging instruments and are subject to cash flow hedge accounting. Forward-Starting Swaps Forward-starting swaps hedge the risk of an increase in underlying benchmark interest rates during the period of time between the inception date of the swap agreement and the future date of a debt issuance. Under the terms of the forward-starting swaps, we pay to the counterparties (at the expected settlement dates of the instruments) amounts based on a fixed interest rate applied to a notional amount and receive from the counterparties an amount equal to a variable interest rate (based on LIBOR or an equivalent index rate) on the same notional amount. The following table summarizes our portfolio of 30-year forward-starting swaps at December 31, 2019, all of which are associated with the expected future issuance of senior notes. Hedged Transaction Number and Type of Derivatives Outstanding Notional Amount Expected Settlement Date Weighted-Average Fixed Rate Locked Accounting Treatment Future long-term debt offering 1 forward-starting swap (1) $75.0 9/2020 2.39% Cash flow hedge Future long-term debt offering 1 forward-starting swap (1) $75.0 4/2021 2.41% Cash flow hedge Future long-term debt offering 5 forward-starting swaps (2) $500.0 9/2020 2.12% Cash flow hedge Future long-term debt offering 5 forward-starting swaps (2) $500.0 4/2021 2.13% Cash flow hedge (1) These swaps were entered into in May 2019. (2) These swaps were entered into in September 2019 as a result of the exercise of swaptions. In total, the notional amount of forward-starting swaps outstanding at December 31, 2019 was $1.15 billion. The weighted-average fixed interest rate of these derivative instruments is 2.16%. As a result of market conditions, million notional amount of forward-starting swaps in 2017, which resulted in cash proceeds totaling $ million. As cash flow hedges, gains on these derivative instruments are reflected as a component of accumulated other comprehensive income and are being amortized to earnings (as a decrease in interest expense) over the -year life of the associated debt through February 2048. amortized to earnings (as a decrease in interest expense) over a -year period through February 2049. 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, 2019, 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, 2019 (volume measures as noted): Volume Accounting Derivative Purpose Current Long-Term Treatment Derivatives designated as hedging instruments: Natural gas processing: Forecasted natural gas purchases for plant thermal reduction (Bcf) 3.9 n/a Cash flow hedge Forecasted sales of NGLs 0.8 n/a Cash flow hedge Octane enhancement: Forecasted purchase of NGLs (MMBbls) 0.6 n/a Cash flow hedge Forecasted sales of octane enhancement products (MMBbls) 11.2 0.1 Cash flow hedge Natural gas marketing: Forecasted purchases of natural gas (Bcf) 1.1 n/a Cash flow hedge Natural gas storage inventory management activities (Bcf) 3.0 n/a Fair value hedge NGL marketing: Forecasted purchases of NGLs and related hydrocarbon products (MMBbls) 103.5 n/a Cash flow hedge Forecasted sales of NGLs and related hydrocarbon products (MMBbls) 128.1 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) 0.2 n/a Cash flow hedge Forecasted sales of refined products (MMBbls) 0.2 n/a Cash flow hedge Crude oil marketing: Forecasted purchases of crude oil (MMBbls) 15.3 n/a Cash flow hedge Forecasted sales of crude oil (MMBbls) 19.9 n/a Cash flow hedge Propylene marketing: Forecasted sales of NGLs for propylene marketing activities (MMBbls) 0.5 n/a Cash flow hedge Derivatives not designated as hedging instruments: Natural gas risk management activities (Bcf) (3) 52.3 0.2 Mark-to-market NGL risk management activities (MMBbls) (3) 6.5 n/a Mark-to-market Refined products risk management activities (MMBbls) (3) 9.4 n/a Mark-to-market Crude oil risk management activities (MMBbls) (3) 27.3 11.0 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 January 2021, April 2020 and December 2022, respectively. (3) Reflects the use of derivative instruments to manage risks associated with transportation, processing and storage assets. The carrying amount of our inventories subject to fair value hedges was $31.7 million and $50.2 million at December 31, 2019 and 2018, respectively. 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, 2019 December 31, 2018 December 31, 2019 December 31, 2018 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 $ – Current liabilities $ 6.7 Current liabilities $ – Interest rate derivatives Other assets – Other assets – Other liabilities 6.8 Other liabilities – Total interest rate derivatives – – 13.5 – Commodity derivatives Current assets 116.5 Current assets 138.5 Current liabilities 107.1 Current liabilities 115.0 Commodity derivatives Other assets – Other assets 5.6 Other liabilities – Other liabilities 11.1 Total commodity derivatives 116.5 144.1 107.1 126.1 Total derivatives designated as hedging instruments $ 116.5 $ 144.1 $ 120.6 $ 126.1 Derivatives not designated as hedging instruments Commodity derivatives Current assets 10.7 Current assets 15.9 Current liabilities 8.6 Current liabilities 33.2 Commodity derivatives Other assets 0.6 Other assets 1.9 Other liabilities 0.5 Other liabilities 3.1 Total commodity derivatives 11.3 17.8 9.1 36.3 Total derivatives not designated as hedging instruments $ 11.3 $ 17.8 $ 9.1 $ 36.3 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, 2019: Commodity derivatives $ 127.8 $ – $ 127.8 $ (115.3 ) $ (11.0 ) $ – $ 1.5 As of December 31, 2018: Commodity derivatives $ 161.9 – $ 161.9 $ (158.6 ) $ – $ – $ 3.3 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, 2019: Interest rate derivatives $ 13.5 $ – $ 13.5 $ – $ – $ 13.5 Commodity derivatives 116.2 – 116.2 (115.3 ) – 0.9 As of December 31, 2018: Commodity derivatives $ 162.4 $ – $ 162.4 $ (158.6 ) $ (2.3 ) $ 1.5 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 years indicated: Derivatives in Fair Value Hedging Relationships Location Gain (Loss) Recognized in Income on Derivative For the Year Ended December 31, 2019 2018 2017 Interest rate derivatives Interest expense $ – $ 1.3 $ (0.2 ) Commodity derivatives Revenue 2.2 9.9 1.1 Total $ 2.2 $ 11.2 $ 0.9 Derivatives in Fair Value Hedging Relationships Location Gain (Loss) Recognized in Income on Hedged Item For the Year Ended December 31, 2019 2018 2017 Interest rate derivatives Interest expense $ – $ (1.4 ) $ 0.4 Commodity derivatives Revenue 6.9 (6.9 ) 27.4 Total $ 6.9 $ (8.3 ) $ 27.8 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 years indicated: Derivatives in Cash Flow Hedging Relationships Change in Value Recognized in Other Comprehensive Income (Loss) On Derivative For the Year Ended December 31, 2019 2018 2017 Interest rate derivatives $ 81.4 $ 22.2 $ (5.7 ) Commodity derivatives – Revenue (1) 55.8 293.0 (33.7 ) Commodity derivatives – Operating costs and expenses (1) (11.7 ) 0.2 (4.8 ) Total $ 125.5 $ 315.4 $ (44.2 ) (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 For the Year Ended December 31, 2019 2018 2017 Interest rate derivatives Interest expense $ (37.3 ) $ (38.1 ) $ (40.4 ) Commodity derivatives Revenue 152.4 131.7 (111.6 ) Commodity derivatives Operating costs and expenses (10.7 ) (1.3 ) (0.6 ) Total $ 104.4 $ 92.3 $ (152.6 ) Over the next twelve months, we expect to reclassify $39.7 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 $55.7 million of gains attributable to commodity derivative instruments from accumulated other comprehensive income to earnings, $55.4 million as an increase in revenue and $0.3 million as a decrease to operating costs and expenses. The following table presents the effect of our derivative instruments not designated as hedging instruments on our Statements of Consolidated Operations for the years indicated: Derivatives Not Designated as Hedging Instruments Location Gain (Loss) Recognized in Income on Derivative For the Year Ended December 31, 2019 2018 2017 Interest rate derivatives Interest expense $ (94.9 ) $ – $ – Commodity derivatives Revenue 102.2 (462.9 ) (42.7 ) Commodity derivatives Operating costs and expenses (12.4 ) 8.2 0.1 Total $ (5.1 ) $ (454.7 ) $ (42.6 ) The $5.1 million loss recognized for the year ended December 31, 2019 (as noted in the preceding table) from derivatives not designated as hedging instruments consists of (i) $24.2 million of realized gains and $65.6 million of net unrealized mark-to-market gains attributable to commodity derivatives and (ii) $94.9 million of unrealized mark-to-market losses attributable to interest rate derivatives. In total and inclusive of both fair value hedges and derivatives not designated as hedging instruments, unrealized mark-to-market gains (losses) included in gross operating margin and interest expense for the years indicated: For the Year Ended December 31, 2019 2018 2017 Mark-to-market gains (losses) in gross operating margin: NGL Pipelines & Services $ (5.5 ) $ 18.0 $ (11.2 ) Crude Oil Pipelines & Services 80.6 (44.1 ) (4.8 ) Natural Gas Pipelines & Services (0.2 ) 6.7 (9.4 ) Petrochemical & Refined Products Services (7.2 ) 1.7 2.4 Total mark-to-market impact on gross operating margin 67.7 (17.7 ) (23.0 ) Mark-to-market gains (losses) in interest expense (94.9 ) (0.1 ) 0.2 Total $ (27.2 ) $ (17.8 ) $ (22.8 ) 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 are presented before and after the application of Chicago Mercantile Exchange (“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 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. Derivative transactions cleared on exchanges other than the CME (e.g., the Intercontinental Exchange or ICE) continue to be reported on a gross basis. At December 31, 2019 Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Financial assets: Commodity derivatives: Value before application of CME Rule 814 $ 53.4 $ 343.7 $ 0.1 $ 397.2 Impact of CME Rule 814 change (47.0 ) (222.4 ) – (269.4 ) Total commodity derivatives 6.4 121.3 0.1 127.8 Total $ 6.4 $ 121.3 $ 0.1 $ 127.8 Financial liabilities: Liquidity Option (see Note 17) $ – $ – $ 509.6 $ 509.6 Interest rate derivatives – 13.5 – 13.5 Commodity derivatives: Value before application of CME Rule 814 88.1 273.6 0.3 362.0 Impact of CME Rule 814 change (81.9 ) (163.9 ) – (245.8 ) Total commodity derivatives 6.2 109.7 0.3 116.2 Total $ 6.2 $ 123.2 $ 509.9 $ 639.3 In the aggregate, the fair value of our commodity hedging portfolios at was a net derivative asset of $ At December 31, 2018 Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Financial assets: Commodity derivatives: Value before application of CME Rule 814 $ 172.3 $ 282.4 $ 2.2 $ 456.9 Impact of CME Rule 814 change (134.8 ) (159.3 ) (0.9 ) (295.0 ) Total commodity derivatives 37.5 123.1 1.3 161.9 Total $ 37.5 $ 123.1 $ 1.3 $ 161.9 Financial liabilities: Liquidity Option (see Note 17) $ – $ – $ 390.0 $ 390.0 Commodity derivatives: Value before application of CME Rule 814 85.5 291.2 21.4 398.1 Impact of CME Rule 814 change (48.6 ) (172.9 ) (14.2 ) (235.7 ) Total commodity derivatives 36.9 118.3 7.2 162.4 Total $ 36.9 $ 118.3 $ 397.2 $ 552.4 The following Fair Value At December 31, 2019 Financial Assets Financial Liabilities Valuation Techniques Unobservable Input Range Commodity derivatives – Crude oil $ 0.1 $ 0.3 Discounted cash flow Forward commodity prices $61.05-$62.14/barrel Total $ 0.1 $ 0.3 Fair Value At December 31, 2018 Financial Assets Financial Liabilities Valuation Techniques Unobservable Input Range Commodity derivatives – Crude oil $ 0.9 $ 0.8 Discounted cash flow Forward commodity prices $37.59-$51.99/barrel Commodity derivatives – Ethane 0.4 0.6 Discounted cash flow Forward commodity prices $0.28-$0.31/gallon Commodity derivatives – Propane – 1.0 Discounted cash flow Forward commodity prices $0.61-$0.66/gallon Commodity derivatives – Normal butane – 0.7 Discounted cash flow Forward commodity prices $0.66-$0.72/gallon Commodity derivatives – Natural gasoline – 4.1 Discounted cash flow Forward commodity prices $0.99-$1.01/gallon Total $ 1.3 $ 7.2 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, 2019. 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 is based on a number of Level 3 inputs. See Note 17 for a discussion of this liability. 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 years indicated: test For the Year Ended December 31, test Location 2019 2018 Financial asset (liability) balance, net, January 1 $ (395.9 ) $ (332.7 ) Total gains (losses) included in: Net income (1) Revenue 3.7 0.7 Net income Other expense, net – Liquidity Option (119.6 ) (56.1 ) Other comprehensive income (loss) Commodity derivative instruments – changes in fair value of cash flow hedges (2.1 ) (3.2 ) Settlements (1) Revenue (3.5 ) (1.9 ) Transfers out of Level 3 (2) 7.6 (2.7 ) Financial liability balance, net, December 31 $ (509.8 ) $ (395.9 ) (1) There were $0.2 million of unrealized gains and $1.2 million of unrealized losses included in these amounts for the years ended December 31, 2019 and 2018, 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, 2019 and 2018. Nonrecurring Fair Value Measurements Long-lived assets, which consist of 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. Similarly, we evaluate our equity method investments for impairment when there are events or changes in circumstances that indicate there is a potential loss in value of the investment attributable to an other than temporary decline. In the event we determine that the value of an investment is not recoverable due to an other than temporary decline, we record a non-cash impairment charge to adjust the carrying value of the investment to its estimated fair value. 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 include 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 that were subject to non-recurring fair value measurements during the year ended December 31, 2019: Fair Value Measurements at the End of the Reporting Period Using Carrying Value at December 31, 2019 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 $ – $ – $ – $ – $ 50.6 Long-lived assets held and used 0.3 – – 0.3 0.5 Total $ 51.1 As presented on our Statement of Consolidated Cash Flows, total non-cash asset impairment and related charges for the year ended December 31, 2019 were $132.8 million, which consisted of $76.4 million for the impairment of our investment in Centennial (see Note 5), $51.1 million of impairment charges attributable to long-lived assets and $5.3 million of impairment charges attributable to the write-down of surplus materials classified as current assets. The impairment charges attributable to long-lived assets were primarily due to the planned abandonment of certain terminal and natural gas processing plants in Texas. The following table presents categories of long-lived assets, primarily property, plant and equipment, that were subject to non-recurring fair value measurements during the year ended December 31, 2018: Fair Value Measurements at the End of the Reporting Period Using Carrying Value at December 31, 2018 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 $ – $ – $ – $ – $ 43.7 Long-lived assets held and used – – – – 3.1 Total $ 46.8 Total non-cash asset impairment and related charges during 2018 were $50.5 million, which consisted of $46.8 million of impairment charges attributable to long-lived assets and $3.7 million of impairment charges attributable to the write-down of surplus materials classified as current assets. The impairment charges attributable to long-lived assets were primarily due to the planned abandonment of certain terminal and natural gas processing plants in Texas. The following table presents categories of long-lived assets, primarily property, plant and equipment, that were subject to non-recurring fair value measurements during the year ended December 31, 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. The 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 and for the planned abandonment of certain storage and pipeline assets in Texas. 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 $30.37 billion and $25.97 billion at December 31, 2019 and 2018, respectively. The aggregate carrying value of these debt obligations was $27.15 billion and $26.15 billion at December 31, 2019 and 2018, 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 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, 2019
Related Party Transactions [Abstract]
Related Party Transactions	Note 15. Related Party Transactions The following table summarizes our related party transactions for the years indicated: For the Year Ended December 31, 2019 2018 2017 Revenues – related parties: Unconsolidated affiliates $ 67.3 $ 107.7 $ 45.0 Costs and expenses – related parties: EPCO and its privately held affiliates $ 1,145.3 $ 1,089.6 $ 1,010.9 Unconsolidated affiliates 403.1 447.4 223.4 Total $ 1,548.4 $ 1,537.0 $ 1,234.3 The following table summarizes our related party accounts receivable and accounts payable balances at the dates indicated: December 31, 2019 2018 Accounts receivable - related parties: Unconsolidated affiliates $ 2.5 $ 3.5 Accounts payable - related parties: EPCO and its privately held affiliates $ 143.7 $ 116.3 Unconsolidated affiliates 18.6 23.9 Total $ 162.3 $ 140.2 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, 2019 , 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 700,783,776 32% Of the total number of units held by EPCO and its privately held affiliates, 108,222,618 have been pledged as security under the credit facilities of EPCO and its privately held affiliates at December 31, 2019. 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 EPD’s 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, 2019, 2018 and 2017, we paid EPCO and its privately held affiliates cash distributions totaling $1.19 billion, $1.16 billion and $1.12 billion, respectively. From time-to-time, EPCO and its privately held affiliates elect to purchase additional common units under EPD’s DRIP and ATM program. During the years ended December 31, 2019, 2018 and 2017, privately held affiliates of EPCO reinvested $29 million, $213 million and $100 million, respectively, through our DRIP. See Note 8 for additional information regarding our DRIP and ATM program. We lease office space from affiliates of EPCO on a long-term basis. The rental rates in these lease agreements approximate market rates. For the years ended December 31, 2019, 2018 and 2017, we recognized $ $ EPCO ASA Under the ASA, EPCO provides us with the administrative and operating services deemed necessary to manage and operate our businesses, properties and assets (all in accordance with prudent industry practices). Our operating costs and expenses include amounts paid to EPCO for the actual direct and indirect costs it incurs to operate our facilities, including the compensation of its employees. Likewise, our general and administrative costs include amounts paid to EPCO for management and other 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). 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. The ASA allows us to participate as a named insured in EPCO’s overall insurance program, with the associated premiums and other costs being allocated to us. See Note 18 for additional information regarding our insurance programs. The following table presents our related party costs and expenses attributable to the ASA with EPCO for the years indicated: For the Year Ended December 31, 2019 2018 2017 Operating costs and expenses $ 1,000.2 $ 948.8 $ 882.1 General and administrative expenses 127.6 124.2 110.4 Total costs and expenses $ 1,127.8 $ 1,073.0 $ 992.5 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 unconsolidated affiliates: • For the years ended December 31, 2019, 2018 and 2017, we paid Seaway $194.5 million, $163.2 million and $98.8 million, respectively, for pipeline transportation and storage services in connection with our crude oil marketing activities. Revenues from Seaway were $42.7 million, $74.4 million and $19.6 million for the years ended December 31, 2019, 2018 and 2017, respectively. • For the years ended December 31, 2019 and 2018, we purchased $89.2 million and $157.9 million, respectively, of NGLs from VESCO. • We pay Promix for the transportation, storage and fractionation of NGLs. Expenses with Promix were $34.8 million, $31.9 million and $27.8 million for the years ended December 31, 2019, 2018 and 2017, respectively. In addition, we sell natural gas to Promix for its plant fuel requirements. Revenues from Promix were $9.1 million, $9.5 million and $7.8 million for the years ended December 31, 2019, 2018 and 2017, respectively. • For the years ended December 31, 2019, 2018 and 2017, we paid Texas Express $33.5 million, $57.6 million and $29.5 million, respectively, for pipeline transportation services. • For the years ended December 31, 2019, 2018 and 2017, we paid Eagle Ford Crude Oil Pipeline $36.0 million, $18.5 million and $42.8 million, respectively, for pipeline transportation services. • We perform management services for certain of our unconsolidated affiliates. We charged such affiliates $9.9 million, $11.6 million and $10.6 million for the years ended December 31, 2019, 2018 and 2017, respectively.

Provision for Income Taxes

Provision for Income Taxes	12 Months Ended
	Dec. 31, 2019
Provision for Income Taxes [Abstract]
Provision for Income Taxes	Note 16. 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, 2019, 2018 and 2017 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, 2019 2018 2017 Current portion of income tax provision (benefit): Federal $ (1.3 ) $ 5.3 $ 0.1 State 25.7 33.1 18.5 Foreign 1.2 0.5 1.0 Total current portion 25.6 38.9 19.6 Deferred portion of income tax provision (benefit): Federal 1.6 (0.3 ) (1.8 ) State 18.5 21.7 7.9 Foreign (0.1 ) – – Total deferred portion 20.0 21.4 6.1 Total provision for income taxes $ 45.6 $ 60.3 $ 25.7 A reconciliation of the provision for income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows: For the Year Ended December 31, 2019 2018 2017 Pre-Tax Net Book Income (“NBI”) $ 4,732.7 $ 4,298.8 $ 2,881.3 Texas Margin Tax (1) $ 44.2 $ 54.8 $ 26.4 State income taxes (net of federal benefit) 0.5 0.2 0.5 Federal income taxes computed by applying the federal statutory rate to NBI of corporate entities 0.9 2.1 0.1 Other permanent differences – 3.2 (1.3 ) Provision for income taxes $ 45.6 $ 60.3 $ 25.7 Effective income tax rate 1.0 % 1.4 % 0.9 % (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. The following table presents the significant components of deferred tax assets and deferred tax liabilities at the dates indicated: December 31, 2019 2018 Deferred tax liabilities: Attributable to property, plant and equipment $ 100.2 $ 80.8 Attributable to investments in partnerships 3.3 2.3 Total deferred tax liabilities 103.5 83.1 Less deferred tax assets: Net operating loss carryovers (1) 0.1 0.1 Temporary differences related to Texas Margin Tax 3.0 2.6 Total deferred tax assets 3.1 2.7 Total net deferred tax liabilities $ 100.4 $ 80.4 (1) These losses expire in various years between 2020 and 2037 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, 2019, 2018 or 2017.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies [Abstract]
Commitments and Contingencies	Note 17. 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, 2019 and 2018, our accruals for litigation contingencies were $0.2 million and $0.5 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. Energy Transfer Matter In connection with a proposed pipeline project, we and ETP signed a non-binding letter of intent in April 2011 that disclaimed any partnership or joint venture related to such project absent executed definitive documents and board approvals of the respective companies. Definitive agreements were never executed and board approval was never obtained for the potential pipeline project. In August 2011, the proposed pipeline project was cancelled due to a lack of customer support. In September 2011, ETP filed suit against us and a third party in connection with the cancelled project alleging, among other things, that we and ETP had formed a “partnership.” The case was tried in the District Court of Dallas County, Texas, 298th Judicial District. While we firmly believe, and argued during our defense, that no agreement was ever executed forming a legal joint venture or partnership between the parties, the jury found that the actions of the two companies, nevertheless, constituted a legal partnership. As a result, the jury found that ETP was wrongfully excluded from a subsequent pipeline project involving a third party, and awarded ETP $319.4 million in actual damages on March 4, 2014. On July 29, 2014, the trial court entered judgment against us in an aggregate amount of $535.8 million, which included (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 trial 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 Dallas 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 $ 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. We did not record a provision for this matter at December 31, 2019 as management believed that payment of damages by us was not probable. PDH Litigation In July 2013, we executed a contract with Foster Wheeler USA Corporation (“Foster Wheeler”) pursuant to which Foster Wheeler was to serve as the general contractor responsible for the engineering, procurement, construction and installation of our initial propane dehydrogenation (“PDH 1”) facility. In November 2014, Foster Wheeler was acquired by an affiliate of AMEC plc to form Amec Foster Wheeler plc, and Foster Wheeler is now known as Amec Foster Wheeler USA Corporation (“AFW”). In December 2015, Enterprise and AFW entered into a transition services agreement under which AFW was partially terminated from the PDH 1 project. In December 2015, Enterprise engaged a second contractor, Optimized Process Designs LLC, to complete the construction and installation of PDH 1. 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, 2019, we had approximately 8.9 trillion British thermal units (“TBtus”) of natural gas, 20.4 MMBbls of crude oil, and 38.1 MMBbls of NGL and petrochemical products in our custody that were owned by third parties. We maintain insurance coverage in connection with such volumes that 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 attributable to 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, 2019 . A description of each type of contractual obligation follows: Payment or Settlement due by Period Contractual Obligations Total 2020 2021 2022 2023 2024 Thereafter Scheduled maturities of debt obligations $ 27,878.4 $ 1,982.0 $ 1,325.0 $ 1,400.0 $ 1,250.0 $ 850.0 $ 21,071.4 Estimated cash interest payments $ 26,264.5 $ 1,224.7 $ 1,154.0 $ 1,101.2 $ 1,061.1 $ 1,023.0 $ 20,700.5 Operating lease obligations $ 271.2 $ 45.2 $ 40.1 $ 28.6 $ 20.2 $ 15.7 $ 121.4 Purchase obligations: Product purchase commitments: Estimated payment obligations: Natural gas $ 610.2 $ 345.4 $ 264.8 $ – $ – $ – $ – NGLs $ 5,534.7 $ 844.0 $ 911.1 $ 627.5 $ 548.1 $ 513.5 $ 2,090.5 Crude oil $ 14,025.5 $ 1,436.9 $ 1,677.2 $ 1,659.8 $ 1,532.1 $ 1,536.3 $ 6,183.2 Petrochemicals and refined products $ 384.0 $ 164.1 $ 77.2 $ 48.9 $ 48.9 $ 44.9 $ – Other $ 19.6 $ 7.6 $ 4.8 $ 2.8 $ 2.9 $ 1.5 $ – Service payment commitments $ 335.7 $ 66.6 $ 59.7 $ 57.7 $ 43.3 $ 14.5 $ 93.9 Capital expenditure commitments $ 45.8 $ 45.8 $ – $ – $ – $ – $ – Scheduled Maturities of Debt We have long-term and short-term payment obligations under debt agreements. Amounts shown in the preceding table represent our scheduled future maturities of debt principal for the years indicated. See Note 7 for additional information regarding our consolidated debt obligations. Estimated Cash Interest Payments Our estimated cash payments for interest are based on the principal amount of our consolidated debt obligations outstanding at December 31, 2019, the contractually scheduled maturities of such balances, and the applicable interest rates. Our estimated cash payments for interest are influenced by the long-term maturities of our $2.65 billion in junior subordinated notes (due June 2067 through February 2078). The estimated cash payments assume that (i) the junior subordinated notes are not repaid prior to their respective maturity dates and (ii) the amount of interest paid on the junior subordinated notes is based on either (a) the current fixed interest rate charged or (b) the weighted-average variable rate paid in 2019, as applicable, for each note through the respective maturity date. See Note 7 for information regarding fixed and weighted-average variable interest rates charged in 2019. Operating Lease Obligations We lease certain property, plant and equipment under noncancelable and cancelable operating leases. Amounts shown in the preceding table represent minimum cash lease payment obligations under our operating leases with terms in excess of one year. Our significant lease agreements consist of (i) land held pursuant to 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) office space leased from affiliates of EPCO. These 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. The following table presents information regarding operating leases where we are the lessee at December 31, 2019 : Asset Category ROU Asset Carrying Value Lease Liability Carrying Value Weighted- Average Remaining Term Weighted- Average Discount Rate Storage and pipeline facilities $ 137.9 $ 138.6 16 years 4.3 % Transportation equipment 49.9 52.4 3 years 3.5 % Office and warehouse space 22.4 21.0 2 years 3.4 % Total $ 210.2 $ 212.0 (1) ROU asset amounts are a component of “Other assets” on our consolidated balance sheet. (2) At December 31, 2019, lease liabilities of $40.4 million and $171.6 million were included within “ Other current liabilities ” and “ Other liabilities ,” (3) The discount rate for each category of assets represents the weighted average of either (i) the implicit rate applicable to the underlying leases (where determinable) or (ii) our incremental borrowing rate adjusted for collateralization (if the implicit rate is not determinable). In general, the discount rates are based on either (i) information available at the lease commencement date or (ii) January 1, 2019 for leases existing at the adoption date for ASC 842. In total, operating lease expense was $106.6 million, $86.4 million and $103.6 million for the years ended December 31, 2019, 2018 and 2017, respectively. The following table disaggregates our total operating lease expense for year ended December 31, 2019 : Long-term operating leases: Fixed lease expense: Non-cash lease expense (amortization of ROU assets) $ 42.8 Related accretion expense on lease liability balances 9.0 Total fixed lease expense 51.8 Variable lease expense 6.2 Subtotal operating lease expense 58.0 Short-term operating leases 48.6 Total operating lease expense $ 106.6 Fixed lease expense is charged to earnings on a straight-line basis over the contractual term, with any variable lease payments expensed as incurred. Short-term operating lease expense is expensed as incurred. Cash paid for operating lease liabilities recorded on our balance sheet was $48.1 million for the year ended December 31, 2019. We recognized $246.1 million in ROU assets and lease liabilities for long-term operating leases at January 1, 2019 in connection with the adoption of ASC 842. On an undiscounted basis, our long-term operating lease obligations aggregated to $314.4 million at January 1, 2019. We do not have any significant operating or direct financing leases where we are the lessor. Our operating lease income for the year ended December 31, 2019 was $ million. We do not have any sales-type leases. Purchase Obligations We define purchase obligations as agreements with remaining terms in excess of one year to purchase goods or services that are enforceable and legally binding (i.e., unconditional) on us that specify all significant terms, including (i) fixed or minimum quantities to be purchased, (ii) fixed, minimum or variable price provisions and (iii) the approximate timing of the transactions. We classify our unconditional purchase obligations into the following categories: • We have long-term product purchase obligations for natural gas, NGLs, crude oil, and 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 presents our estimated future payment obligations under these contracts based on the contractual price in each agreement at December 31, 2019 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, including those attributable to 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 expenditures, including our share of the capital expenditures of 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 We are obligated to spend up to an aggregate $270 million over a ten-year period ending in 2025 on specified midstream gathering assets for certain producers utilizing our EFS Midstream System. If constructed, these new assets would be owned by us and be a component of the EFS Midstream System. As of December 31, 2019, we have spent $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, 2019 2018 Noncurrent portion of AROs (see Note 4) $ 126.9 $ 121.4 Deferred revenues – non-current portion (see Note 9) 197.0 210.3 Liquidity Option liability 509.6 390.0 Lease liability – non-current portion 171.6 – Derivative liabilities 7.3 14.2 Other 20.0 15.7 Total $ 1,032.4 $ 751.6 We classify the Liquidity Option liability as long-term since we expect that it will be replaced by a long-term deferred tax liability of similar amount upon exercise of the Liquidity Option. See the following discussion titled “Liquidity Option” within this Note 17. Liquidity Option In October 2014, we acquired approximately 65.9% of the limited partner interests of Oiltanking Partners, L.P. (“Oiltanking”), all of the member interests of OTLP GP, LLC, the general partner of Oiltanking (“Oiltanking GP”), and the incentive distribution rights held by Oiltanking GP from Oiltanking Holding Americas, Inc. (“OTA”), a U.S. corporation, as the first step (“Step 1”) 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. In order to fund the equity consideration paid in Step 1 of the Oiltanking acquisition, we issued 54,807,352 common units to OTA on October 1, 2014 in a transaction exempt from the registration requirements of the Securities Act of 1933 (the “Securities Act”), as amended, pursuant to Section 4(a)(2) thereof. We also entered into a put option agreement (the “Liquidity Option Agreement” or “Liquidity Option”) with OTA and Marquard & Bahls AG (“M&B”), a German corporation and the ultimate parent company of OTA, in connection with Step 1. Under the Liquidity Option Agreement, the Partnership granted M&B the option to sell to the Partnership 100% of the issued and outstanding capital stock of OTA at any time within a 90-day period commencing on February 1, 2020. On February 25, 2020, the Partnership received notice from M&B of M&B’s election to exercise its Liquidity Option right. The Liquidity Option Agreement permits M&B to allow deferred tax liabilities to remain with OTA, including tax liabilities existing at the time of the sale of Oiltanking to us in 2014, and for M&B to directly receive EPD common units upon settlement of the Liquidity Option exercise that are unencumbered by any such liabilities. As a result, the liquidity of M&B is enhanced following exercise and settlement of the option, when compared to its financial position prior thereto (hence the name “Liquidity Option”). Under the terms of the Liquidity Option Agreement, the aggregate consideration to be paid by the Partnership for OTA’s capital stock at settlement will equal the volume-weighted sales price of EPD common units for the 10-trading day period immediately preceding the exercise notice date, multiplied by the 54,807,352 EPD common units owned by OTA. The consideration paid by the Partnership may be in the form of newly issued EPD common units, cash or any mix thereof, as determined solely by the Partnership. Settlement of the option exercise transaction is expected to occur on March 5, 2020. The Partnership currently expects that it will elect to deliver to M&B (or its designated affiliate) 54,807,352 newly issued EPD common units (in lieu of any cash) in connection with such settlement. Upon settlement of the Liquidity Option exercise, we will indirectly acquire the EPD common units owned by OTA, and assume all future income tax obligations of OTA associated with (i) owning EPD common units encumbered by the entity-level taxes of a U.S. corporation and (ii) the deferred tax liability as of the settlement date. In total, the partners’ capital balance for common units as presented on the Consolidated Balance Sheet will increase by the market value of the new EPD common units issued to M&B at settlement. The new EPD common units issued to M&B Our obligation to M&B to effect such transactions is limited to five registration statements and underwritten offerings. The acquisition of OTA OTA does not meet the definition of a business as described in ASC 805, Business Combinations . In consolidation, the EPD common units will be presented as treasury units held at cost, with cost measured as the fair value of consideration paid or issued to M&B in connection with exercise of the Liquidity Option. At December 31, 2019 and 2018, we estimated that our liability under the Liquidity Option Agreement, which is a component of “Other long-term liabilities” on our Consolidated Balance Sheet was $509.6 million and $390.0 million, respectively. The Liquidity Option liability, at any measurement date, represents the present value of estimated federal and state income taxes that we believe a market participant would incur due to ownership of OTA, including its deferred income tax liabilities. Our valuation estimate for the Liquidity Option liability at December 31, 2019 incorporates several estimates that are not readily observable in the market (i.e., Level 3 inputs) such as: (i) a discount rate of 5.7%; (ii) a blended federal and state income tax rate of approximately 22.8%; (iii) forecasted annual growth rates in our taxable earnings ranging from approximately 0.7% to 2.2%; (iv) allocations of Partnership income to OTA ranging from approximately 2.3% to 2.5%; and (v) the length of time that OTA is in existence following exercise of the option (up to 30 years). The valuation estimate reflects the most recent U.S. federal income tax reforms along with certain tax planning strategies that we believe could be employed by a market participant. 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, 2019, 2018 and 2017 include $ million, $ million and $ million, respectively, of aggregate non-cash expense attributable to accretion and changes in management estimates regarding inputs to the valuation model. The higher level of e When the Liquidity Option is exercised, the Liquidity Option liability will be replaced by the deferred income tax liabilities of OTA as calculated in accordance with ASC 740, Income Taxes

Significant Risks and Uncertain

Significant Risks and Uncertainties	12 Months Ended
	Dec. 31, 2019
Significant Risks and Uncertainties [Abstract]
Significant Risks and Uncertainties	Note 18. 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, and 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, NGL and crude oil volumes 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 for 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, crude oil, and petrochemicals and refined products and under 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. The primary markets for our services are the Gulf Coast, Southwest, Rocky Mountain, Northeast and Midwest regions of the U.S. We have a concentration of trade receivables due from independent and major integrated oil and gas companies and other pipelines and wholesalers operating in these markets. These concentrations may affect our overall credit risk in that these energy industry customers may be similarly affected by adverse 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 adverse 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 EPD 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, 2019
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	Note 19. 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 years indicated: For the Year Ended December 31, 2019 2018 2017 Decrease (increase) in: Accounts receivable – trade $ (1,248.8 ) $ 730.2 $ (1,076.2 ) Accounts receivable – related parties 0.9 (2.3 ) (0.7 ) Inventories (558.0 ) 121.4 194.6 Prepaid and other current assets (69.6 ) 214.4 226.0 Other assets (63.5 ) (9.7 ) (111.0 ) Increase (decrease) in: Accounts payable – trade (43.9 ) 18.3 66.6 Accounts payable – related parties 67.8 51.4 56.0 Accrued product payables 1,447.8 (1,132.0 ) 952.3 Accrued interest 36.1 37.6 17.3 Other current liabilities 58.1 (70.9 ) (291.4 ) Other liabilities (84.3 ) 57.8 (1.3 ) Net effect of changes in operating accounts $ (457.4 ) $ 16.2 $ 32.2 Cash payments for interest, net of $143.8, $147.9 and $192.1 capitalized in 2019, 2018 and 2017, respectively $ 1,080.3 $ 1,017.9 $ 912.1 Cash payments for federal and state income taxes $ 23.6 $ 15.5 $ 20.9 We incurred liabilities for construction in progress that had not been paid at December 31, 2019, 2018 and 2017 of $432.0 million, $567.6 million and $373.0 million, respectively. Such amounts are not included under the caption “Capital expenditures” on our Statements of Consolidated Cash Flows. Capital expenditures for the year ended December 31, 2017 reflect the receipt of $46.1 million of CIACs from third parties. The following table presents our cash proceeds from asset sales for the years indicated: For the Year Ended December 31, 2019 2018 2017 Cash proceeds from sale of crude oil pipeline system (the “Red River System”) $ – $ 134.9 $ – Cash proceeds from other asset sales 20.6 26.3 40.1 Total $ 20.6 $ 161.2 $ 40.1 The following table presents net gains (losses) attributable to asset sales for the years indicated: For the Year Ended December 31, 2019 2018 2017 Gains attributable to sale of Red River System $ – $ 20.6 $ – Net gains attributable to other asset sales 5.7 8.1 10.7 Total $ 5.7 $ 28.7 $ 10.7 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, 2019
Quarterly Financial Information (Unaudited) [Abstract]
Quarterly Financial Information (Unaudited)	Note 20. 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, 2019: Revenues $ 8,543.5 $ 8,276.3 $ 7,964.1 $ 8,005.3 Operating income 1,626.2 1,560.3 1,474.2 1,418.0 Net income 1,280.4 1,236.5 1,044.8 1,125.4 Net income attributable to limited partners 1,260.5 1,214.7 1,019.2 1,096.9 Earnings per unit: Basic $ 0.57 $ 0.55 $ 0.46 $ 0.50 Diluted $ 0.57 $ 0.55 $ 0.46 $ 0.50 For the Year Ended December 31, 2018: Revenues $ 9,298.5 $ 8,467.5 $ 9,585.9 $ 9,182.3 Operating income 1,138.5 986.4 1,643.3 1,640.4 Net income 911.5 687.2 1,334.6 1,305.2 Net income attributable to limited partners 900.7 673.8 1,313.2 1,284.7 Earnings per unit: Basic $ 0.41 $ 0.31 $ 0.60 $ 0.59 Diluted $ 0.41 $ 0.31 $ 0.60 $ 0.59 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, 2019
Condensed Consolidating Financial Information [Abstract]
Condensed Consolidating Financial Information	Note 21. 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, EPD guarantees substantially all of the debt obligations of EPO. If EPO were to default on any of its guaranteed debt, EPD would be responsible for full and unconditional repayment of that obligation. See Note 7 for additional information regarding our consolidated debt obligations. EPO’s consolidated subsidiaries have no significant restrictions on their ability to pay distributions or make loans to EPD. Enterprise Products Partners L.P. Condensed Consolidating Balance Sheet December 31, 2019 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 $ 109.2 $ 315.8 $ (15.1 ) $ 409.9 $ 0.1 $ – $ 410.0 Accounts receivable – trade, net 1,471.1 3,403.8 (1.3 ) 4,873.6 – – 4,873.6 Accounts receivable – related parties 233.1 799.9 (1,023.6 ) 9.4 – (6.9 ) 2.5 Inventories 1,351.3 740.4 (0.3 ) 2,091.4 – – 2,091.4 Derivative assets 115.2 12.0 – 127.2 – – 127.2 Prepaid and other current assets 221.0 183.5 (46.3 ) 358.2 – – 358.2 Total current assets 3,500.9 5,455.4 (1,086.6 ) 7,869.7 0.1 (6.9 ) 7,862.9 Property, plant and equipment, net 6,413.3 35,233.6 (43.5 ) 41,603.4 – – 41,603.4 Investments in unconsolidated affiliates 45,514.0 4,165.7 (47,079.5 ) 2,600.2 25,279.3 (25,279.3 ) 2,600.2 Intangible assets, net 636.7 2,852.3 (40.0 ) 3,449.0 – – 3,449.0 Goodwill 459.5 5,285.7 – 5,745.2 – – 5,745.2 Other assets 404.9 288.5 (221.9 ) 471.5 1.0 – 472.5 Total assets $ 56,929.3 $ 53,281.2 $ (48,471.5 ) $ 61,739.0 $ 25,280.4 $ (25,286.2 ) $ 61,733.2 LIABILITIES AND EQUITY Current liabilities: Current maturities of debt $ 1,981.9 $ – $ – $ 1,981.9 $ – $ – $ 1,981.9 Accounts payable – trade 301.4 717.7 (14.6 ) 1,004.5 – – 1,004.5 Accounts payable – related parties 977.5 222.3 (1,037.5 ) 162.3 6.9 (6.9 ) 162.3 Accrued product payables 1,895.4 3,021.9 (1.6 ) 4,915.7 – – 4,915.7 Accrued interest 431.6 0.9 (0.8 ) 431.7 – – 431.7 Derivative liabilities 114.2 8.2 – 122.4 – – 122.4 Other current liabilities 120.5 438.2 (47.3 ) 511.4 – (0.2 ) 511.2 Total current liabilities 5,822.5 4,409.2 (1,101.8 ) 9,129.9 6.9 (7.1 ) 9,129.7 Long-term debt 25,628.6 14.6 – 25,643.2 – – 25,643.2 Deferred tax liabilities 22.2 75.6 (0.8 ) 97.0 – 3.4 100.4 Other long-term liabilities 161.2 608.9 (247.2 ) 522.9 509.5 – 1,032.4 Commitments and contingencies Equity: Partners’ and other owners’ equity 25,294.8 48,107.6 (48,155.3 ) 25,247.1 24,764.0 (25,247.1 ) 24,764.0 Noncontrolling interests – 65.3 1,033.6 1,098.9 – (35.4 ) 1,063.5 Total equity 25,294.8 48,172.9 (47,121.7 ) 26,346.0 24,764.0 (25,282.5 ) 25,827.5 Total liabilities and equity $ 56,929.3 $ 53,281.2 $ (48,471.5 ) $ 61,739.0 $ 25,280.4 $ (25,286.2 ) $ 61,733.2 Enterprise Products Partners L.P. Condensed Consolidating Balance Sheet December 31, 2018 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 $ 393.4 $ 50.3 $ (33.6 ) $ 410.1 $ – $ – $ 410.1 Accounts receivable – trade, net 1,303.1 2,356.8 (0.8 ) 3,659.1 – – 3,659.1 Accounts receivable – related parties 141.8 1,423.7 (1,530.1 ) 35.4 0.8 (32.7 ) 3.5 Inventories 889.3 633.2 (0.4 ) 1,522.1 – – 1,522.1 Derivative assets 105.0 49.1 0.3 154.4 – – 154.4 Prepaid and other current assets 166.0 155.1 (10.2 ) 310.9 – 0.6 311.5 Total current assets 2,998.6 4,668.2 (1,574.8 ) 6,092.0 0.8 (32.1 ) 6,060.7 Property, plant and equipment, net 6,112.7 32,628.7 (3.8 ) 38,737.6 – – 38,737.6 Investments in unconsolidated affiliates 43,962.6 4,170.6 (45,518.1 ) 2,615.1 24,273.6 (24,273.6 ) 2,615.1 Intangible assets, net 659.2 2,963.0 (13.8 ) 3,608.4 – – 3,608.4 Goodwill 459.5 5,285.7 – 5,745.2 – – 5,745.2 Other assets 292.1 131.9 (222.1 ) 201.9 0.9 – 202.8 Total assets $ 54,484.7 $ 49,848.1 $ (47,332.6 ) $ 57,000.2 $ 24,275.3 $ (24,305.7 ) $ 56,969.8 LIABILITIES AND EQUITY Current liabilities: Current maturities of debt $ 1,500.0 $ 0.1 $ – $ 1,500.1 $ – $ – $ 1,500.1 Accounts payable – trade 404.0 734.3 (35.5 ) 1,102.8 – – 1,102.8 Accounts payable – related parties 1,557.3 127.5 (1,543.9 ) 140.9 31.9 (32.6 ) 140.2 Accrued product payables 1,574.7 1,902.3 (1.2 ) 3,475.8 – – 3,475.8 Accrued interest 395.5 0.9 (0.8 ) 395.6 – – 395.6 Derivative liabilities 86.2 61.7 0.3 148.2 – – 148.2 Other current liabilities 87.9 326.3 (9.4 ) 404.8 – – 404.8 Total current liabilities 5,605.6 3,153.1 (1,590.5 ) 7,168.2 31.9 (32.6 ) 7,167.5 Long-term debt 24,663.4 14.7 – 24,678.1 – – 24,678.1 Deferred tax liabilities 17.0 62.0 (0.9 ) 78.1 – 2.3 80.4 Other long-term liabilities 65.2 518.4 (221.9 ) 361.7 389.9 – 751.6 Commitments and contingencies Equity: Partners’ and other owners’ equity 24,133.5 46,031.8 (45,917.9 ) 24,247.4 23,853.5 (24,247.4 ) 23,853.5 Noncontrolling interests – 68.1 398.6 466.7 – (28.0 ) 438.7 Total equity 24,133.5 46,099.9 (45,519.3 ) 24,714.1 23,853.5 (24,275.4 ) 24,292.2 Total liabilities and equity $ 54,484.7 $ 49,848.1 $ (47,332.6 ) $ 57,000.2 $ 24,275.3 $ (24,305.7 ) $ 56,969.8 Enterprise Products Partners L.P. Condensed Consolidating Statement of Operations For the Year Ended December 31, 2019 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 $ 35,396.9 $ 21,849.0 $ (24,456.7 ) $ 32,789.2 $ – $ – $ 32,789.2 Costs and expenses: Operating costs and expenses 34,074.1 17,438.7 (24,451.0 ) 27,061.8 – – 27,061.8 General and administrative costs 32.2 174.2 3.1 209.5 2.2 – 211.7 Total costs and expenses 34,106.3 17,612.9 (24,447.9 ) 27,271.3 2.2 – 27,273.5 Equity in income of unconsolidated affiliates 4,667.1 648.7 (4,752.8 ) 563.0 4,713.0 (4,713.0 ) 563.0 Operating income 5,957.7 4,884.8 (4,761.6 ) 6,080.9 4,710.8 (4,713.0 ) 6,078.7 Other income (expense): Interest expense (1,243.8 ) (10.5 ) 11.3 (1,243.0 ) – – (1,243.0 ) Other, net 19.8 8.0 (11.3 ) 16.5 (119.5 ) – (103.0 ) Total other expense, net (1,224.0 ) (2.5 ) – (1,226.5 ) (119.5 ) – (1,346.0 ) Income before income taxes 4,733.7 4,882.3 (4,761.6 ) 4,854.4 4,591.3 (4,713.0 ) 4,732.7 Provision for income taxes (16.5 ) (28.3 ) 0.3 (44.5 ) – (1.1 ) (45.6 ) Net income 4,717.2 4,854.0 (4,761.3 ) 4,809.9 4,591.3 (4,714.1 ) 4,687.1 Net loss (income) attributable to noncontrolling interests – (6.6 ) (94.7 ) (101.3 ) – 5.5 (95.8 ) Net income attributable to entity $ 4,717.2 $ 4,847.4 $ (4,856.0 ) $ 4,708.6 $ 4,591.3 $ (4,708.6 ) $ 4,591.3 Enterprise Products Partners L.P. Condensed Consolidating Statement of Operations For the Year Ended December 31, 2018 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 $ 42,946.4 $ 23,756.4 $ (30,168.6 ) $ 36,534.2 $ – $ – $ 36,534.2 Costs and expenses: Operating costs and expenses 41,718.2 19,845.2 (30,166.1 ) 31,397.3 – – 31,397.3 General and administrative costs 31.8 172.0 2.1 205.9 2.3 0.1 208.3 Total costs and expenses 41,750.0 20,017.2 (30,164.0 ) 31,603.2 2.3 0.1 31,605.6 Equity in income of unconsolidated affiliates 4,148.3 587.2 (4,255.5 ) 480.0 4,230.8 (4,230.8 ) 480.0 Operating income 5,344.7 4,326.4 (4,260.1 ) 5,411.0 4,228.5 (4,230.9 ) 5,408.6 Other income (expense): Interest expense (1,097.1 ) (10.5 ) 10.9 (1,096.7 ) – – (1,096.7 ) Other, net 12.1 41.8 (10.9 ) 43.0 (56.1 ) – (13.1 ) Total other expense, net (1,085.0 ) 31.3 – (1,053.7 ) (56.1 ) – (1,109.8 ) Income before income taxes 4,259.7 4,357.7 (4,260.1 ) 4,357.3 4,172.4 (4,230.9 ) 4,298.8 Provision for income taxes (29.2 ) (29.6 ) – (58.8 ) – (1.5 ) (60.3 ) Net income 4,230.5 4,328.1 (4,260.1 ) 4,298.5 4,172.4 (4,232.4 ) 4,238.5 Net loss (income) attributable to noncontrolling interests – (7.6 ) (63.8 ) (71.4 ) – 5.3 (66.1 ) Net income attributable to entity $ 4,230.5 $ 4,320.5 $ (4,323.9 ) $ 4,227.1 $ 4,172.4 $ (4,227.1 ) $ 4,172.4 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 Comprehensive Income For the Year Ended December 31, 2019 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 $ 4,890.2 $ 4,701.5 $ (4,761.3 ) $ 4,830.4 $ 4,611.8 $ (4,734.6 ) $ 4,707.6 Comprehensive loss (income) attributable to noncontrolling interests – (6.6 ) (94.7 ) (101.3 ) – 5.5 (95.8 ) Comprehensive income attributable to entity $ 4,890.2 $ 4,694.9 $ (4,856.0 ) $ 4,729.1 $ 4,611.8 $ (4,729.1 ) $ 4,611.8 Enterprise Products Partners L.P. Condensed Consolidating Statement of Comprehensive Income For the Year Ended December 31, 2018 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 $ 4,312.6 $ 4,468.5 $ (4,260.1 ) $ 4,521.0 $ 4,395.0 $ (4,454.9 ) $ 4,461.1 Comprehensive loss (income) attributable to noncontrolling interests – (7.6 ) (63.8 ) (71.4 ) – 5.3 (66.1 ) Comprehensive income attributable to entity $ 4,312.6 $ 4,460.9 $ (4,323.9 ) $ 4,449.6 $ 4,395.0 $ (4,449.6 ) $ 4,395.0 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 Cash Flows For the Year Ended December 31, 2019 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 $ 4,717.2 $ 4,854.0 $ (4,761.3 ) $ 4,809.9 $ 4,591.3 $ (4,714.1 ) $ 4,687.1 Reconciliation of net income to net cash flows provided by operating activities: Depreciation, amortization and accretion 309.0 1,642.7 (2.4 ) 1,949.3 – – 1,949.3 Equity in income of unconsolidated affiliates (4,667.1 ) (648.7 ) 4,752.8 (563.0 ) (4,713.0 ) 4,713.0 (563.0 ) Distributions received from unconsolidated affiliates attributable to earnings 1,560.7 317.7 (1,310.4 ) 568.0 4,005.8 (4,005.8 ) 568.0 Net effect of changes in operating accounts and other operating activities 3,007.5 (3,294.0 ) 35.5 (251.0 ) 129.9 0.2 (120.9 ) Net cash flows provided by operating activities 4,927.3 2,871.7 (1,285.8 ) 6,513.2 4,014.0 (4,006.7 ) 6,520.5 Investing activities: Capital expenditures (675.4 ) (3,850.2 ) (6.1 ) (4,531.7 ) – – (4,531.7 ) Proceeds from asset sales 2.3 18.3 – 20.6 – – 20.6 Other investing activities (2,080.6 ) 3.7 2,012.5 (64.4 ) (119.3 ) 119.3 (64.4 ) Cash used in investing activities (2,753.7 ) (3,828.2 ) 2,006.4 (4,575.5 ) (119.3 ) 119.3 (4,575.5 ) Financing activities: Borrowings under debt agreements 58,172.6 – – 58,172.6 – – 58,172.6 Repayments of debt (56,716.4 ) (0.1 ) – (56,716.5 ) – – (56,716.5 ) Cash distributions paid to partners (4,005.8 ) (1,871.7 ) 1,871.7 (4,005.8 ) (3,839.8 ) 4,005.8 (3,839.8 ) Cash payments made in connection with DERs – – – – (22.1 ) – (22.1 ) Cash distributions paid to noncontrolling interests – (9.5 ) (97.6 ) (107.1 ) – 0.9 (106.2 ) Cash contributions from noncontrolling interests – – 632.8 632.8 – – 632.8 Net cash proceeds from issuance of common units – – – – 82.2 – 82.2 Common units acquired in connection with 2019 Buyback Program – – – – (81.1 ) – (81.1 ) Cash contributions from owners 119.3 3,109.0 (3,109.0 ) 119.3 – (119.3 ) – Other financing activities (27.5 ) (5.7 ) – (33.2 ) (33.8 ) – (67.0 ) Cash provided by (used in) financing activities (2,457.8 ) 1,222.0 (702.1 ) (1,937.9 ) (3,894.6 ) 3,887.4 (1,945.1 ) Net change in cash and cash equivalents, including restricted cash (284.2 ) 265.5 18.5 (0.2 ) 0.1 – (0.1 ) Cash and cash equivalents, including restricted cash, January 1 393.4 50.3 (33.6 ) 410.1 – – 410.1 Cash and cash equivalents, including restricted cash, December 31 $ 109.2 $ 315.8 $ (15.1 ) $ 409.9 $ 0.1 $ – $ 410.0 Enterprise Products Partners L.P. Condensed Consolidating Statement of Cash Flows For the Year Ended December 31, 2018 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 $ 4,230.5 $ 4,328.1 $ (4,260.1 ) $ 4,298.5 $ 4,172.4 $ (4,232.4 ) $ 4,238.5 Reconciliation of net income to net cash flows provided by operating activities: Depreciation, amortization and accretion 279.9 1,512.1 (0.4 ) 1,791.6 – – 1,791.6 Equity in income of unconsolidated affiliates (4,148.3 ) (587.2 ) 4,255.5 (480.0 ) (4,230.8 ) 4,230.8 (480.0 ) Distributions received from unconsolidated affiliates attributable to earnings 1,248.9 263.0 (1,032.5 ) 479.4 3,780.0 (3,780.0 ) 479.4 Net effect of changes in operating accounts and other operating activities 3,221.5 (3,244.2 ) (2.3 ) (25.0 ) 121.2 0.6 96.8 Net cash flows provided by operating activities 4,832.5 2,271.8 (1,039.8 ) 6,064.5 3,842.8 (3,781.0 ) 6,126.3 Investing activities: Capital expenditures (692.0 ) (3,476.0 ) – (4,168.0 ) (55.2 ) – (4,223.2 ) Cash used for business combinations, net of cash received – (150.6 ) – (150.6 ) – – (150.6 ) Proceeds from asset sales 129.3 31.9 – 161.2 – – 161.2 Other investing activities (2,288.2 ) 196.2 2,023.0 (69.0 ) (523.3 ) 523.3 (69.0 ) Cash used in investing activities (2,850.9 ) (3,398.5 ) 2,023.0 (4,226.4 ) (578.5 ) 523.3 (4,281.6 ) Financing activities: Borrowings under debt agreements 79,588.7 11.5 (11.5 ) 79,588.7 – – 79,588.7 Repayments of debt (77,956.7 ) (0.4 ) – (77,957.1 ) – – (77,957.1 ) Cash distributions paid to partners (3,780.0 ) (1,333.1 ) 1,333.1 (3,780.0 ) (3,726.9 ) 3,780.0 (3,726.9 ) Cash payments made in connection with DERs – – – – (17.7 ) – (17.7 ) Cash distributions paid to noncontrolling interests – (9.2 ) (73.4 ) (82.6 ) – 1.0 (81.6 ) Cash contributions from noncontrolling interests – – 238.1 238.1 – – 238.1 Net cash proceeds from issuance of common units – – – – 538.4 – 538.4 Common units acquired in connection with Legacy Buyback Program – – – – (30.8 ) – (30.8 ) Cash contributions from owners 523.3 2,476.7 (2,476.7 ) 523.3 – (523.3 ) – Other financing activities (28.7 ) – – (28.7 ) (27.3 ) – (56.0 ) Cash provided by (used in) financing activities (1,653.4 ) 1,145.5 (990.4 ) (1,498.3 ) (3,264.3 ) 3,257.7 (1,504.9 ) Net change in cash and cash equivalents, including restricted cash 328.2 18.8 (7.2 ) 339.8 – – 339.8 Cash and cash equivalents, including restricted cash, January 1 65.2 31.5 (26.4 ) 70.3 – – 70.3 Cash and cash equivalents, including restricted cash, December 31 $ 393.4 $ 50.3 $ (33.6 ) $ 410.1 $ – $ – $ 410.1 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 from unconsolidated affiliates attributable to earnings 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 (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 and cash equivalents, including restricted cash (301.0 ) (27.4 ) (18.9 ) (347.3 ) – – (347.3 ) Cash and cash equivalents, including restricted cash, January 1 366.2 58.9 (7.5 ) 417.6 – – 417.6 Cash and cash equivalents, including restricted cash, December 31 $ 65.2 $ 31.5 $ (26.4 ) $ 70.3 $ – $ – $ 70.3

Subsequent Event

Subsequent Event	12 Months Ended
	Dec. 31, 2019
Subsequent Event [Abstract]
Subsequent Event	Note 22. Subsequent Event Issuance of $3.0 Billion of Senior Notes in January 2020 In January 2020, EPO issued $3.0 billion aggregate principal amount of senior notes comprised of (i) $1.0 billion principal amount of senior notes due January 2030 (“Senior Notes AAA”), (ii) $1.0 billion principal amount of senior notes due January 2051 (“Senior Notes BBB”) and (iii) $1.0 billion principal amount of senior notes due January 2060 (“Senior Notes CCC”). Net proceeds from this offering were used by EPO for the repayment of $500 million principal amount of its Senior Notes Q that matured in January 2020, temporary repayment of amounts outstanding under its commercial paper program and for general company purposes. In addition, net proceeds from this offering will be used by EPO for the repayment of $1.0 billion principal amount of its Senior Notes Y upon their maturity in September 2020. Senior Notes AAA were issued at 99.921% of their principal amount and have a fixed-rate interest rate of 2.80% per year. Senior Notes BBB were issued at 99.413% of their principal amount and have a fixed-rate interest rate of 3.70% per year. Senior Notes CCC were issued at 99.360% of their principal amount and have a fixed-rate interest rate of 3.95% per year. EPD guaranteed these senior notes through an unconditional guarantee on an unsecured and unsubordinated basis. In January 2020, we terminated an aggregate $575 million notional amount of forward-starting swaps (cash flow hedges), which resulted in cash payments of $33.3 million. The termination of these swaps was done in connection with EPO’s issuance of $3.0 billion aggregate principal amount of senior notes in January 2020. Exercise of Liquidity Option in February 2020 On February 25, 2020, the Partnership received notice from M&B of M&B’s election to exercise its Liquidity Option right. Settlement of the option exercise transaction is expected to occur on March 5, 2020. For additional information regarding the Liquidity Option and the effects of the option exercise, see Note 17.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2019
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 years indicated: For the Year Ended December 31, 2019 2018 2017 Balance at beginning of period $ 11.5 $ 12.1 $ 11.3 Charged to costs and expenses 1.2 0.7 2.7 Deductions (0.3 ) (1.3 ) (1.9 ) Balance at end of period $ 12.4 $ 11.5 $ 12.1 See “Credit Risk” in Note 18 for additional information. In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-13, “ Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments
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 primarily 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. See Note 14 for information regarding our derivative instruments and hedging activities. 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, 2019 2018 Cash and cash equivalents $ 334.7 $ 344.8 Restricted cash 75.3 65.3 Total cash, cash equivalents and restricted cash shown in the Statements of Consolidated Cash Flows $ 410.0 $ 410.1
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 8 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 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 change in the fair value of the hedge is reported in other comprehensive income (loss) and is reclassified to 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. 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, 2019, 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 years indicated: For the Year Ended December 31, 2019 2018 2017 Balance at beginning of period $ 6.9 $ 11.6 $ 11.9 Charged to costs and expenses 12.3 8.2 12.1 Acquisition-related additions and other 2.5 1.7 1.7 Deductions (14.5 ) (14.6 ) (14.1 ) Balance at end of period $ 7.2 $ 6.9 $ 11.6 At December 31, 2019 and 2018, $5.8 million and $3.2 million, respectively, of our environmental reserves were classified as current liabilities.
Estimates	Estimates Preparing our consolidated financial statements in conformity with U.S. GAAP requires us to make estimates that affect amounts presented in the financial statements. Our most significant estimates relate to (i) the useful lives and depreciation/amortization methods used for fixed and identifiable intangible assets; (ii) measurement of fair value and projections used in impairment testing of fixed and intangible assets (including goodwill); (iii) contingencies; and (iv) revenue and expense accruals. Actual results could differ materially from our estimates. On an ongoing basis, we review our estimates based on currently available information. Any changes in the facts and circumstances underlying our estimates may require us to update such estimates, which could have a material impact on our consolidated financial statements.
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 third-party yield curves 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 the following commodity derivative instruments which are used to hedge our various inventories and transportation capacities: (i) NGL-based contracts with terms greater than one year; (ii) crude, natural gas and refined products-based contracts with terms greater than 36 months; (iii) over-the-counter options; and (iv) exchange traded options with terms greater than one year. 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.
Impairment Testing for Goodwill	Impairment Testing for Goodwill See Note 6 for information regarding our annual goodwill impairment test.
Impairment Testing for Long-Lived Assets	Impairment Testing for Long-Lived Assets Long-lived assets, which consist of 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 estimated 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 when there are events or changes in circumstances that indicate there is a potential 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 value of an investment is not recoverable due to an other than temporary decline, we record a non-cash impairment charge to adjust the carrying value of the investment to its estimated fair value. There were no impairment charges related to our equity method investments during the years ended December 31, and . In 2019, we recorded a $ See Note 5 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 3 for additional information regarding our inventories.
Leases	Leases In February 2016, the FASB issued Accounting Standards Codification (“ASC”) 842, Leases Leases The new standard introduces two lessee accounting models, which results in a lease being classified as either a “finance” or “operating” lease based on 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 ASC 840 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 right-of-use (“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. For finance leases, a lessee will amortize the ROU asset (generally on a straight-line basis in a manner similar to depreciation) and accrete the lease liability (as a component of interest expense) using the . Operating leases will result in the recognition of a single lease expense amount that is recorded on a straight-line basis. ASC 842 resulted in changes to the way our operating leases are recorded, presented and disclosed in our consolidated financial statements. Upon adoption of ASC 842 on January 1, 2019, we recognized a ROU asset and a corresponding lease liability based on the present value of then existing long-term operating lease obligations. In addition, we elected to apply several practical expedients and made accounting policy elections upon adoption of ASC 842 including: • We do not recognize ROU assets and lease liabilities for short-term leases and instead record them in a manner similar to operating leases under legacy lease accounting guidelines. A short term lease is one with a maximum lease term of 12 months or less and does not include a purchase option the lessee is reasonably certain to exercise. • We did not reassess whether any expired or existing contracts as of January 1, 2019 contained leases or the lease classification for any such existing or expired leases. • The impact of adopting ASC 842 was prospective beginning January 1, 2019. We did not recast prior periods presented in our consolidated financial statements to reflect the new lease accounting guidance. • We combine lease and nonlease components relating to our office and warehouse leases, as applicable. See Note 17 for our disclosures regarding operating lease obligations.
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 over the remaining portion of the fiscal year in which the maintenance occurred. 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 4 for additional information regarding our property, plant and equipment and AROs.
Revenue [Policy Text Block]	Revenues For periods prior to January 1, 2018, we accounted for our revenue streams using ASC 605, Revenue Recognition We adopted ASC 606, Revenue from Contracts with Customers, on January 1, 2018 using a modified retrospective approach that applied the new revenue recognition standard to existing contracts at the implementation date and any future revenue contracts. As such, our consolidated revenues and related financial information for periods prior to January 1, 2018 were not adjusted and continue to be reported in accordance with ASC 605. We did not record a cumulative effect adjustment upon initially applying ASC 606 since there was no impact on partners’ equity upon adoption; however, the extent of our revenue-related disclosures has increased under the new standard. The core principle of ASC 606 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. We apply this core principle by following five key steps outlined in ASC 606: (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 judgment and an analysis of the contract’s material terms and conditions. Substantially all of our revenues are accounted for under ASC 606; however, to a limited extent, some revenues are accounted for under other guidance such as ASC 842, Leases, Nonmonetary Transactions, Derivatives and Hedging Activities Under ASC 606, we recognize revenue when or as we satisfy our performance obligation to the customer. In situations where we have recognized revenue, but have a conditional right to consideration (based on something other than the passage of time) from the customer, we recognize unbilled revenue (a contract asset) on our consolidated balance sheet. Unbilled revenue is reclassified to accounts receivable when we have an unconditional right of payment from the customer. Payments received from customers in advance of the period in which we satisfy a performance obligation are recorded as deferred revenue (a contract liability) on our consolidated balance sheet. Our revenue streams are derived from the sale of products and providing midstream services. Revenues from the sale of products are recognized at a point in time, which represents the transfer of control (and the satisfaction of our performance obligation under the contract) to the customer. From that point forward, the customer is able to direct the use of, and obtain substantially all the benefits from, its use of the products. With respect to midstream services (e.g., interruptible transportation), we satisfy our performance obligations over time and recognize revenues when the services are provided and the customer receives the benefits based on an output measure of volumes redelivered. We believe this measure is a faithful depiction of the transfer of control for midstream services since there is (i) an insignificant period of time between the receipt of customers’ volumes and their subsequent redelivery, and (ii) it is not possible to individually track and differentiate customers’ inventories as they traverse our facilities. For stand-ready performance obligations (e.g., a storage capacity reservation contract), we recognize revenues over time on a straight-line basis as time elapses over the term of the contract. We believe that these approaches accurately depict the transfer of benefits to the customer. Customers are invoiced for products purchased or services rendered when we have an unconditional right to consideration under the associated contract. The consideration we are entitled to invoice may be either fixed, variable or a combination of both. Examples of fixed consideration would be fixed payments from customers under take-or-pay arrangements, storage capacity reservation agreements and firm transportation contracts. Variable consideration represents payments from customers that are based on factors that fluctuate (or vary) based on volumes, prices or both. Examples of variable consideration include interruptible transportation agreements, market-indexed product sales contracts and the value of NGLs we retain under natural gas processing agreements. The terms of our billings are typical of the industry for the products we sell. Under certain midstream service agreements, customers are required to provide a minimum volume over an agreed-upon period with a provision that allows the customer to make-up any volume shortfalls over an agreed-upon period (referred to as “make-up rights”). Revenue pursuant to such agreements is initially deferred and subsequently recognized when either the make-up rights are exercised, the likelihood of the customer exercising the rights becomes remote, or we are otherwise released from the performance obligation. Customers may contribute funds to us to help offset the construction costs related to pipeline construction activities and production well tie-ins. Under ASC 605, these amounts were accounted for as contributions in aid of construction costs (“CIACs”) and netted against property, plant and equipment. Under ASC 606, these receipts are recognized as additional service revenues over the term of the associated midstream services provided to the customer. For those contracts under which we have the ability to invoice the customer in an amount that corresponds directly with the value of the performance obligation completed to date, we recognize revenue as we have the right to invoice. See Note 9 regarding our revenue disclosures.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2019
Summary of Significant Accounting Policies [Abstract]
Allowance for Doubtful Accounts Activity	The following table presents our allowance for doubtful accounts activity for the years indicated: For the Year Ended December 31, 2019 2018 2017 Balance at beginning of period $ 11.5 $ 12.1 $ 11.3 Charged to costs and expenses 1.2 0.7 2.7 Deductions (0.3 ) (1.3 ) (1.9 ) Balance at end of period $ 12.4 $ 11.5 $ 12.1
Cash, Cash Equivalents and Restricted Cash	December 31, 2019 2018 Cash and cash equivalents $ 334.7 $ 344.8 Restricted cash 75.3 65.3 Total cash, cash equivalents and restricted cash shown in the Statements of Consolidated Cash Flows $ 410.0 $ 410.1
Environmental Reserves Activity	The following table presents the activity of our environmental reserves for the years indicated: For the Year Ended December 31, 2019 2018 2017 Balance at beginning of period $ 6.9 $ 11.6 $ 11.9 Charged to costs and expenses 12.3 8.2 12.1 Acquisition-related additions and other 2.5 1.7 1.7 Deductions (14.5 ) (14.6 ) (14.1 ) Balance at end of period $ 7.2 $ 6.9 $ 11.6

Inventories (Tables)

Inventories (Tables)	12 Months Ended
	Dec. 31, 2019
Inventories [Abstract]
Inventory Amounts by Product Type	Our inventory amounts by product type were as follows at the dates indicated: December 31, 2019 2018 NGLs $ 1,094.9 $ 647.7 Petrochemicals and refined products 311.5 264.7 Crude oil 674.2 593.4 Natural gas 10.8 16.3 Total $ 2,091.4 $ 1,522.1
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 years indicated: For the Year Ended December 31, 2019 2018 2017 Cost of sales (1) $ 22,065.8 $ 26,789.8 $ 21,487.0 Lower of cost or net realizable value adjustments recognized in cost of sales 22.7 11.5 9.1 (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, 2019
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 2019 2018 Plants, pipelines and facilities (1) 3-45 (5) $ 47,201.2 $ 42,371.0 Underground and other storage facilities (2) 5-40 (6) 3,965.5 3,624.2 Transportation equipment (3) 3-10 198.9 187.1 Marine vessels (4) 15-30 905.9 828.6 Land 372.3 359.5 Construction in progress 2,641.2 3,526.8 Total 55,285.0 50,897.2 Less accumulated depreciation 13,681.6 12,159.6 Property, plant and equipment, net $ 41,603.4 $ 38,737.6 (1) Plants, pipelines and facilities include processing plants; NGL, natural gas, crude oil and petrochemical and refined products pipelines; terminal loading and unloading facilities; buildings; office furniture and equipment; laboratory and shop equipment and related assets. (2) Underground and other storage facilities include underground product storage caverns; above ground storage tanks; water wells and related assets. (3) 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 years indicated: For the Year Ended December 31, 2019 2018 2017 Depreciation expense (1) $ 1,562.6 $ 1,436.2 $ 1,296.1 Capitalized interest (2) 143.8 147.9 192.1 (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 years indicated: For the Year Ended December 31, 2019 2018 2017 ARO liability beginning balance $ 126.3 $ 86.7 $ 85.4 Liabilities incurred 5.0 24.4 4.7 Liabilities settled (2.3 ) (2.5 ) (2.2 ) Revisions in estimated cash flows (4.8 ) 11.5 (6.7 ) Accretion expense 7.9 6.2 5.5 ARO liability ending balance $ 132.1 $ 126.3 $ 86.7
Forecasted Accretion Expense Associated with AROs	The following table presents our forecast of ARO-related accretion expense for the years indicated: 2020 2021 2022 2023 2024 $ 8.2 $ 8.6 $ 9.1 $ 9.6 $ 10.3

Investments in Unconsolidated_2

Investments in Unconsolidated Affiliates (Tables)	12 Months Ended
	Dec. 31, 2019
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, December 31, 2019 2019 2018 NGL Pipelines & Services: Venice Energy Service Company, L.L.C. (“VESCO”) 13.1% $ 23.2 $ 24.1 K/D/S Promix, L.L.C. (“Promix”) 50% 25.7 28.9 Baton Rouge Fractionators LLC (“BRF”) 32.2% 15.6 16.3 Skelly-Belvieu Pipeline Company, L.L.C. (“Skelly-Belvieu”) 50% 33.1 35.6 Texas Express Pipeline LLC (“Texas Express”) 35% 358.1 337.6 Texas Express Gathering LLC (“TEG”) 45% 41.1 43.6 Front Range Pipeline LLC (“Front Range”) 33.3% 207.0 175.9 Crude Oil Pipelines & Services: Seaway Crude Holdings LLC (“Seaway”) 50% 1,353.1 1,369.7 Eagle Ford Pipeline LLC (“Eagle Ford Crude Oil Pipeline”) 50% 386.5 388.7 Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Corpus Christi”) 50% 126.9 109.1 Natural Gas Pipelines & Services: White River Hub, LLC (“White River Hub”) 50% 19.1 20.1 Old Ocean Pipeline, LLC (“Old Ocean”) 50% 8.2 2.7 Petrochemical & Refined Products Services: Centennial Pipeline LLC (“Centennial”) (1) 50% – 59.1 Baton Rouge Propylene Concentrator LLC (“BRPC”) 30% 2.0 3.2 Transport 4, LLC (“Transport 4”) 25% 0.6 0.5 Total $ 2,600.2 $ 2,615.1 (1) The investment in Centennial was written off in December 2019. The following table presents our equity in income (loss) of unconsolidated affiliates by business segment for the years indicated: For the Year Ended December 31, 2019 2018 2017 NGL Pipelines & Services $ 114.5 $ 117.0 $ 73.4 Crude Oil Pipelines & Services 449.2 365.4 358.4 Natural Gas Pipelines & Services 6.3 6.8 3.8 Petrochemical & Refined Products Services (1) (7.0 ) (9.2 ) (9.6 ) Total $ 563.0 $ 480.0 $ 426.0 (1) The losses recorded for this segment are primarily due to protection, maintenance and pipeline integrity costs of the idled Centennial Pipeline, which was purged and filled with nitrogen in 2013. Although we wrote off our investment in Centennial in 2019, we, as a 50% owner of Centennial, have a continuing obligation to fund the pipeline’s costs in its idled state. December 31, 2019 2018 NGL Pipelines & Services $ 20.5 $ 21.7 Crude Oil Pipelines & Services 16.6 17.4 Petrochemical & Refined Products Services – 1.7 Total $ 37.1 $ 40.8 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, 2019 2018 Balance Sheet Data: Current assets $ 358.1 $ 350.2 Property, plant and equipment, net 5,379.7 5,359.1 Other assets 68.7 80.4 Total assets $ 5,806.5 $ 5,789.7 Current liabilities $ 230.9 $ 220.6 Other liabilities 69.6 77.9 Combined equity 5,506.0 5,491.2 Total liabilities and combined equity $ 5,806.5 $ 5,789.7 For the Year Ended December 31, 2019 2018 2017 Income Statement Data: Revenues $ 1,950.2 $ 1,721.3 $ 1,509.0 Operating income 1,250.4 1,074.6 925.9 Net income 1,251.8 1,069.1 929.5

Intangible Assets and Goodwill

Intangible Assets and Goodwill (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 December 31, 2018 Gross Value Accumulated Amortization Carrying Value Gross Value Accumulated Amortization Carrying Value NGL Pipelines & Services: Customer relationship intangibles $ 447.8 $ (206.3 ) $ 241.5 $ 457.3 $ (201.9 ) $ 255.4 Contract-based intangibles 162.6 (43.9 ) 118.7 363.4 (238.7 ) 124.7 Segment total 610.4 (250.2 ) 360.2 820.7 (440.6 ) 380.1 Crude Oil Pipelines & Services: Customer relationship intangibles 2,203.5 (243.5 ) 1,960.0 2,203.5 (174.1 ) 2,029.4 Contract-based intangibles 276.9 (235.0 ) 41.9 276.9 (211.7 ) 65.2 Segment total 2,480.4 (478.5 ) 2,001.9 2,480.4 (385.8 ) 2,094.6 Natural Gas Pipelines & Services: Customer relationship intangibles 1,350.3 (481.6 ) 868.7 1,350.3 (447.8 ) 902.5 Contract-based intangibles 468.0 (395.5 ) 72.5 464.7 (387.9 ) 76.8 Segment total 1,818.3 (877.1 ) 941.2 1,815.0 (835.7 ) 979.3 Petrochemical & Refined Products Services: Customer relationship intangibles 181.4 (57.5 ) 123.9 181.4 (51.8 ) 129.6 Contract-based intangibles 46.0 (24.2 ) 21.8 46.0 (21.2 ) 24.8 Segment total 227.4 (81.7 ) 145.7 227.4 (73.0 ) 154.4 Total intangible assets $ 5,136.5 $ (1,687.5 ) $ 3,449.0 $ 5,343.5 $ (1,735.1 ) $ 3,608.4
Amortization Expense of Intangible Assets by Segment	The following table presents the amortization expense of our intangible assets by business segment for the years indicated: For the Year Ended December 31, 2019 2018 2017 NGL Pipelines & Services $ 31.9 $ 34.7 $ 28.9 Crude Oil Pipelines & Services 92.7 87.8 92.5 Natural Gas Pipelines & Services 41.4 39.1 36.2 Petrochemical & Refined Products Services 8.7 8.7 9.3 Total $ 174.7 $ 170.3 $ 166.9
Forecasted Amortization Expense	The following table presents our forecast of amortization expense associated with existing intangible assets for the years indicated: 2020 2021 2022 2023 2024 $ 164.8 $ 167.0 $ 164.0 $ 162.4 $ 158.9
Significant Acquired Intangible Assets	At December 31, 2019, the carrying value of our portfolio of customer relationship intangible assets was $3.2 billion, the principal components of which were as follows: a Weighted Average Remaining Amortization Period December 31, 2019 Gross Value Accumulated Amortization Carrying Value Basin-specific customer relationships: EFS Midstream (acquired 2015) 22.4 years $ 1,409.8 $ (160.1) $ 1,249.7 State Line and Fairplay (acquired 2010) 27.2 years 895.0 (205.1) 689.9 San Juan Gathering (acquired 2004) 19.8 years 331.3 (236.8) 94.5 General customer relationships: Oiltanking (acquired 2014) 24.0 years 1,192.5 (122.2) 1,070.3 a Weighted Average Remaining Amortization Period December 31, 2019 Gross Value Accumulated Amortization Carrying Value Oiltanking customer contracts 3.6 years $ 293.3 $ (245.9) $ 47.4 Jonah natural gas gathering agreements 22.0 years 224.4 (171.4) 53.0 Delaware Basin natural gas processing contracts 7.0 years 82.6 (15.0) 67.6

Debt Obligations (Tables)

Debt Obligations (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 2018 EPO senior debt obligations: Commercial Paper Notes, variable-rates $ 482.0 $ – Senior Notes N, 6.50% fixed-rate, due January 2019 – 700.0 Senior Notes LL, 2.55% fixed-rate, due October 2019 – 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 1,000.0 364-Day Revolving Credit Agreement, variable-rate, due September 2020 – – Senior Notes TT, 2.80% fixed-rate, due February 2021 750.0 750.0 Senior Notes RR, 2.85% fixed-rate, due April 2021 575.0 575.0 Senior Notes VV, 3.50% fixed-rate, due February 2022 750.0 750.0 Senior Notes CC, 4.05% fixed-rate, due February 2022 650.0 650.0 Senior Notes HH, 3.35% fixed-rate, due March 2023 1,250.0 1,250.0 Senior Notes JJ, 3.90% fixed-rate, due February 2024 850.0 850.0 Multi-Year Revolving Credit Agreement, variable-rate, due September 2024 – – 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 WW, 4.15% fixed-rate, due October 2028 1,000.0 1,000.0 Senior Notes YY, 3.125% fixed-rate, due July 2029 1,250.0 – 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 UU, 4.25% fixed-rate, due February 2048 1,250.0 1,250.0 Senior Notes XX, 4.80% fixed-rate, due February 2049 1,250.0 1,250.0 Senior Notes ZZ, 4.20% fixed-rate, due January 2050 1,250.0 – Senior Notes NN, 4.95% fixed-rate, due October 2054 400.0 400.0 TEPPCO senior debt obligations: TEPPCO Senior Notes, 7.55% fixed-rate, due April 2038 0.4 0.4 Total principal amount of senior debt obligations 25,232.0 23,750.0 EPO Junior Subordinated Notes C, variable-rate, due June 2067 232.2 256.4 EPO Junior Subordinated Notes D, fixed/variable-rate, due August 2077 700.0 700.0 EPO Junior Subordinated Notes E, fixed/variable-rate, due August 2077 1,000.0 1,000.0 EPO Junior Subordinated Notes F, fixed/variable-rate, due February 2078 700.0 700.0 TEPPCO Junior Subordinated Notes, variable-rate, due June 2067 14.2 14.2 Total principal amount of senior and junior debt obligations 27,878.4 26,420.6 Other, non-principal amounts (253.3 ) (242.4 ) Less current maturities of debt (1,981.9 ) (1,500.1 ) Total long-term debt $ 25,643.2 $ 24,678.1 (1) Variable rate is reset quarterly and based on 3-month London Interbank Offered Rate ("LIBOR") plus 2.778%. (2) Fixed rate of 4.875% through August 15, 2022; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 2.986%. (3) Fixed rate of 5.250% through August 15, 2027; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 3.033%. (4) Fixed rate of 5.375% through February 14, 2028; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 2.57%. 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, 2019: Range of Interest Rates Paid Weighted-Average Interest Rate Paid Commercial Paper Notes 1.79% to 2.80% 2.61% EPO Junior Subordinated Notes C and TEPPCO Junior Subordinated Notes 4.68% to 5.52% 5.22%
Consolidated Debt Maturities	The following table presents the scheduled contractual maturities of principal amounts of our consolidated debt obligations at December 31, 2019 for the next five years, and in total thereafter: Scheduled Maturities of Debt Total 2020 2021 2022 2023 2024 Thereafter Commercial Paper Notes $ 482.0 $ 482.0 $ – $ – $ – $ – $ – Senior Notes 24,750.0 1,500.0 1,325.0 1,400.0 1,250.0 850.0 18,425.0 Junior Subordinated Notes 2,646.4 – – – – – 2,646.4 Total $ 27,878.4 $ 1,982.0 $ 1,325.0 $ 1,400.0 $ 1,250.0 $ 850.0 $ 21,071.4

Equity and Distributions (Table

Equity and Distributions (Tables)	12 Months Ended
	Dec. 31, 2019
Equity and Distributions [Abstract]
Summary of Changes in Outstanding Units	Partners’ equity reflects the classes of our limited partner interests outstanding. 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 Common Units (Unrestricted) Restricted Common Units Total Common Units Number of units issued and 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 issued and outstanding at December 31, 2017 2,161,089,479 – 2,161,089,479 Common unit repurchases under Legacy Buyback Program (1,236,800 ) – (1,236,800 ) Common units issued in connection with DRIP and EUPP 19,861,951 – 19,861,951 Common units issued in connection with the vesting of phantom unit awards 3,479,958 – 3,479,958 Cancellation of treasury units acquired in connection with the vesting of equity-based awards (1,037,522 ) – (1,037,522 ) Common units issued in connection with employee compensation 1,443,586 – 1,443,586 Common units issued in connection with land acquisition 1,223,242 – 1,223,242 Other 45,135 – 45,135 Number of units issued and outstanding at December 31, 2018 2,184,869,029 – 2,184,869,029 Common unit repurchases under 2019 Buyback Program (2,909,128 ) – (2,909,128 ) Common units issued in connection with DRIP and EUPP 2,897,990 – 2,897,990 Common units issued in connection with the vesting of phantom unit awards 3,895,049 – 3,895,049 Cancellation of treasury units acquired in connection with the vesting of equity-based awards (1,174,446 ) – (1,174,446 ) Common units issued in connection with employee compensation 1,626,041 – 1,626,041 Other 21,595 – 21,595 Number of units issued and outstanding at December 31, 2019 2,189,226,130 – 2,189,226,130
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: Cash Flow Hedges Commodity Derivative Instruments Interest Rate Derivative Instruments Other Total Accumulated Other Comprehensive Income (Loss), December 31, 2017 $ (10.1 ) $ (165.1 ) $ 3.5 $ (171.7 ) Other comprehensive income (loss) for period, before reclassifications 293.2 22.2 (0.5 ) 314.9 Reclassification of losses (gains) to net income during period (130.4 ) 38.1 – (92.3 ) Total other comprehensive income (loss) for period 162.8 60.3 (0.5 ) 222.6 Accumulated Other Comprehensive Income (Loss), December 31, 2018 152.7 (104.8 ) 3.0 50.9 Other comprehensive income (loss) for period, before reclassifications 44.1 81.4 (0.6 ) 124.9 Reclassification of losses (gains) to net income during period (141.7 ) 37.3 – (104.4 ) Total other comprehensive income (loss) for period (97.6 ) 118.7 (0.6 ) 20.5 Accumulated Other Comprehensive Income (Loss), December 31, 2019 $ 55.1 $ 13.9 $ 2.4 $ 71.4
Reclassifications out of Accumulated Other Comprehensive Income (Loss) Into Net Income	The following table presents reclassifications of (income) loss out of accumulated other comprehensive income (loss) into net income during the years indicated: For the Year Ended December 31, Losses (gains) on cash flow hedges: Location 2019 2018 Interest rate derivatives Interest expense $ 37.3 $ 38.1 Commodity derivatives Revenue (152.4 ) (131.7 ) Commodity derivatives Operating costs and expenses 10.7 1.3 Total $ (104.4 ) $ (92.3 )
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 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 2018: 1st Quarter $ 0.4275 4/30/2018 5/8/2018 2nd Quarter $ 0.4300 7/31/2018 8/8/2018 3rd Quarter $ 0.4325 10/31/2018 11/8/2018 4th Quarter $ 0.4350 1/31/2019 2/8/2019 2019: 1st Quarter $ 0.4375 4/30/2019 5/13/2019 2nd Quarter $ 0.4400 7/31/2019 8/13/2019 3rd Quarter $ 0.4425 10/31/2019 11/12/2019 4th Quarter $ 0.4450 1/31/2020 2/12/2020

Revenues (Tables)

Revenues (Tables)	12 Months Ended
	Dec. 31, 2019
Revenues [Abstract]
Revenues by Business Segment and Revenue Type	We classify our revenues into sales of products and midstream services. Product sales relate primarily to our various marketing activities whereas midstream services represent our other integrated businesses (i.e., gathering, processing, transportation, fractionation, storage and terminaling). The following table presents our revenues by business segment, and further by revenue type, for the years indicated: For the Year Ended December 31, 2019 2018 2017 NGL Pipelines & Services: Sales of NGLs and related products $ 10,934.3 $ 12,920.9 $ 10,521.3 Segment midstream services: Natural gas processing and fractionation 1,069.9 1,341.0 719.1 Transportation 1,054.3 1,007.0 891.7 Storage and terminals 412.2 380.0 335.9 Total segment midstream services 2,536.4 2,728.0 1,946.7 Total NGL Pipelines & Services 13,470.7 15,648.9 12,468.0 Crude Oil Pipelines & Services: Sales of crude oil 9,007.8 10,001.2 7,365.2 Segment midstream services: Transportation 801.8 676.5 473.9 Storage and terminals 477.7 364.9 317.7 Total segment midstream services 1,279.5 1,041.4 791.6 Total Crude Oil Pipelines & Services 10,287.3 11,042.6 8,156.8 Natural Gas Pipelines & Services: Sales of natural gas 2,075.4 2,411.7 2,238.5 Segment midstream services: Transportation 1,094.0 1,042.7 907.1 Total segment midstream services 1,094.0 1,042.7 907.1 Total Natural Gas Pipelines & Services 3,169.4 3,454.4 3,145.6 Petrochemical & Refined Products Services: Sales of petrochemicals and refined products 4,985.2 5,535.4 4,696.3 Segment midstream services: Fractionation and isomerization 166.6 188.3 156.3 Transportation, including marine logistics 539.4 481.8 430.7 Storage and terminals 170.6 182.8 187.8 Total segment midstream services 876.6 852.9 774.8 Total Petrochemical & Refined Products Services 5,861.8 6,388.3 5,471.1 Total consolidated revenues $ 32,789.2 $ 36,534.2 $ 29,241.5 (1) Revenues are accounted for under ASC 606. (2) Revenues are accounted for under ASC 605.
Unbilled Revenue and Deferred Revenue	The following table provides information regarding our contract assets and contract liabilities at the dates indicated: December 31, Contract Asset Location 2019 2018 Unbilled revenue (current amount) Prepaid and other current assets $ 17.6 $ 13.3 Total $ 17.6 $ 13.3 December 31, Contract Liability Location 2019 2018 Deferred revenue (current amount) Other current liabilities $ 117.9 $ 80.9 Deferred revenue (noncurrent) Other long-term liabilities 197.0 210.3 Total $ 314.9 $ 291.2 The following table presents significant changes in our unbilled revenue and deferred revenue balances during the years indicated: Unbilled Revenue Deferred Revenue Balance at January 1, 2018 (upon adoption of ASC 606) $ – $ 224.7 Amount included in opening balance transferred to other accounts during period (1) – (90.8 ) Amount recorded during period 321.7 432.5 Amounts recorded during period transferred to other accounts (1) (310.6 ) (274.8 ) Amount recorded in connection with business combination 2.2 – Other changes – (0.4 ) Balance at December 31, 2018 $ 13.3 $ 291.2 Amount included in opening balance transferred to other accounts during period (1) (13.3 ) (126.4 ) Amount recorded during period 340.0 539.8 Amounts recorded during period transferred to other accounts (1) (322.4 ) (384.8 ) Amount recorded in connection with business combination – – Other changes – (4.9 ) Balance at December 31, 2019 $ 17.6 $ 314.9 (1) Unbilled revenues are transferred to accounts receivable once we have an unconditional right to consideration from the customer. Deferred revenues are recognized as revenue upon satisfaction of our performance obligation to the customer.
Remaining Performance Obligations	Period Fixed Consideration One Year Ended December 31, 2020 $ 3,654.6 One Year Ended December 31, 2021 3,363.9 One Year Ended December 31, 2022 3,062.7 One Year Ended December 31, 2023 2,857.8 One Year Ended December 31, 2024 2,743.8 Thereafte r 14,106.7 Total $ 29,789.5

Business Segments (Tables)

Business Segments (Tables)	12 Months Ended
	Dec. 31, 2019
Business Segments [Abstract]
Measurement of Total Segment Gross Operating Margin	The following table presents our measurement of total segment gross operating margin for the years indicated. The GAAP financial measure most directly comparable to total segment gross operating margin is operating income. For the Year Ended December 31, 2019 2018 2017 Operating income $ 6,078.7 $ 5,408.6 $ 3,928.9 Adjustments to reconcile operating income to total gross operating margin (addition or subtraction indicated by sign): Depreciation, amortization and accretion expense in operating costs and expenses 1,848.3 1,687.0 1,531.3 Asset impairment and related charges in operating costs and expenses 132.7 50.5 49.8 Net gains attributable to asset sales in operating costs and expenses (5.7 ) (28.7 ) (10.7 ) General and administrative costs 211.7 208.3 181.1 Non-refundable payments received from shippers attributable to make-up rights (1) 47.0 21.5 24.1 Subsequent recognition of revenues attributable to make-up rights (2) (22.9 ) (56.2 ) (29.9 ) Total segment gross operating margin $ 8,289.8 $ 7,291.0 $ 5,674.6 (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 years indicated: For the Year Ended December 31, 2019 2018 2017 Gross operating margin by segment: NGL Pipelines & Services $ 4,069.8 $ 3,830.7 $ 3,258.3 Crude Oil Pipelines & Services 2,087.8 1,511.3 987.2 Natural Gas Pipelines & Services 1,062.6 891.2 714.5 Petrochemical & Refined Products Services 1,069.6 1,057.8 714.6 Total segment gross operating margin $ 8,289.8 $ 7,291.0 $ 5,674.6 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 Adjustments and Eliminations Consolidated Total Revenues from third parties: Year ended December 31, 2019 $ 13,460.8 $ 10,244.6 $ 3,154.7 $ 5,861.8 $ – $ 32,721.9 Year ended December 31, 2018 15,630.5 10,968.2 3,439.5 6,388.3 – 36,426.5 Year ended December 31, 2017 12,455.7 8,137.2 3,132.5 5,471.1 – 29,196.5 Revenues from related parties: Year ended December 31, 2019 9.9 42.7 14.7 – – 67.3 Year ended December 31, 2018 18.4 74.4 14.9 – – 107.7 Year ended December 31, 2017 12.3 19.6 13.1 – – 45.0 Intersegment and intrasegment revenues: Year ended December 31, 2019 20,840.4 34,613.0 624.7 2,481.3 (58,559.4 ) – Year ended December 31, 2018 26,453.6 35,490.4 721.9 2,917.5 (65,583.4 ) – Year ended December 31, 2017 27,278.6 15,943.0 850.8 1,766.9 (45,839.3 ) – Total revenues: Year ended December 31, 2019 34,311.1 44,900.3 3,794.1 8,343.1 (58,559.4 ) 32,789.2 Year ended December 31, 2018 42,102.5 46,533.0 4,176.3 9,305.8 (65,583.4 ) 36,534.2 Year ended December 31, 2017 39,746.6 24,099.8 3,996.4 7,238.0 (45,839.3 ) 29,241.5 Equity in income (loss) of unconsolidated affiliates: Year ended December 31, 2019 114.5 449.2 6.3 (7.0 ) – 563.0 Year ended December 31, 2018 117.0 365.4 6.8 (9.2 ) – 480.0 Year ended December 31, 2017 73.4 358.4 3.8 (9.6 ) – 426.0 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 Adjustments and Eliminations Consolidated Total Property, plant and equipment, net: At December 31, 2019 $ 16,652.1 $ 6,324.4 $ 8,432.5 $ 7,553.2 $ 2,641.2 $ 41,603.4 At December 31, 2018 14,845.4 5,847.7 8,303.8 6,213.9 3,526.8 38,737.6 At December 31, 2017 13,831.2 5,208.4 8,375.0 3,507.7 4,698.1 35,620.4 Investments in unconsolidated affiliates: At December 31, 2019 703.8 1,866.5 27.3 2.6 – 2,600.2 At December 31, 2018 662.0 1,867.5 22.8 62.8 – 2,615.1 At December 31, 2017 733.9 1,839.2 20.8 65.5 – 2,659.4 Intangible assets, net: At December 31, 2019 360.2 2,001.9 941.2 145.7 – 3,449.0 At December 31, 2018 380.1 2,094.6 979.3 154.4 – 3,608.4 At December 31, 2017 322.3 2,186.5 1,018.4 163.1 – 3,690.3 Goodwill: At December 31, 2019 2,651.7 1,841.0 296.3 956.2 – 5,745.2 At December 31, 2018 2,651.7 1,841.0 296.3 956.2 – 5,745.2 At December 31, 2017 2,651.7 1,841.0 296.3 956.2 – 5,745.2 Segment assets: At December 31, 2019 20,367.8 12,033.8 9,697.3 8,657.7 2,641.2 53,397.8 At December 31, 2018 18,539.2 11,650.8 9,602.2 7,387.3 3,526.8 50,706.3 At December 31, 2017 17,539.1 11,075.1 9,710.5 4,692.5 4,698.1 47,715.3
Consolidated Revenues and Expenses	The following table presents additional information regarding our consolidated revenues and costs and expenses for the years indicated: For the Year Ended December 31, 2019 2018 2017 Consolidated revenues: NGL Pipelines & Services $ 13,470.7 $ 15,648.9 $ 12,468.0 Crude Oil Pipelines & Services 10,287.3 11,042.6 8,156.8 Natural Gas Pipelines & Services 3,169.4 3,454.4 3,145.6 Petrochemical & Refined Products Services 5,861.8 6,388.3 5,471.1 Total consolidated revenues $ 32,789.2 $ 36,534.2 $ 29,241.5 Consolidated costs and expenses: Operating costs and expenses: Cost of sales $ 22,065.8 $ 26,789.8 $ 21,487.0 Other operating costs and expenses (1) 3,020.7 2,898.7 2,500.1 Depreciation, amortization and accretion 1,848.3 1,687.0 1,531.3 Asset impairment and related charges 132.7 50.5 49.8 Ne t g (5.7 ) (28.7 ) (10.7 ) General and administrative costs 211.7 208.3 181.1 Total consolidated costs and expenses $ 27,273.5 $ 31,605.6 $ 25,738.6 (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.

Earnings Per Unit (Tables)

Earnings Per Unit (Tables)	12 Months Ended
	Dec. 31, 2019
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 years indicated: For the Year Ended December 31, 2019 2018 2017 BASIC EARNINGS PER UNIT Net income attributable to limited partners $ 4,591.3 $ 4,172.4 $ 2,799.3 Earnings allocated to phantom unit awards (1) (27.7 ) (21.5 ) (15.9 ) Net income available to common unitholders $ 4,563.6 $ 4,150.9 $ 2,783.4 Basic weighted-average number of common units outstanding 2,188.6 2,176.5 2,145.0 Basic earnings per unit $ 2.09 $ 1.91 $ 1.30 DILUTED EARNINGS PER UNIT Net income attributable to limited partners $ 4,591.3 $ 4,172.4 $ 2,799.3 Diluted weighted-average number of units outstanding: Distribution-bearing common units 2,188.6 2,176.5 2,145.0 Phantom units (1) 13.1 10.5 9.3 Total 2,201.7 2,187.0 2,154.3 Diluted earnings per unit $ 2.09 $ 1.91 $ 1.30 (1) Phantom units are considered participating securities for purposes of computing basic earnings per unit. See Note 13 for information regarding our phantom units.

Business Combinations (Tables)

Business Combinations (Tables)	12 Months Ended
	Dec. 31, 2019
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 Delaware Processing acquisition. Purchase price for remaining 50% equity interest in Delaware Processing $ 154.5 Fair value of our 50% equity interest in Delaware Processing held before the acquisition 146.4 Total $ 300.9 Recognized amounts of identifiable assets acquired and liabilities assumed: Assets acquired in business combination: Current assets, including cash of $3.9 million $ 10.8 Property, plant and equipment 200.0 Contract-based intangible assets 82.6 Customer relationship intangible assets 9.9 Total assets acquired $ 303.3 Liabilities assumed in business combination: Current liabilities $ (1.8 ) Long-term liabilities (0.6 ) Total liabilities assumed $ (2.4 ) Total identifiable net assets $ 300.9 Goodwill $ – The following table presents the final fair value allocation of assets acquired and liabilities assumed in the Azure acquisition. 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 identifiable net assets $ 191.4

Equity-Based Awards (Tables)

Equity-Based Awards (Tables)	12 Months Ended
	Dec. 31, 2019
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 years indicated: For the Year Ended December 31, 2019 2018 2017 Equity-classified awards: Phantom unit awards $ 132.2 $ 99.7 $ 92.8 Profits interest awards 11.6 6.1 6.0 Restricted common unit awards – – 0.5 Liability-classified awards 0.1 0.3 0.4 Total $ 143.9 $ 106.1 $ 99.7
Other Share-based Compensation Plans	The following table presents phantom unit award activity for the years indicated: Number of Units Weighted- Average Grant Date Fair Value per Unit Phantom unit awards at December 31, 2016 7,767,501 $ 27.20 Granted (2) 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 Granted (3) 5,006,181 $ 26.82 Vested (3,479,958 ) $ 28.57 Forfeited (482,447 ) $ 26.88 Phantom unit awards at December 31, 2018 10,333,277 $ 26.97 Granted (4) 6,854,920 $ 27.75 Vested (3,895,049 ) $ 27.53 Forfeited (318,464 ) $ 27.21 Phantom unit awards at December 31, 2019 12,974,684 $ 27.21 (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 2017 was $123.1 million based on a grant date market price of EPD common units ranging from $24.55 to $28.87 per unit. An estimated annual forfeiture rate of 3.8% was applied to these awards. (3) The aggregate grant date fair value of phantom unit awards issued during 2018 was $134.3 million based on a grant date market price of EPD common units ranging from $25.40 to $29.22 per unit. An estimated annual forfeiture rate of 3.2% was applied to these awards. (4) The aggregate grant date fair value of phantom unit awards issued during 2019 was $190.2 million based on a grant date market price of EPD common units ranging from $26.32 to $29.29 per unit. An estimated annual forfeiture rate of 3.0% was applied to these awards. The following table summarizes key elements of each Employee Partnership as of December 31, 2019: Employee Partnership EPD 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 0.3900 February 2020 $12.9 million $0.8 million PubCo II 2,834,198 $66.3 million 0.3900 February 2021 $14.9 million $4.0 million PrivCo I 1,111,438 $26.0 million 0.3900 February 2021 $5.8 million $0.3 million EPD IV 6,400,000 $172.9 million 0.4325 December 2023 $26.7 million $18.4 million EPCO II 1,600,000 $43.2 million 0.4325 December 2023 $6.6 million $0.5 million (1) Represents the fair market value of EPD common units contributed to each Employee Partnership at the applicable contribution date. (2) Represents the total grant date fair value of the profits interest awards awarded to the Class B limited partners of each Employee Partnership irrespective of how such costs will be allocated between us and EPCO and its privately held affiliates. (3) Represents our expected share of the unrecognized compensation cost at December 31, 2019. We expect to recognize our share of the unrecognized compensation cost for PubCo II, PrivCo I, EPD IV and EPCO II over a weighted-average period of 1.1 years, 1.1 years, 3.9 years and 3.9 years, respectively. The Class B limited partner interests of PubCo I vested on February 22, 2020. 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 2.7% 5.9% to 7.0% 15% to 40% PubCo II 5.0 years 1.1% to 3.0% 5.9% to 7.0% 19% to 40% PrivCo I 5.0 years 1.2% to 1.6% 6.1% to 6.7% 28% to 40% EPD IV 5.0 years 2.8% 6.5% 27% EPCO II 5.0 years 1.6% to 2.8% 6.3% to 6.8% 24% to 27%
Supplemental Information Regarding Phantom Unit Awards	The following table presents supplemental information regarding phantom unit awards for the years indicated: For the Year Ended December 31, 2019 2018 2017 Cash payments made in connection with DERs $ 22.1 $ 17.7 $ 15.1 Total intrinsic value of phantom unit awards that vested during period $ 111.1 $ 90.7 $ 69.8

Derivative Instruments, Hedgi_2

Derivative Instruments, Hedging Activities and Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2019
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 30-year forward-starting swaps at December 31, 2019, all of which are associated with the expected future issuance of senior notes. Hedged Transaction Number and Type of Derivatives Outstanding Notional Amount Expected Settlement Date Weighted-Average Fixed Rate Locked Accounting Treatment Future long-term debt offering 1 forward-starting swap (1) $75.0 9/2020 2.39% Cash flow hedge Future long-term debt offering 1 forward-starting swap (1) $75.0 4/2021 2.41% Cash flow hedge Future long-term debt offering 5 forward-starting swaps (2) $500.0 9/2020 2.12% Cash flow hedge Future long-term debt offering 5 forward-starting swaps (2) $500.0 4/2021 2.13% Cash flow hedge (1) These swaps were entered into in May 2019. (2) These swaps were entered into in September 2019 as a result of the exercise of swaptions. The following table summarizes our portfolio of commodity derivative instruments outstanding at December 31, 2019 (volume measures as noted): Volume Accounting Derivative Purpose Current Long-Term Treatment Derivatives designated as hedging instruments: Natural gas processing: Forecasted natural gas purchases for plant thermal reduction (Bcf) 3.9 n/a Cash flow hedge Forecasted sales of NGLs 0.8 n/a Cash flow hedge Octane enhancement: Forecasted purchase of NGLs (MMBbls) 0.6 n/a Cash flow hedge Forecasted sales of octane enhancement products (MMBbls) 11.2 0.1 Cash flow hedge Natural gas marketing: Forecasted purchases of natural gas (Bcf) 1.1 n/a Cash flow hedge Natural gas storage inventory management activities (Bcf) 3.0 n/a Fair value hedge NGL marketing: Forecasted purchases of NGLs and related hydrocarbon products (MMBbls) 103.5 n/a Cash flow hedge Forecasted sales of NGLs and related hydrocarbon products (MMBbls) 128.1 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) 0.2 n/a Cash flow hedge Forecasted sales of refined products (MMBbls) 0.2 n/a Cash flow hedge Crude oil marketing: Forecasted purchases of crude oil (MMBbls) 15.3 n/a Cash flow hedge Forecasted sales of crude oil (MMBbls) 19.9 n/a Cash flow hedge Propylene marketing: Forecasted sales of NGLs for propylene marketing activities (MMBbls) 0.5 n/a Cash flow hedge Derivatives not designated as hedging instruments: Natural gas risk management activities (Bcf) (3) 52.3 0.2 Mark-to-market NGL risk management activities (MMBbls) (3) 6.5 n/a Mark-to-market Refined products risk management activities (MMBbls) (3) 9.4 n/a Mark-to-market Crude oil risk management activities (MMBbls) (3) 27.3 11.0 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 January 2021, April 2020 and December 2022, respectively. (3) 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, 2019 December 31, 2018 December 31, 2019 December 31, 2018 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 $ – Current liabilities $ 6.7 Current liabilities $ – Interest rate derivatives Other assets – Other assets – Other liabilities 6.8 Other liabilities – Total interest rate derivatives – – 13.5 – Commodity derivatives Current assets 116.5 Current assets 138.5 Current liabilities 107.1 Current liabilities 115.0 Commodity derivatives Other assets – Other assets 5.6 Other liabilities – Other liabilities 11.1 Total commodity derivatives 116.5 144.1 107.1 126.1 Total derivatives designated as hedging instruments $ 116.5 $ 144.1 $ 120.6 $ 126.1 Derivatives not designated as hedging instruments Commodity derivatives Current assets 10.7 Current assets 15.9 Current liabilities 8.6 Current liabilities 33.2 Commodity derivatives Other assets 0.6 Other assets 1.9 Other liabilities 0.5 Other liabilities 3.1 Total commodity derivatives 11.3 17.8 9.1 36.3 Total derivatives not designated as hedging instruments $ 11.3 $ 17.8 $ 9.1 $ 36.3
Offsetting Financial Assets	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, 2019: Commodity derivatives $ 127.8 $ – $ 127.8 $ (115.3 ) $ (11.0 ) $ – $ 1.5 As of December 31, 2018: Commodity derivatives $ 161.9 – $ 161.9 $ (158.6 ) $ – $ – $ 3.3
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, 2019: Interest rate derivatives $ 13.5 $ – $ 13.5 $ – $ – $ 13.5 Commodity derivatives 116.2 – 116.2 (115.3 ) – 0.9 As of December 31, 2018: Commodity derivatives $ 162.4 $ – $ 162.4 $ (158.6 ) $ (2.3 ) $ 1.5
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 years indicated: Derivatives in Fair Value Hedging Relationships Location Gain (Loss) Recognized in Income on Derivative For the Year Ended December 31, 2019 2018 2017 Interest rate derivatives Interest expense $ – $ 1.3 $ (0.2 ) Commodity derivatives Revenue 2.2 9.9 1.1 Total $ 2.2 $ 11.2 $ 0.9 Derivatives in Fair Value Hedging Relationships Location Gain (Loss) Recognized in Income on Hedged Item For the Year Ended December 31, 2019 2018 2017 Interest rate derivatives Interest expense $ – $ (1.4 ) $ 0.4 Commodity derivatives Revenue 6.9 (6.9 ) 27.4 Total $ 6.9 $ (8.3 ) $ 27.8
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 years indicated: Derivatives in Cash Flow Hedging Relationships Change in Value Recognized in Other Comprehensive Income (Loss) On Derivative For the Year Ended December 31, 2019 2018 2017 Interest rate derivatives $ 81.4 $ 22.2 $ (5.7 ) Commodity derivatives – Revenue (1) 55.8 293.0 (33.7 ) Commodity derivatives – Operating costs and expenses (1) (11.7 ) 0.2 (4.8 ) Total $ 125.5 $ 315.4 $ (44.2 ) (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	Derivatives in Cash Flow Hedging Relationships Location Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income For the Year Ended December 31, 2019 2018 2017 Interest rate derivatives Interest expense $ (37.3 ) $ (38.1 ) $ (40.4 ) Commodity derivatives Revenue 152.4 131.7 (111.6 ) Commodity derivatives Operating costs and expenses (10.7 ) (1.3 ) (0.6 ) Total $ 104.4 $ 92.3 $ (152.6 )
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 years indicated: Derivatives Not Designated as Hedging Instruments Location Gain (Loss) Recognized in Income on Derivative For the Year Ended December 31, 2019 2018 2017 Interest rate derivatives Interest expense $ (94.9 ) $ – $ – Commodity derivatives Revenue 102.2 (462.9 ) (42.7 ) Commodity derivatives Operating costs and expenses (12.4 ) 8.2 0.1 Total $ (5.1 ) $ (454.7 ) $ (42.6 )
Unrealized mark-to-market gains (losses)	In total and inclusive of both fair value hedges and derivatives not designated as hedging instruments, unrealized mark-to-market gains (losses) included in gross operating margin and interest expense for the years indicated: For the Year Ended December 31, 2019 2018 2017 Mark-to-market gains (losses) in gross operating margin: NGL Pipelines & Services $ (5.5 ) $ 18.0 $ (11.2 ) Crude Oil Pipelines & Services 80.6 (44.1 ) (4.8 ) Natural Gas Pipelines & Services (0.2 ) 6.7 (9.4 ) Petrochemical & Refined Products Services (7.2 ) 1.7 2.4 Total mark-to-market impact on gross operating margin 67.7 (17.7 ) (23.0 ) Mark-to-market gains (losses) in interest expense (94.9 ) (0.1 ) 0.2 Total $ (27.2 ) $ (17.8 ) $ (22.8 )
Fair Value Measurements of Financial Assets and Liabilities Measured on a Recurring Basis	At December 31, 2019 Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Financial assets: Commodity derivatives: Value before application of CME Rule 814 $ 53.4 $ 343.7 $ 0.1 $ 397.2 Impact of CME Rule 814 change (47.0 ) (222.4 ) – (269.4 ) Total commodity derivatives 6.4 121.3 0.1 127.8 Total $ 6.4 $ 121.3 $ 0.1 $ 127.8 Financial liabilities: Liquidity Option (see Note 17) $ – $ – $ 509.6 $ 509.6 Interest rate derivatives – 13.5 – 13.5 Commodity derivatives: Value before application of CME Rule 814 88.1 273.6 0.3 362.0 Impact of CME Rule 814 change (81.9 ) (163.9 ) – (245.8 ) Total commodity derivatives 6.2 109.7 0.3 116.2 Total $ 6.2 $ 123.2 $ 509.9 $ 639.3 At December 31, 2018 Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Financial assets: Commodity derivatives: Value before application of CME Rule 814 $ 172.3 $ 282.4 $ 2.2 $ 456.9 Impact of CME Rule 814 change (134.8 ) (159.3 ) (0.9 ) (295.0 ) Total commodity derivatives 37.5 123.1 1.3 161.9 Total $ 37.5 $ 123.1 $ 1.3 $ 161.9 Financial liabilities: Liquidity Option (see Note 17) $ – $ – $ 390.0 $ 390.0 Commodity derivatives: Value before application of CME Rule 814 85.5 291.2 21.4 398.1 Impact of CME Rule 814 change (48.6 ) (172.9 ) (14.2 ) (235.7 ) Total commodity derivatives 36.9 118.3 7.2 162.4 Total $ 36.9 $ 118.3 $ 397.2 $ 552.4
Fair Value Measurements, Valuation Techniques	The following Fair Value At December 31, 2019 Financial Assets Financial Liabilities Valuation Techniques Unobservable Input Range Commodity derivatives – Crude oil $ 0.1 $ 0.3 Discounted cash flow Forward commodity prices $61.05-$62.14/barrel Total $ 0.1 $ 0.3 Fair Value At December 31, 2018 Financial Assets Financial Liabilities Valuation Techniques Unobservable Input Range Commodity derivatives – Crude oil $ 0.9 $ 0.8 Discounted cash flow Forward commodity prices $37.59-$51.99/barrel Commodity derivatives – Ethane 0.4 0.6 Discounted cash flow Forward commodity prices $0.28-$0.31/gallon Commodity derivatives – Propane – 1.0 Discounted cash flow Forward commodity prices $0.61-$0.66/gallon Commodity derivatives – Normal butane – 0.7 Discounted cash flow Forward commodity prices $0.66-$0.72/gallon Commodity derivatives – Natural gasoline – 4.1 Discounted cash flow Forward commodity prices $0.99-$1.01/gallon Total $ 1.3 $ 7.2
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 years indicated: test For the Year Ended December 31, test Location 2019 2018 Financial asset (liability) balance, net, January 1 $ (395.9 ) $ (332.7 ) Total gains (losses) included in: Net income (1) Revenue 3.7 0.7 Net income Other expense, net – Liquidity Option (119.6 ) (56.1 ) Other comprehensive income (loss) Commodity derivative instruments – changes in fair value of cash flow hedges (2.1 ) (3.2 ) Settlements (1) Revenue (3.5 ) (1.9 ) Transfers out of Level 3 (2) 7.6 (2.7 ) Financial liability balance, net, December 31 $ (509.8 ) $ (395.9 ) (1) There were $0.2 million of unrealized gains and $1.2 million of unrealized losses included in these amounts for the years ended December 31, 2019 and 2018, 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, 2019 and 2018.
Nonrecurring Fair Value Measurements	The following table presents categories of long-lived assets that were subject to non-recurring fair value measurements during the year ended December 31, 2019: Fair Value Measurements at the End of the Reporting Period Using Carrying Value at December 31, 2019 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 $ – $ – $ – $ – $ 50.6 Long-lived assets held and used 0.3 – – 0.3 0.5 Total $ 51.1 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, 2018: Fair Value Measurements at the End of the Reporting Period Using Carrying Value at December 31, 2018 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 $ – $ – $ – $ – $ 43.7 Long-lived assets held and used – – – – 3.1 Total $ 46.8 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, 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

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2019
Related Party Transactions [Abstract]
Related Party Transactions	The following table summarizes our related party transactions for the years indicated: For the Year Ended December 31, 2019 2018 2017 Revenues – related parties: Unconsolidated affiliates $ 67.3 $ 107.7 $ 45.0 Costs and expenses – related parties: EPCO and its privately held affiliates $ 1,145.3 $ 1,089.6 $ 1,010.9 Unconsolidated affiliates 403.1 447.4 223.4 Total $ 1,548.4 $ 1,537.0 $ 1,234.3 The following table summarizes our related party accounts receivable and accounts payable balances at the dates indicated: December 31, 2019 2018 Accounts receivable - related parties: Unconsolidated affiliates $ 2.5 $ 3.5 Accounts payable - related parties: EPCO and its privately held affiliates $ 143.7 $ 116.3 Unconsolidated affiliates 18.6 23.9 Total $ 162.3 $ 140.2 At December 31, 2019 , 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 700,783,776 32% The following table presents our related party costs and expenses attributable to the ASA with EPCO for the years indicated: For the Year Ended December 31, 2019 2018 2017 Operating costs and expenses $ 1,000.2 $ 948.8 $ 882.1 General and administrative expenses 127.6 124.2 110.4 Total costs and expenses $ 1,127.8 $ 1,073.0 $ 992.5

Provision for Income Taxes (Tab

Provision for Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 2018 2017 Current portion of income tax provision (benefit): Federal $ (1.3 ) $ 5.3 $ 0.1 State 25.7 33.1 18.5 Foreign 1.2 0.5 1.0 Total current portion 25.6 38.9 19.6 Deferred portion of income tax provision (benefit): Federal 1.6 (0.3 ) (1.8 ) State 18.5 21.7 7.9 Foreign (0.1 ) – – Total deferred portion 20.0 21.4 6.1 Total provision for income taxes $ 45.6 $ 60.3 $ 25.7
Reconciliation of Provision for Income Taxes	A reconciliation of the provision for income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows: For the Year Ended December 31, 2019 2018 2017 Pre-Tax Net Book Income (“NBI”) $ 4,732.7 $ 4,298.8 $ 2,881.3 Texas Margin Tax (1) $ 44.2 $ 54.8 $ 26.4 State income taxes (net of federal benefit) 0.5 0.2 0.5 Federal income taxes computed by applying the federal statutory rate to NBI of corporate entities 0.9 2.1 0.1 Other permanent differences – 3.2 (1.3 ) Provision for income taxes $ 45.6 $ 60.3 $ 25.7 Effective income tax rate 1.0 % 1.4 % 0.9 % (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.
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, 2019 2018 Deferred tax liabilities: Attributable to property, plant and equipment $ 100.2 $ 80.8 Attributable to investments in partnerships 3.3 2.3 Total deferred tax liabilities 103.5 83.1 Less deferred tax assets: Net operating loss carryovers (1) 0.1 0.1 Temporary differences related to Texas Margin Tax 3.0 2.6 Total deferred tax assets 3.1 2.7 Total net deferred tax liabilities $ 100.4 $ 80.4 (1) These losses expire in various years between 2020 and 2037 and are subject to limitations on their utilization.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies [Abstract]
Summary of Contractual Obligations	The following table summarizes our various contractual obligations at December 31, 2019 . A description of each type of contractual obligation follows: Payment or Settlement due by Period Contractual Obligations Total 2020 2021 2022 2023 2024 Thereafter Scheduled maturities of debt obligations $ 27,878.4 $ 1,982.0 $ 1,325.0 $ 1,400.0 $ 1,250.0 $ 850.0 $ 21,071.4 Estimated cash interest payments $ 26,264.5 $ 1,224.7 $ 1,154.0 $ 1,101.2 $ 1,061.1 $ 1,023.0 $ 20,700.5 Operating lease obligations $ 271.2 $ 45.2 $ 40.1 $ 28.6 $ 20.2 $ 15.7 $ 121.4 Purchase obligations: Product purchase commitments: Estimated payment obligations: Natural gas $ 610.2 $ 345.4 $ 264.8 $ – $ – $ – $ – NGLs $ 5,534.7 $ 844.0 $ 911.1 $ 627.5 $ 548.1 $ 513.5 $ 2,090.5 Crude oil $ 14,025.5 $ 1,436.9 $ 1,677.2 $ 1,659.8 $ 1,532.1 $ 1,536.3 $ 6,183.2 Petrochemicals and refined products $ 384.0 $ 164.1 $ 77.2 $ 48.9 $ 48.9 $ 44.9 $ – Other $ 19.6 $ 7.6 $ 4.8 $ 2.8 $ 2.9 $ 1.5 $ – Service payment commitments $ 335.7 $ 66.6 $ 59.7 $ 57.7 $ 43.3 $ 14.5 $ 93.9 Capital expenditure commitments $ 45.8 $ 45.8 $ – $ – $ – $ – $ –
Operating Leases	The following table presents information regarding operating leases where we are the lessee at December 31, 2019 : Asset Category ROU Asset Carrying Value Lease Liability Carrying Value Weighted- Average Remaining Term Weighted- Average Discount Rate Storage and pipeline facilities $ 137.9 $ 138.6 16 years 4.3 % Transportation equipment 49.9 52.4 3 years 3.5 % Office and warehouse space 22.4 21.0 2 years 3.4 % Total $ 210.2 $ 212.0 (1) ROU asset amounts are a component of “Other assets” on our consolidated balance sheet. (2) At December 31, 2019, lease liabilities of $40.4 million and $171.6 million were included within “ Other current liabilities ” and “ Other liabilities ,” (3) The discount rate for each category of assets represents the weighted average of either (i) the implicit rate applicable to the underlying leases (where determinable) or (ii) our incremental borrowing rate adjusted for collateralization (if the implicit rate is not determinable). In general, the discount rates are based on either (i) information available at the lease commencement date or (ii) January 1, 2019 for leases existing at the adoption date for ASC 842.
Consolidated Lease Expense	The following table disaggregates our total operating lease expense for year ended December 31, 2019 : Long-term operating leases: Fixed lease expense: Non-cash lease expense (amortization of ROU assets) $ 42.8 Related accretion expense on lease liability balances 9.0 Total fixed lease expense 51.8 Variable lease expense 6.2 Subtotal operating lease expense 58.0 Short-term operating leases 48.6 Total operating lease expense $ 106.6
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, 2019 2018 Noncurrent portion of AROs (see Note 4) $ 126.9 $ 121.4 Deferred revenues – non-current portion (see Note 9) 197.0 210.3 Liquidity Option liability 509.6 390.0 Lease liability – non-current portion 171.6 – Derivative liabilities 7.3 14.2 Other 20.0 15.7 Total $ 1,032.4 $ 751.6

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2019
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 years indicated: For the Year Ended December 31, 2019 2018 2017 Decrease (increase) in: Accounts receivable – trade $ (1,248.8 ) $ 730.2 $ (1,076.2 ) Accounts receivable – related parties 0.9 (2.3 ) (0.7 ) Inventories (558.0 ) 121.4 194.6 Prepaid and other current assets (69.6 ) 214.4 226.0 Other assets (63.5 ) (9.7 ) (111.0 ) Increase (decrease) in: Accounts payable – trade (43.9 ) 18.3 66.6 Accounts payable – related parties 67.8 51.4 56.0 Accrued product payables 1,447.8 (1,132.0 ) 952.3 Accrued interest 36.1 37.6 17.3 Other current liabilities 58.1 (70.9 ) (291.4 ) Other liabilities (84.3 ) 57.8 (1.3 ) Net effect of changes in operating accounts $ (457.4 ) $ 16.2 $ 32.2 Cash payments for interest, net of $143.8, $147.9 and $192.1 capitalized in 2019, 2018 and 2017, respectively $ 1,080.3 $ 1,017.9 $ 912.1 Cash payments for federal and state income taxes $ 23.6 $ 15.5 $ 20.9
Schedule of Significant Acquisitions and Disposals	The following table presents our cash proceeds from asset sales for the years indicated: For the Year Ended December 31, 2019 2018 2017 Cash proceeds from sale of crude oil pipeline system (the “Red River System”) $ – $ 134.9 $ – Cash proceeds from other asset sales 20.6 26.3 40.1 Total $ 20.6 $ 161.2 $ 40.1 The following table presents net gains (losses) attributable to asset sales for the years indicated: For the Year Ended December 31, 2019 2018 2017 Gains attributable to sale of Red River System $ – $ 20.6 $ – Net gains attributable to other asset sales 5.7 8.1 10.7 Total $ 5.7 $ 28.7 $ 10.7

Quarterly Financial Informati_2

Quarterly Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019: Revenues $ 8,543.5 $ 8,276.3 $ 7,964.1 $ 8,005.3 Operating income 1,626.2 1,560.3 1,474.2 1,418.0 Net income 1,280.4 1,236.5 1,044.8 1,125.4 Net income attributable to limited partners 1,260.5 1,214.7 1,019.2 1,096.9 Earnings per unit: Basic $ 0.57 $ 0.55 $ 0.46 $ 0.50 Diluted $ 0.57 $ 0.55 $ 0.46 $ 0.50 For the Year Ended December 31, 2018: Revenues $ 9,298.5 $ 8,467.5 $ 9,585.9 $ 9,182.3 Operating income 1,138.5 986.4 1,643.3 1,640.4 Net income 911.5 687.2 1,334.6 1,305.2 Net income attributable to limited partners 900.7 673.8 1,313.2 1,284.7 Earnings per unit: Basic $ 0.41 $ 0.31 $ 0.60 $ 0.59 Diluted $ 0.41 $ 0.31 $ 0.60 $ 0.59

Condensed Consolidating Finan_2

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2019
Condensed Consolidating Financial Information [Abstract]
Condensed Consolidating Balance Sheet	Enterprise Products Partners L.P. Condensed Consolidating Balance Sheet December 31, 2019 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 $ 109.2 $ 315.8 $ (15.1 ) $ 409.9 $ 0.1 $ – $ 410.0 Accounts receivable – trade, net 1,471.1 3,403.8 (1.3 ) 4,873.6 – – 4,873.6 Accounts receivable – related parties 233.1 799.9 (1,023.6 ) 9.4 – (6.9 ) 2.5 Inventories 1,351.3 740.4 (0.3 ) 2,091.4 – – 2,091.4 Derivative assets 115.2 12.0 – 127.2 – – 127.2 Prepaid and other current assets 221.0 183.5 (46.3 ) 358.2 – – 358.2 Total current assets 3,500.9 5,455.4 (1,086.6 ) 7,869.7 0.1 (6.9 ) 7,862.9 Property, plant and equipment, net 6,413.3 35,233.6 (43.5 ) 41,603.4 – – 41,603.4 Investments in unconsolidated affiliates 45,514.0 4,165.7 (47,079.5 ) 2,600.2 25,279.3 (25,279.3 ) 2,600.2 Intangible assets, net 636.7 2,852.3 (40.0 ) 3,449.0 – – 3,449.0 Goodwill 459.5 5,285.7 – 5,745.2 – – 5,745.2 Other assets 404.9 288.5 (221.9 ) 471.5 1.0 – 472.5 Total assets $ 56,929.3 $ 53,281.2 $ (48,471.5 ) $ 61,739.0 $ 25,280.4 $ (25,286.2 ) $ 61,733.2 LIABILITIES AND EQUITY Current liabilities: Current maturities of debt $ 1,981.9 $ – $ – $ 1,981.9 $ – $ – $ 1,981.9 Accounts payable – trade 301.4 717.7 (14.6 ) 1,004.5 – – 1,004.5 Accounts payable – related parties 977.5 222.3 (1,037.5 ) 162.3 6.9 (6.9 ) 162.3 Accrued product payables 1,895.4 3,021.9 (1.6 ) 4,915.7 – – 4,915.7 Accrued interest 431.6 0.9 (0.8 ) 431.7 – – 431.7 Derivative liabilities 114.2 8.2 – 122.4 – – 122.4 Other current liabilities 120.5 438.2 (47.3 ) 511.4 – (0.2 ) 511.2 Total current liabilities 5,822.5 4,409.2 (1,101.8 ) 9,129.9 6.9 (7.1 ) 9,129.7 Long-term debt 25,628.6 14.6 – 25,643.2 – – 25,643.2 Deferred tax liabilities 22.2 75.6 (0.8 ) 97.0 – 3.4 100.4 Other long-term liabilities 161.2 608.9 (247.2 ) 522.9 509.5 – 1,032.4 Commitments and contingencies Equity: Partners’ and other owners’ equity 25,294.8 48,107.6 (48,155.3 ) 25,247.1 24,764.0 (25,247.1 ) 24,764.0 Noncontrolling interests – 65.3 1,033.6 1,098.9 – (35.4 ) 1,063.5 Total equity 25,294.8 48,172.9 (47,121.7 ) 26,346.0 24,764.0 (25,282.5 ) 25,827.5 Total liabilities and equity $ 56,929.3 $ 53,281.2 $ (48,471.5 ) $ 61,739.0 $ 25,280.4 $ (25,286.2 ) $ 61,733.2 Enterprise Products Partners L.P. Condensed Consolidating Balance Sheet December 31, 2018 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 $ 393.4 $ 50.3 $ (33.6 ) $ 410.1 $ – $ – $ 410.1 Accounts receivable – trade, net 1,303.1 2,356.8 (0.8 ) 3,659.1 – – 3,659.1 Accounts receivable – related parties 141.8 1,423.7 (1,530.1 ) 35.4 0.8 (32.7 ) 3.5 Inventories 889.3 633.2 (0.4 ) 1,522.1 – – 1,522.1 Derivative assets 105.0 49.1 0.3 154.4 – – 154.4 Prepaid and other current assets 166.0 155.1 (10.2 ) 310.9 – 0.6 311.5 Total current assets 2,998.6 4,668.2 (1,574.8 ) 6,092.0 0.8 (32.1 ) 6,060.7 Property, plant and equipment, net 6,112.7 32,628.7 (3.8 ) 38,737.6 – – 38,737.6 Investments in unconsolidated affiliates 43,962.6 4,170.6 (45,518.1 ) 2,615.1 24,273.6 (24,273.6 ) 2,615.1 Intangible assets, net 659.2 2,963.0 (13.8 ) 3,608.4 – – 3,608.4 Goodwill 459.5 5,285.7 – 5,745.2 – – 5,745.2 Other assets 292.1 131.9 (222.1 ) 201.9 0.9 – 202.8 Total assets $ 54,484.7 $ 49,848.1 $ (47,332.6 ) $ 57,000.2 $ 24,275.3 $ (24,305.7 ) $ 56,969.8 LIABILITIES AND EQUITY Current liabilities: Current maturities of debt $ 1,500.0 $ 0.1 $ – $ 1,500.1 $ – $ – $ 1,500.1 Accounts payable – trade 404.0 734.3 (35.5 ) 1,102.8 – – 1,102.8 Accounts payable – related parties 1,557.3 127.5 (1,543.9 ) 140.9 31.9 (32.6 ) 140.2 Accrued product payables 1,574.7 1,902.3 (1.2 ) 3,475.8 – – 3,475.8 Accrued interest 395.5 0.9 (0.8 ) 395.6 – – 395.6 Derivative liabilities 86.2 61.7 0.3 148.2 – – 148.2 Other current liabilities 87.9 326.3 (9.4 ) 404.8 – – 404.8 Total current liabilities 5,605.6 3,153.1 (1,590.5 ) 7,168.2 31.9 (32.6 ) 7,167.5 Long-term debt 24,663.4 14.7 – 24,678.1 – – 24,678.1 Deferred tax liabilities 17.0 62.0 (0.9 ) 78.1 – 2.3 80.4 Other long-term liabilities 65.2 518.4 (221.9 ) 361.7 389.9 – 751.6 Commitments and contingencies Equity: Partners’ and other owners’ equity 24,133.5 46,031.8 (45,917.9 ) 24,247.4 23,853.5 (24,247.4 ) 23,853.5 Noncontrolling interests – 68.1 398.6 466.7 – (28.0 ) 438.7 Total equity 24,133.5 46,099.9 (45,519.3 ) 24,714.1 23,853.5 (24,275.4 ) 24,292.2 Total liabilities and equity $ 54,484.7 $ 49,848.1 $ (47,332.6 ) $ 57,000.2 $ 24,275.3 $ (24,305.7 ) $ 56,969.8
Condensed Consolidating Statement of Operations	Enterprise Products Partners L.P. Condensed Consolidating Statement of Operations For the Year Ended December 31, 2019 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 $ 35,396.9 $ 21,849.0 $ (24,456.7 ) $ 32,789.2 $ – $ – $ 32,789.2 Costs and expenses: Operating costs and expenses 34,074.1 17,438.7 (24,451.0 ) 27,061.8 – – 27,061.8 General and administrative costs 32.2 174.2 3.1 209.5 2.2 – 211.7 Total costs and expenses 34,106.3 17,612.9 (24,447.9 ) 27,271.3 2.2 – 27,273.5 Equity in income of unconsolidated affiliates 4,667.1 648.7 (4,752.8 ) 563.0 4,713.0 (4,713.0 ) 563.0 Operating income 5,957.7 4,884.8 (4,761.6 ) 6,080.9 4,710.8 (4,713.0 ) 6,078.7 Other income (expense): Interest expense (1,243.8 ) (10.5 ) 11.3 (1,243.0 ) – – (1,243.0 ) Other, net 19.8 8.0 (11.3 ) 16.5 (119.5 ) – (103.0 ) Total other expense, net (1,224.0 ) (2.5 ) – (1,226.5 ) (119.5 ) – (1,346.0 ) Income before income taxes 4,733.7 4,882.3 (4,761.6 ) 4,854.4 4,591.3 (4,713.0 ) 4,732.7 Provision for income taxes (16.5 ) (28.3 ) 0.3 (44.5 ) – (1.1 ) (45.6 ) Net income 4,717.2 4,854.0 (4,761.3 ) 4,809.9 4,591.3 (4,714.1 ) 4,687.1 Net loss (income) attributable to noncontrolling interests – (6.6 ) (94.7 ) (101.3 ) – 5.5 (95.8 ) Net income attributable to entity $ 4,717.2 $ 4,847.4 $ (4,856.0 ) $ 4,708.6 $ 4,591.3 $ (4,708.6 ) $ 4,591.3 Enterprise Products Partners L.P. Condensed Consolidating Statement of Operations For the Year Ended December 31, 2018 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 $ 42,946.4 $ 23,756.4 $ (30,168.6 ) $ 36,534.2 $ – $ – $ 36,534.2 Costs and expenses: Operating costs and expenses 41,718.2 19,845.2 (30,166.1 ) 31,397.3 – – 31,397.3 General and administrative costs 31.8 172.0 2.1 205.9 2.3 0.1 208.3 Total costs and expenses 41,750.0 20,017.2 (30,164.0 ) 31,603.2 2.3 0.1 31,605.6 Equity in income of unconsolidated affiliates 4,148.3 587.2 (4,255.5 ) 480.0 4,230.8 (4,230.8 ) 480.0 Operating income 5,344.7 4,326.4 (4,260.1 ) 5,411.0 4,228.5 (4,230.9 ) 5,408.6 Other income (expense): Interest expense (1,097.1 ) (10.5 ) 10.9 (1,096.7 ) – – (1,096.7 ) Other, net 12.1 41.8 (10.9 ) 43.0 (56.1 ) – (13.1 ) Total other expense, net (1,085.0 ) 31.3 – (1,053.7 ) (56.1 ) – (1,109.8 ) Income before income taxes 4,259.7 4,357.7 (4,260.1 ) 4,357.3 4,172.4 (4,230.9 ) 4,298.8 Provision for income taxes (29.2 ) (29.6 ) – (58.8 ) – (1.5 ) (60.3 ) Net income 4,230.5 4,328.1 (4,260.1 ) 4,298.5 4,172.4 (4,232.4 ) 4,238.5 Net loss (income) attributable to noncontrolling interests – (7.6 ) (63.8 ) (71.4 ) – 5.3 (66.1 ) Net income attributable to entity $ 4,230.5 $ 4,320.5 $ (4,323.9 ) $ 4,227.1 $ 4,172.4 $ (4,227.1 ) $ 4,172.4 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
Condensed Consolidating Statement of Comprehensive Income	Enterprise Products Partners L.P. Condensed Consolidating Statement of Comprehensive Income For the Year Ended December 31, 2019 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 $ 4,890.2 $ 4,701.5 $ (4,761.3 ) $ 4,830.4 $ 4,611.8 $ (4,734.6 ) $ 4,707.6 Comprehensive loss (income) attributable to noncontrolling interests – (6.6 ) (94.7 ) (101.3 ) – 5.5 (95.8 ) Comprehensive income attributable to entity $ 4,890.2 $ 4,694.9 $ (4,856.0 ) $ 4,729.1 $ 4,611.8 $ (4,729.1 ) $ 4,611.8 Enterprise Products Partners L.P. Condensed Consolidating Statement of Comprehensive Income For the Year Ended December 31, 2018 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 $ 4,312.6 $ 4,468.5 $ (4,260.1 ) $ 4,521.0 $ 4,395.0 $ (4,454.9 ) $ 4,461.1 Comprehensive loss (income) attributable to noncontrolling interests – (7.6 ) (63.8 ) (71.4 ) – 5.3 (66.1 ) Comprehensive income attributable to entity $ 4,312.6 $ 4,460.9 $ (4,323.9 ) $ 4,449.6 $ 4,395.0 $ (4,449.6 ) $ 4,395.0 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
Condensed Consolidating Statement of Cash Flows	Enterprise Products Partners L.P. Condensed Consolidating Statement of Cash Flows For the Year Ended December 31, 2019 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 $ 4,717.2 $ 4,854.0 $ (4,761.3 ) $ 4,809.9 $ 4,591.3 $ (4,714.1 ) $ 4,687.1 Reconciliation of net income to net cash flows provided by operating activities: Depreciation, amortization and accretion 309.0 1,642.7 (2.4 ) 1,949.3 – – 1,949.3 Equity in income of unconsolidated affiliates (4,667.1 ) (648.7 ) 4,752.8 (563.0 ) (4,713.0 ) 4,713.0 (563.0 ) Distributions received from unconsolidated affiliates attributable to earnings 1,560.7 317.7 (1,310.4 ) 568.0 4,005.8 (4,005.8 ) 568.0 Net effect of changes in operating accounts and other operating activities 3,007.5 (3,294.0 ) 35.5 (251.0 ) 129.9 0.2 (120.9 ) Net cash flows provided by operating activities 4,927.3 2,871.7 (1,285.8 ) 6,513.2 4,014.0 (4,006.7 ) 6,520.5 Investing activities: Capital expenditures (675.4 ) (3,850.2 ) (6.1 ) (4,531.7 ) – – (4,531.7 ) Proceeds from asset sales 2.3 18.3 – 20.6 – – 20.6 Other investing activities (2,080.6 ) 3.7 2,012.5 (64.4 ) (119.3 ) 119.3 (64.4 ) Cash used in investing activities (2,753.7 ) (3,828.2 ) 2,006.4 (4,575.5 ) (119.3 ) 119.3 (4,575.5 ) Financing activities: Borrowings under debt agreements 58,172.6 – – 58,172.6 – – 58,172.6 Repayments of debt (56,716.4 ) (0.1 ) – (56,716.5 ) – – (56,716.5 ) Cash distributions paid to partners (4,005.8 ) (1,871.7 ) 1,871.7 (4,005.8 ) (3,839.8 ) 4,005.8 (3,839.8 ) Cash payments made in connection with DERs – – – – (22.1 ) – (22.1 ) Cash distributions paid to noncontrolling interests – (9.5 ) (97.6 ) (107.1 ) – 0.9 (106.2 ) Cash contributions from noncontrolling interests – – 632.8 632.8 – – 632.8 Net cash proceeds from issuance of common units – – – – 82.2 – 82.2 Common units acquired in connection with 2019 Buyback Program – – – – (81.1 ) – (81.1 ) Cash contributions from owners 119.3 3,109.0 (3,109.0 ) 119.3 – (119.3 ) – Other financing activities (27.5 ) (5.7 ) – (33.2 ) (33.8 ) – (67.0 ) Cash provided by (used in) financing activities (2,457.8 ) 1,222.0 (702.1 ) (1,937.9 ) (3,894.6 ) 3,887.4 (1,945.1 ) Net change in cash and cash equivalents, including restricted cash (284.2 ) 265.5 18.5 (0.2 ) 0.1 – (0.1 ) Cash and cash equivalents, including restricted cash, January 1 393.4 50.3 (33.6 ) 410.1 – – 410.1 Cash and cash equivalents, including restricted cash, December 31 $ 109.2 $ 315.8 $ (15.1 ) $ 409.9 $ 0.1 $ – $ 410.0 Enterprise Products Partners L.P. Condensed Consolidating Statement of Cash Flows For the Year Ended December 31, 2018 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 $ 4,230.5 $ 4,328.1 $ (4,260.1 ) $ 4,298.5 $ 4,172.4 $ (4,232.4 ) $ 4,238.5 Reconciliation of net income to net cash flows provided by operating activities: Depreciation, amortization and accretion 279.9 1,512.1 (0.4 ) 1,791.6 – – 1,791.6 Equity in income of unconsolidated affiliates (4,148.3 ) (587.2 ) 4,255.5 (480.0 ) (4,230.8 ) 4,230.8 (480.0 ) Distributions received from unconsolidated affiliates attributable to earnings 1,248.9 263.0 (1,032.5 ) 479.4 3,780.0 (3,780.0 ) 479.4 Net effect of changes in operating accounts and other operating activities 3,221.5 (3,244.2 ) (2.3 ) (25.0 ) 121.2 0.6 96.8 Net cash flows provided by operating activities 4,832.5 2,271.8 (1,039.8 ) 6,064.5 3,842.8 (3,781.0 ) 6,126.3 Investing activities: Capital expenditures (692.0 ) (3,476.0 ) – (4,168.0 ) (55.2 ) – (4,223.2 ) Cash used for business combinations, net of cash received – (150.6 ) – (150.6 ) – – (150.6 ) Proceeds from asset sales 129.3 31.9 – 161.2 – – 161.2 Other investing activities (2,288.2 ) 196.2 2,023.0 (69.0 ) (523.3 ) 523.3 (69.0 ) Cash used in investing activities (2,850.9 ) (3,398.5 ) 2,023.0 (4,226.4 ) (578.5 ) 523.3 (4,281.6 ) Financing activities: Borrowings under debt agreements 79,588.7 11.5 (11.5 ) 79,588.7 – – 79,588.7 Repayments of debt (77,956.7 ) (0.4 ) – (77,957.1 ) – – (77,957.1 ) Cash distributions paid to partners (3,780.0 ) (1,333.1 ) 1,333.1 (3,780.0 ) (3,726.9 ) 3,780.0 (3,726.9 ) Cash payments made in connection with DERs – – – – (17.7 ) – (17.7 ) Cash distributions paid to noncontrolling interests – (9.2 ) (73.4 ) (82.6 ) – 1.0 (81.6 ) Cash contributions from noncontrolling interests – – 238.1 238.1 – – 238.1 Net cash proceeds from issuance of common units – – – – 538.4 – 538.4 Common units acquired in connection with Legacy Buyback Program – – – – (30.8 ) – (30.8 ) Cash contributions from owners 523.3 2,476.7 (2,476.7 ) 523.3 – (523.3 ) – Other financing activities (28.7 ) – – (28.7 ) (27.3 ) – (56.0 ) Cash provided by (used in) financing activities (1,653.4 ) 1,145.5 (990.4 ) (1,498.3 ) (3,264.3 ) 3,257.7 (1,504.9 ) Net change in cash and cash equivalents, including restricted cash 328.2 18.8 (7.2 ) 339.8 – – 339.8 Cash and cash equivalents, including restricted cash, January 1 65.2 31.5 (26.4 ) 70.3 – – 70.3 Cash and cash equivalents, including restricted cash, December 31 $ 393.4 $ 50.3 $ (33.6 ) $ 410.1 $ – $ – $ 410.1 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 from unconsolidated affiliates attributable to earnings 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 (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 and cash equivalents, including restricted cash (301.0 ) (27.4 ) (18.9 ) (347.3 ) – – (347.3 ) Cash and cash equivalents, including restricted cash, January 1 366.2 58.9 (7.5 ) 417.6 – – 417.6 Cash and cash equivalents, including restricted cash, December 31 $ 65.2 $ 31.5 $ (26.4 ) $ 70.3 $ – $ – $ 70.3

Partnership Operations, Organ_2

Partnership Operations, Organization and Basis of Presentation (Details) bbl in Millions	12 Months Ended
	Dec. 31, 2019SegmentmiBcfbbl
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
Enterprise Products Partners L.P. [Member]
Related Party Transaction [Line Items]
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%

Summary of Significant Accoun_4

Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash, Cash Equivalents and Restricted Cash:
Cash and cash equivalents	$ 334.7	$ 344.8
Restricted cash	75.3	65.3
Total cash, cash equivalents and restricted cash shown in the Statements of Consolidated Cash Flows	410	410.1	$ 70.3	$ 417.6
Allowance for Doubtful Accounts [Member]
Movement in valuation allowances and reserves [Roll Forward]
Balance at beginning of period	11.5	12.1	11.3
Charged to costs and expenses	1.2	0.7	2.7
Deductions	(0.3)	(1.3)	(1.9)
Balance at end of period	$ 12.4	$ 11.5	$ 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%

Summary of Significant Accoun_5

Summary of Significant Accounting Policies, Part 2 (Details)	12 Months Ended
	Dec. 31, 2019
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 Accoun_6

Summary of Significant Accounting Policies, Part 3 (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Environmental Costs [Abstract]
Environmental reserves - current portion	$ 5.8	$ 3.2
Schedule of Equity Method Investments [Line Items]
Non-cash asset impairment charge of unconsolidated affiliate	76.4
Environmental Reserves [Member]
Movement in valuation allowances and reserves [Roll Forward]
Balance at beginning of period	6.9	11.6	$ 11.9
Charged to costs and expenses	12.3	8.2	12.1
Acquisition-related additions and other	2.5	1.7	1.7
Deductions	(14.5)	(14.6)	(14.1)
Balance at end of period	$ 7.2	$ 6.9	$ 11.6

Inventories (Details)

Inventories (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Inventory by Product Type [Abstract]
NGLs		$ 1,094.9	$ 647.7
Petrochemicals and refined products		311.5	264.7
Crude oil		674.2	593.4
Natural gas		10.8	16.3
Total		2,091.4	1,522.1
Summary of cost of sales and lower of cost or net realizable value adjustments [Abstract]
Cost of sales	[1]	22,065.8	26,789.8	$ 21,487
Lower of cost or net realizable value adjustments recognized in cost of sales		$ 22.7	$ 11.5	$ 9.1
[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_2

Property, Plant and Equipment (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Property, plant and equipment and accumulated depreciation [Abstract]
Property, plant and equipment, gross		$ 55,285	$ 50,897.2
Less accumulated depreciation		13,681.6	12,159.6
Property, plant and equipment, net		41,603.4	38,737.6	$ 35,620.4
Summary of depreciation expense and capitalized interest [Abstract]
Depreciation expense	[1]	1,562.6	1,436.2	1,296.1
Capitalized interest	[2]	143.8	147.9	192.1
Asset Retirement Obligations [Roll Forward]
ARO liability beginning balance		126.3	86.7	85.4
Liabilities incurred		5	24.4	4.7
Liabilities settled		(2.3)	(2.5)	(2.2)
Revisions in estimated cash flows		(4.8)	11.5	(6.7)
Accretion expense		7.9	6.2	5.5
ARO liability ending balance		132.1	126.3	$ 86.7
Capitalized costs, asset retirement costs		69.6	72.5
Forecasted accretion expense [Abstract]
2020		8.2
2021		8.6
2022		9.1
2023		9.6
2024		10.3
Plants, pipelines and facilities [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Property, plant and equipment, gross	[3]	$ 47,201.2	42,371
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]	$ 3,965.5	3,624.2
Underground and other storage facilities [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life	[5],[6]	5 years
Underground and other storage facilities [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life	[5],[6]	40 years
Transportation equipment [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Property, plant and equipment, gross	[7]	$ 198.9	187.1
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]	$ 905.9	828.6
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		$ 372.3	359.5
Construction in progress [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Property, plant and equipment, gross		$ 2,641.2	$ 3,526.8
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. We placed a number of major growth projects into service during 2019 including the Shin Oak NGL pipeline, Midland-to-ECHO 2 pipeline, an isobutane dehydrogenation facility, the Mentone and Bulldog natural gas processing plants, and LPG-related expansion projects at our Enterprise Hydrocarbons Terminal.
[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.Marine vessels include tow boats, barges and related equipment used in our marine transportation business.
[8]	Marine vessels include tow boats, barges and related equipment used in our marine transportation business.

Investments in Unconsolidated_3

Investments in Unconsolidated Affiliates (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Schedule of Equity Method Investments [Line Items]
Investments in unconsolidated affiliates		$ 2,600.2	$ 2,615.1	$ 2,659.4
Non-cash asset impairment charge of unconsolidated affiliate		76.4
Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]
Equity in income (loss) of unconsolidated affiliates		563	480	426
Unamortized excess cost amounts by business segment:
Unamortized excess cost amounts		37.1	40.8
Equity method investment amortization of excess cost		2.1	2.1	2.1
Forecasted amortization of excess cost amounts - 2020		2
Forecasted amortization of excess cost amounts - 2021		2
Forecasted amortization of excess cost amounts - 2022		2
Forecasted amortization of excess cost amounts - 2023		2
Forecasted amortization of excess cost amounts - 2024		2
Balance Sheet Data:
Current assets		358.1	350.2
Property, plant and equipment, net		5,379.7	5,359.1
Other assets		68.7	80.4
Total assets		5,806.5	5,789.7
Current liabilities		230.9	220.6
Other liabilities		69.6	77.9
Combined equity		5,506	5,491.2
Total liabilities and combined equity		5,806.5	5,789.7
Income Statement Data:
Revenues		1,950.2	1,721.3	1,509
Operating income		1,250.4	1,074.6	925.9
Net income		1,251.8	1,069.1	929.5
NGL Pipelines & Services [Member]
Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]
Equity in income (loss) of unconsolidated affiliates		114.5	117	73.4
Unamortized excess cost amounts by business segment:
Unamortized excess cost amounts		$ 20.5	21.7
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		$ 23.2	24.1
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		$ 25.7	28.9
NGL Pipelines & Services [Member] | Baton Rouge Fractionators LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest		32.20%
Investments in unconsolidated affiliates		$ 15.6	16.3
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		$ 33.1	35.6
NGL Pipelines & Services [Member] | Texas Express Pipeline LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest		35.00%
Investments in unconsolidated affiliates		$ 358.1	337.6
NGL Pipelines & Services [Member] | Texas Express Gathering LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest		45.00%
Investments in unconsolidated affiliates		$ 41.1	43.6
NGL Pipelines & Services [Member] | Front Range Pipeline LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest		33.30%
Investments in unconsolidated affiliates		$ 207	175.9
Crude Oil Pipelines & Services [Member]
Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]
Equity in income (loss) of unconsolidated affiliates		449.2	365.4	358.4
Unamortized excess cost amounts by business segment:
Unamortized excess cost amounts		$ 16.6	17.4
Crude Oil Pipelines & Services [Member] | Seaway Crude Holdings LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest		50.00%
Investments in unconsolidated affiliates		$ 1,353.1	1,369.7
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		$ 386.5	388.7
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		$ 126.9	109.1
Natural Gas Pipelines & Services [Member]
Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]
Equity in income (loss) of unconsolidated affiliates		$ 6.3	6.8	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		$ 19.1	20.1
Natural Gas Pipelines & Services [Member] | Old Ocean Pipeline, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest		50.00%
Investments in unconsolidated affiliates		$ 8.2	2.7
Petrochemical & Refined Products Services [Member]
Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]
Equity in income (loss) of unconsolidated affiliates	[1]	(7)	(9.2)	$ (9.6)
Unamortized excess cost amounts by business segment:
Unamortized excess cost amounts		$ 0	1.7
Petrochemical & Refined Products Services [Member] | Centennial Pipeline LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest		50.00%
Investments in unconsolidated affiliates	[2]	$ 0	59.1
Non-cash asset impairment charge of unconsolidated affiliate		$ 76.4
Petrochemical & Refined Products Services [Member] | Baton Rouge Propylene Concentrator, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest		30.00%
Investments in unconsolidated affiliates		$ 2	3.2
Petrochemical & Refined Products Services [Member] | Transport 4, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest		25.00%
Investments in unconsolidated affiliates		$ 0.6	$ 0.5
[1]	The losses recorded for this segment are primarily due to protection, maintenance and pipeline integrity costs of the idled Centennial Pipeline, which was purged and filled with nitrogen in 2013. Although we wrote off our investment in Centennial in 2019, we, as a 50% owner of Centennial, have a continuing obligation to fund the pipeline’s costs in its idled state.
[2]	The investment in Centennial was written off in December 2019.

Intangible Assets and Goodwill,

Intangible Assets and Goodwill, Intangible Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Identifiable intangible assets [Abstract]
Gross Value	$ 5,136.5	$ 5,343.5
Accumulated Amortization	(1,687.5)	(1,735.1)
Carrying Value	3,449	3,608.4	$ 3,690.3
Amortization expense	174.7	170.3	166.9
Forecasted amortization expense [Abstract]
2020	164.8
2021	167
2022	164
2023	162.4
2024	158.9
Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Carrying Value	3,200
Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Carrying Value	254.9
NGL Pipelines & Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	610.4	820.7
Accumulated Amortization	(250.2)	(440.6)
Carrying Value	360.2	380.1
Amortization expense	31.9	34.7	28.9
NGL Pipelines & Services [Member] | Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	447.8	457.3
Accumulated Amortization	(206.3)	(201.9)
Carrying Value	241.5	255.4
NGL Pipelines & Services [Member] | Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	162.6	363.4
Accumulated Amortization	(43.9)	(238.7)
Carrying Value	118.7	124.7
Crude Oil Pipelines & Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	2,480.4	2,480.4
Accumulated Amortization	(478.5)	(385.8)
Carrying Value	2,001.9	2,094.6
Amortization expense	92.7	87.8	92.5
Crude Oil Pipelines & Services [Member] | Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	2,203.5	2,203.5
Accumulated Amortization	(243.5)	(174.1)
Carrying Value	1,960	2,029.4
Crude Oil Pipelines & Services [Member] | Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	276.9	276.9
Accumulated Amortization	(235)	(211.7)
Carrying Value	41.9	65.2
Natural Gas Pipelines & Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	1,818.3	1,815
Accumulated Amortization	(877.1)	(835.7)
Carrying Value	941.2	979.3
Amortization expense	41.4	39.1	36.2
Natural Gas Pipelines & Services [Member] | Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	1,350.3	1,350.3
Accumulated Amortization	(481.6)	(447.8)
Carrying Value	868.7	902.5
Natural Gas Pipelines & Services [Member] | Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	468	464.7
Accumulated Amortization	(395.5)	(387.9)
Carrying Value	72.5	76.8
Petrochemical & Refined Products Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	227.4	227.4
Accumulated Amortization	(81.7)	(73)
Carrying Value	145.7	154.4
Amortization expense	8.7	8.7	$ 9.3
Petrochemical & Refined Products Services [Member] | Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	181.4	181.4
Accumulated Amortization	(57.5)	(51.8)
Carrying Value	123.9	129.6
Petrochemical & Refined Products Services [Member] | Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	46	46
Accumulated Amortization	(24.2)	(21.2)
Carrying Value	$ 21.8	$ 24.8

Intangible Assets and Goodwil_2

Intangible Assets and Goodwill, Significant Intangible Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Identifiable intangible assets [Abstract]
Gross Value	$ 5,136.5	$ 5,343.5
Accumulated Amortization	(1,687.5)	(1,735.1)
Carrying Value	3,449	$ 3,608.4	$ 3,690.3
Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Carrying Value	3,200
Customer relationship intangibles [Member] | EFS Midstream [Member]
Identifiable intangible assets [Abstract]
Gross Value	1,409.8
Accumulated Amortization	(160.1)
Carrying Value	$ 1,249.7
Weighted Average Remaining Amortization Period	22 years 4 months 24 days
Customer relationship intangibles [Member] | State Line and Fairplay [Member]
Identifiable intangible assets [Abstract]
Gross Value	$ 895
Accumulated Amortization	(205.1)
Carrying Value	$ 689.9
Weighted Average Remaining Amortization Period	27 years 2 months 12 days
Customer relationship intangibles [Member] | San Juan Gathering [Member]
Identifiable intangible assets [Abstract]
Gross Value	$ 331.3
Accumulated Amortization	(236.8)
Carrying Value	$ 94.5
Weighted Average Remaining Amortization Period	19 years 9 months 18 days
Customer relationship intangibles [Member] | Oiltanking Partners L.P. [Member]
Identifiable intangible assets [Abstract]
Gross Value	$ 1,192.5
Accumulated Amortization	(122.2)
Carrying Value	$ 1,070.3
Weighted Average Remaining Amortization Period	24 years
Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Carrying Value	$ 254.9
Contract-based intangibles [Member] | Oiltanking Partners L.P. [Member]
Identifiable intangible assets [Abstract]
Gross Value	293.3
Accumulated Amortization	(245.9)
Carrying Value	$ 47.4
Weighted Average Remaining Amortization Period	3 years 7 months 6 days
Contract-based intangibles [Member] | Jonah Gas Gathering [Member]
Identifiable intangible assets [Abstract]
Gross Value	$ 224.4
Accumulated Amortization	(171.4)
Carrying Value	$ 53
Weighted Average Remaining Amortization Period	22 years
Contract-based intangibles [Member] | Delaware Basin Gas Processing LLC [Member]
Identifiable intangible assets [Abstract]
Gross Value	$ 82.6
Accumulated Amortization	(15)
Carrying Value	$ 67.6
Weighted Average Remaining Amortization Period	7 years

Intangible Assets and Goodwil_3

Intangible Assets and Goodwill, Goodwill (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Goodwill [Line Items]
Goodwill	$ 5,745.2	$ 5,745.2	$ 5,745.2

Debt Obligations (Details)

Debt Obligations (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Principal outstanding		$ 27,878.4	$ 26,420.6
Other, non-principal amounts		(253.3)	(242.4)
Less current maturities of debt		(1,981.9)	(1,500.1)
Total long-term debt		25,643.2	24,678.1
Debt Obligations Terms:
Repayment of debt obligations		56,716.5	77,957.1	$ 68,459.6
Letters of credit outstanding for facilities and motor fuel tax obligations		101.4
Senior Debt Obligations [Member]
Debt Instrument [Line Items]
Principal outstanding		25,232	23,750
Senior Debt Obligations [Member] | Commercial Paper Notes [Member]
Debt Instrument [Line Items]
Principal outstanding		482	0
Debt Obligations Terms:
Maximum borrowing capacity		$ 3,000
Information regarding variable interest rates paid:
Weighted-average interest rate paid		2.61%
Senior Debt Obligations [Member] | Commercial Paper Notes [Member] | Minimum [Member]
Information regarding variable interest rates paid:
Variable interest rates paid		1.79%
Senior Debt Obligations [Member] | Commercial Paper Notes [Member] | Maximum [Member]
Information regarding variable interest rates paid:
Variable interest rates paid		2.80%
Senior Debt Obligations [Member] | EPO Senior Notes N due January 2019 [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 0	700
Debt Obligations Terms:
Interest rate, stated percentage		6.50%
Senior Debt Obligations [Member] | EPO Senior Notes LL due October 2019 [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 0	800
Debt Obligations Terms:
Interest rate, stated percentage		2.55%
Senior Debt Obligations [Member] | EPO Senior Notes Q due January 2020 [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 500	500
Debt Obligations Terms:
Interest rate, stated percentage		5.25%
Senior Debt Obligations [Member] | EPO Senior Notes Y due September 2020 [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 1,000	1,000
Debt Obligations Terms:
Interest rate, stated percentage		5.20%
Senior Debt Obligations [Member] | EPO 364-Day Revolving Credit Agreement due September 2020 [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 0	0
Debt Obligations Terms:
Maximum borrowing capacity		1,500
Maximum bank commitments increase		200
Total maximum borrowing capacity		$ 1,700
Information regarding variable interest rates paid:
Credit facility interest rate description		Amounts borrowed under our 364-Day and Multi-Year Revolving Credit Agreements bear interest, at our election, equal to: (i) LIBOR, plus an additional variable spread; or (ii) an alternate base rate, which is the greater of (a) the Prime Rate in effect on such day, (b) the Federal Funds Effective Rate in effect on such day plus 0.5%, or (c) the LIBO Market Index Rate in effect on such day plus 1% and a variable spread. The applicable spreads are determined based on our debt ratings.
Senior Debt Obligations [Member] | EPO Senior Notes TT due February 2021 [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 750	750
Debt Obligations Terms:
Interest rate, stated percentage		2.80%
Senior Debt Obligations [Member] | EPO Senior Notes RR due April 2021 [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 575	575
Debt Obligations Terms:
Interest rate, stated percentage		2.85%
Senior Debt Obligations [Member] | EPO Senior Notes VV due February 2022 [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 750	750
Debt Obligations Terms:
Interest rate, stated percentage		3.50%
Senior Debt Obligations [Member] | EPO Senior Notes CC due February 2022 [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 650	650
Debt Obligations Terms:
Interest rate, stated percentage		4.05%
Senior Debt Obligations [Member] | EPO Senior Notes HH due March 2023 [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 1,250	1,250
Debt Obligations Terms:
Interest rate, stated percentage		3.35%
Senior Debt Obligations [Member] | EPO Senior Notes JJ due February 2024 [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 850	850
Debt Obligations Terms:
Interest rate, stated percentage		3.90%
Senior Debt Obligations [Member] | EPO Multi-Year Revolving Credit Agreement due September 2024 [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 0	0
Debt Obligations Terms:
Maximum borrowing capacity		3,500	4,000
Maximum bank commitments increase		500
Total maximum borrowing capacity		$ 4,000
Information regarding variable interest rates paid:
Credit facility interest rate description		Amounts borrowed under our 364-Day and Multi-Year Revolving Credit Agreements bear interest, at our election, equal to: (i) LIBOR, plus an additional variable spread; or (ii) an alternate base rate, which is the greater of (a) the Prime Rate in effect on such day, (b) the Federal Funds Effective Rate in effect on such day plus 0.5%, or (c) the LIBO Market Index Rate in effect on such day plus 1% and a variable spread. The applicable spreads are determined based on our debt ratings.
Senior Debt Obligations [Member] | EPO Senior Notes MM due February 2025 [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 1,150	1,150
Debt Obligations Terms:
Interest rate, stated percentage		3.75%
Senior Debt Obligations [Member] | EPO Senior Notes PP due February 2026 [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 875	875
Debt Obligations Terms:
Interest rate, stated percentage		3.70%
Senior Debt Obligations [Member] | EPO Senior Notes SS due February 2027[Member]
Debt Instrument [Line Items]
Principal outstanding		$ 575	575
Debt Obligations Terms:
Interest rate, stated percentage		3.95%
Senior Debt Obligations [Member] | EPO Senior Notes WW due October 2028 [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 1,000	1,000
Debt Obligations Terms:
Interest rate, stated percentage		4.15%
Senior Debt Obligations [Member] | EPO Senior Notes YY due July 2029 [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 1,250	0
Debt Obligations Terms:
Interest rate, stated percentage		3.125%
Aggregate debt principal issued		$ 1,250
Debt issued as percent of principal amount		99.955%
Senior Debt Obligations [Member] | EPO Senior Notes D due March 2033 [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 500	500
Debt Obligations Terms:
Interest rate, stated percentage		6.875%
Senior Debt Obligations [Member] | EPO Senior Notes H due October 2034 [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 350	350
Debt Obligations Terms:
Interest rate, stated percentage		6.65%
Senior Debt Obligations [Member] | EPO Senior Notes J due March 2035 [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 250	250
Debt Obligations Terms:
Interest rate, stated percentage		5.75%
Senior Debt Obligations [Member] | EPO Senior Notes W due April 2038 [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 399.6	399.6
Debt Obligations Terms:
Interest rate, stated percentage		7.55%
Senior Debt Obligations [Member] | EPO Senior Notes R due October 2039 [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 600	600
Debt Obligations Terms:
Interest rate, stated percentage		6.125%
Senior Debt Obligations [Member] | EPO Senior Notes Z due September 2040 [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 600	600
Debt Obligations Terms:
Interest rate, stated percentage		6.45%
Senior Debt Obligations [Member] | EPO Senior Notes BB due February 2041 [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 750	750
Debt Obligations Terms:
Interest rate, stated percentage		5.95%
Senior Debt Obligations [Member] | EPO Senior Notes DD due February 2042 [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 600	600
Debt Obligations Terms:
Interest rate, stated percentage		5.70%
Senior Debt Obligations [Member] | EPO Senior Notes EE due August 2042 [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 750	750
Debt Obligations Terms:
Interest rate, stated percentage		4.85%
Senior Debt Obligations [Member] | EPO Senior Notes GG due February 2043 [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 1,100	1,100
Debt Obligations Terms:
Interest rate, stated percentage		4.45%
Senior Debt Obligations [Member] | EPO Senior Notes II due March 2044 [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 1,400	1,400
Debt Obligations Terms:
Interest rate, stated percentage		4.85%
Senior Debt Obligations [Member] | EPO Senior Notes KK due February 2045 [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 1,150	1,150
Debt Obligations Terms:
Interest rate, stated percentage		5.10%
Senior Debt Obligations [Member] | EPO Senior Notes QQ due May 2046 [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 975	975
Debt Obligations Terms:
Interest rate, stated percentage		4.90%
Senior Debt Obligations [Member] | EPO Senior Notes UU due February 2048 [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 1,250	1,250
Debt Obligations Terms:
Interest rate, stated percentage		4.25%
Senior Debt Obligations [Member] | EPO Senior Notes XX due February 2049 [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 1,250	1,250
Debt Obligations Terms:
Interest rate, stated percentage		4.80%
Senior Debt Obligations [Member] | EPO Senior Notes ZZ due January 2050 [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 1,250	0
Debt Obligations Terms:
Interest rate, stated percentage		4.20%
Aggregate debt principal issued		$ 1,250
Debt issued as percent of principal amount		99.792%
Senior Debt Obligations [Member] | EPO Senior Notes NN due October 2054 [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 400	400
Debt Obligations Terms:
Interest rate, stated percentage		4.95%
Senior Debt Obligations [Member] | TEPPCO Senior Notes due April 2038 [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 0.4	0.4
Debt Obligations Terms:
Interest rate, stated percentage		7.55%
Junior Debt Obligations [Member]
Debt Obligations Terms:
Aggregate debt principal issued			700	$ 1,700
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes C due June 2067 [Member]
Debt Instrument [Line Items]
Principal outstanding	[1]	$ 232.2	256.4
Debt Obligations Terms:
Repayment of debt obligations		24.2
Gain on extinguishment of debt		$ 1.5
Variable annual interest rate thereafter, variable rate basis		3-month London Interbank Offered Rate ("LIBOR")
Variable interest rate	[1]	2.778%
Information regarding variable interest rates paid:
Weighted-average interest rate paid		5.22%
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes C due June 2067 [Member] | Minimum [Member]
Information regarding variable interest rates paid:
Variable interest rates paid		4.68%
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes C due June 2067 [Member] | Maximum [Member]
Information regarding variable interest rates paid:
Variable interest rates paid		5.52%
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes D due August 2077 [Member]
Debt Instrument [Line Items]
Principal outstanding	[2]	$ 700	700
Debt Obligations Terms:
Interest rate, stated percentage		4.875%
Variable annual interest rate thereafter, variable rate basis		3-month LIBOR
Variable interest rate		2.986%
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes E due August 2077 [Member]
Debt Instrument [Line Items]
Principal outstanding	[3]	$ 1,000	1,000
Debt Obligations Terms:
Interest rate, stated percentage		5.25%
Variable annual interest rate thereafter, variable rate basis		3-month LIBOR
Variable interest rate		3.033%
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes F due February 2078 [Member]
Debt Instrument [Line Items]
Principal outstanding	[4]	$ 700	700
Debt Obligations Terms:
Interest rate, stated percentage		5.375%
Variable annual interest rate thereafter, variable rate basis		3-month LIBOR
Variable interest rate		2.57%
Junior Debt Obligations [Member] | TEPPCO Junior Subordinated Notes due June 2067 [Member]
Debt Instrument [Line Items]
Principal outstanding	[1]	$ 14.2	14.2
Debt Obligations Terms:
Variable annual interest rate thereafter, variable rate basis		3-month London Interbank Offered Rate ("LIBOR")
Variable interest rate		2.778%
Information regarding variable interest rates paid:
Weighted-average interest rate paid		5.22%
Junior Debt Obligations [Member] | TEPPCO Junior Subordinated Notes due June 2067 [Member] | Minimum [Member]
Information regarding variable interest rates paid:
Variable interest rates paid		4.68%
Junior Debt Obligations [Member] | TEPPCO Junior Subordinated Notes due June 2067 [Member] | Maximum [Member]
Information regarding variable interest rates paid:
Variable interest rates paid		5.52%
Senior Notes [Member]
Debt Instrument [Line Items]
Principal outstanding		$ 24,750
Debt Obligations Terms:
Aggregate debt principal issued		$ 2,500	$ 5,000
[1]	Variable rate is reset quarterly and based on 3-month London Interbank Offered Rate ("LIBOR") plus 2.778%.
[2]	Fixed rate of 4.875% through August 15, 2022; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 2.986%.
[3]	Fixed rate of 5.250% through August 15, 2027; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 3.033%.
[4]	Fixed rate of 5.375% through February 14, 2028; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 2.57%.

Debt Obligations, Debt Maturiti

Debt Obligations, Debt Maturities (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Scheduled Maturities of Debt [Abstract]
2020	$ 1,982
2021	1,325
2022	1,400
2023	1,250
2024	850
Thereafter	21,071.4
Total	27,878.4	$ 26,420.6
Commercial Paper Notes [Member]
Scheduled Maturities of Debt [Abstract]
2020	482
2021	0
2022	0
2023	0
2024	0
Thereafter	0
Total	482
Senior Notes [Member]
Scheduled Maturities of Debt [Abstract]
2020	1,500
2021	1,325
2022	1,400
2023	1,250
2024	850
Thereafter	18,425
Total	24,750
Junior Subordinated Notes [Member]
Scheduled Maturities of Debt [Abstract]
2020	0
2021	0
2022	0
2023	0
2024	0
Thereafter	2,646.4
Total	$ 2,646.4

Equity and Distributions, Summa

Equity and Distributions, Summary of Changes in Outstanding Units (Details) - shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Summary of changes in outstanding units [Roll Forward]
Number of units issued and outstanding, beginning balance (in units)	2,184,869,029	2,161,089,479	2,117,588,414
Common units issued in connection with ATM program (in units)			21,807,726
Common unit repurchases under buyback program (in units)	(2,909,128)	(1,236,800)
Common units issued in connection with DRIP and EUPP (in units)	2,897,990	19,861,951	19,046,019
Common units issued in connection with the vesting of phantom unit awards (in units)	3,895,049	3,479,958	2,485,580
Common units issues in connection with the vesting of restricted common unit awards (in units)			0
Forfeiture of restricted common unit awards (in units)			(1,250)
Cancellation of treasury units acquired in connection with the vesting of equity-based awards (in units)	(1,174,446)	(1,037,522)	(1,027,798)
Common units issued in connection with employee compensation (in units)	1,626,041	1,443,586	1,176,103
Common units issued in connection with land acquisition (in units)		1,223,242
Other (in units)	21,595	45,135	14,685
Number of units issued and outstanding, ending balance (in units)	2,189,226,130	2,184,869,029	2,161,089,479
Common Units (Unrestricted) [Member]
Summary of changes in outstanding units [Roll Forward]
Number of units issued and outstanding, beginning balance (in units)	2,184,869,029	2,161,089,479	2,116,906,120
Common units issued in connection with ATM program (in units)			21,807,726
Common unit repurchases under buyback program (in units)	(2,909,128)	(1,236,800)
Common units issued in connection with DRIP and EUPP (in units)	2,897,990	19,861,951	19,046,019
Common units issued in connection with the vesting of phantom unit awards (in units)	3,895,049	3,479,958	2,485,580
Common units issues in connection with the vesting of restricted common unit awards (in units)			681,044
Forfeiture of restricted common unit awards (in units)			0
Cancellation of treasury units acquired in connection with the vesting of equity-based awards (in units)	(1,174,446)	(1,037,522)	(1,027,798)
Common units issued in connection with employee compensation (in units)	1,626,041	1,443,586	1,176,103
Common units issued in connection with land acquisition (in units)		1,223,242
Other (in units)	21,595	45,135	14,685
Number of units issued and outstanding, ending balance (in units)	2,189,226,130	2,184,869,029	2,161,089,479
Restricted Common Units [Member]
Summary of changes in outstanding units [Roll Forward]
Number of units issued and outstanding, beginning balance (in units)	0	0	682,294
Common units issued in connection with ATM program (in units)			0
Common unit repurchases under buyback program (in units)	0	0
Common units issued in connection with DRIP and EUPP (in units)	0	0	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 (in units)			(681,044)
Forfeiture of restricted common unit awards (in units)			(1,250)
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	0	0
Common units issued in connection with land acquisition (in units)		0
Other (in units)	0	0	0
Number of units issued and outstanding, ending balance (in units)	0	0	0

Equity and Distributions, Issua

Equity and Distributions, Issuances of Equity (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Net Cash Proceeds from Sale of Common Units [Abstract]
Net cash proceeds from the issuance of common units		$ 82.2	$ 538.4	$ 1,073.4
Common units issued in connection with employee compensation (in units)		1,626,041	1,443,586	1,176,103
Common units issued in connection with employee compensation		$ 45.6	$ 39.1	$ 33.7
Treasury Units:
Total of common units repurchased under a buyback program (in units)		2,909,128	1,236,800
Common units acquired in connection with buyback program		$ 81.1	$ 30.8
Phantom units vesting during the period (in units)		3,895,049	3,479,958	2,485,580
Phantom unit and restricted unit awards that vested during the period				3,166,624
Acquisition of treasury units in connection with vesting of equity-based awards (in units)		1,174,446	1,037,522	1,027,798
Capital expenditures		$ 4,531.7	$ 4,223.2	$ 3,101.8
Common units issued in connection with land acquisition (in units)			1,223,242
Land [Member]
Treasury Units:
Property, plant and equipment, additions			$ 85.2
Capital expenditures			$ 55.2
Common units issued in connection with land acquisition (in units)			1,223,242
Phantom Unit Awards [Member]
Treasury Units:
Phantom units vesting during the period (in units)		3,895,049	3,479,958	2,490,081
Treasury Units [Member]
Treasury Units:
Acquisition of treasury units in connection with vesting of equity-based awards (in units)		1,174,446	1,037,522	1,027,798
Common units acquired in connection with phantom unit awards		$ 33.7	$ 27.3	$ 29.5
Junior Debt Obligations [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Debt issued under universal shelf registration			$ 700	$ 1,700
2019 Buyback Program [Member]
Treasury Units:
Total of common units repurchased under a buyback program (in units)		2,909,128
Common units acquired in connection with buyback program		$ 81.1
Amount authorized under 2019 Buyback Program		2,000
Remaining available capacity under the 2019 Buyback Program		1,920
Legacy Buyback Program [Member]
Treasury Units:
Maximum common units authorized for repurchase under a buyback program (in units)			4,000,000
Total of common units repurchased under a buyback program (in units)			1,236,800
Common units acquired in connection with buyback program			$ 30.8
Universal Shelf Registration [Member] | Senior Debt Obligations [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Debt issued under universal shelf registration		2,500
Universal Shelf Registration [Member] | Senior Debt Obligations [Member] | Subsequent Event [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Debt issued under universal shelf registration	$ 3,000
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
Gross proceeds from the sale of common units				$ 603.1
Net cash proceeds from the issuance of common units				$ 597
Remaining units available for issuance		$ 2,540
Distribution Reinvestment Plan [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Number of common units issued (in units)		2,601,727	19,316,781	18,541,355
Net cash proceeds from the issuance of common units		$ 73.7	$ 523.3	$ 462.9
Distribution reinvestment plan discount rate		0.00%	2.50%
Remaining units available for issuance (in units)		56,320,229
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]
Gross proceeds from the sale of common units		$ 29	$ 213	$ 100
Employee Unit Purchase Plan [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Number of common units issued (in units)		296,263	545,170	504,664
Net cash proceeds from the issuance of common units		$ 8.5	$ 15.1	$ 13.5
Employer contribution to EUPP		$ 0.9
Remaining units available for issuance (in units)		4,596,585
Distribution Reinvestment and Employee Unit Purchase Plans [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Number of common units purchased on the open market and delivered to participants (in units)		2,801,196

Equity and Distributions, Accum

Equity and Distributions, Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Accumulated Other Comprehensive Income (Loss) [Abstract]
Accumulated Other Comprehensive Income (Loss), Beginning Balance				$ 50.9				$ (171.7)	$ 50.9		$ (171.7)
Other comprehensive income (loss) for period, before reclassifications									124.9		314.9
Reclassification of losses (gains) to net income during period									(104.4)		(92.3)
Total other comprehensive income (loss) for period									20.5		222.6		$ 108.3
Accumulated Other Comprehensive Income (Loss), Ending balance	$ 71.4				$ 50.9				71.4		50.9		(171.7)
Interest expense									1,243		1,096.7		984.6
Revenue	(8,005.3)	$ (7,964.1)	$ (8,276.3)	(8,543.5)	(9,182.3)	$ (9,585.9)	$ (8,467.5)	(9,298.5)	(32,789.2)	[1]	(36,534.2)	[1]	(29,241.5)	[2]
Operating costs and expenses									27,061.8		31,397.3		25,557.5
Total	(1,125.4)	$ (1,044.8)	$ (1,236.5)	(1,280.4)	(1,305.2)	$ (1,334.6)	$ (687.2)	(911.5)	(4,687.1)		(4,238.5)		(2,855.6)
Cash Flow Hedges [Member] | Commodity Derivatives [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Accumulated Other Comprehensive Income (Loss), Beginning Balance				152.7				(10.1)	152.7		(10.1)
Other comprehensive income (loss) for period, before reclassifications									44.1		293.2
Reclassification of losses (gains) to net income during period									(141.7)		(130.4)
Total other comprehensive income (loss) for period									(97.6)		162.8
Accumulated Other Comprehensive Income (Loss), Ending balance	55.1				152.7				55.1		152.7		(10.1)
Cash Flow Hedges [Member] | Interest Rate Derivatives [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Accumulated Other Comprehensive Income (Loss), Beginning Balance				(104.8)				(165.1)	(104.8)		(165.1)
Other comprehensive income (loss) for period, before reclassifications									81.4		22.2
Reclassification of losses (gains) to net income during period									37.3		38.1
Total other comprehensive income (loss) for period									118.7		60.3
Accumulated Other Comprehensive Income (Loss), Ending balance	13.9				(104.8)				13.9		(104.8)		(165.1)
Other [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Accumulated Other Comprehensive Income (Loss), Beginning Balance				$ 3				$ 3.5	3		3.5
Other comprehensive income (loss) for period, before reclassifications									(0.6)		(0.5)
Reclassification of losses (gains) to net income during period									0		0
Total other comprehensive income (loss) for period									(0.6)		(0.5)
Accumulated Other Comprehensive Income (Loss), Ending balance	$ 2.4				$ 3				2.4		3		$ 3.5
Reclassification out of Accumulated Other Comprehensive Income (Loss) [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Total									(104.4)		(92.3)
Reclassification out of Accumulated Other Comprehensive Income (Loss) [Member] | Cash Flow Hedges [Member] | Commodity Derivatives [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Revenue									(152.4)		(131.7)
Operating costs and expenses									10.7		1.3
Reclassification out of Accumulated Other Comprehensive Income (Loss) [Member] | Cash Flow Hedges [Member] | Interest Rate Derivatives [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Interest expense									$ 37.3		$ 38.1
[1]	Revenues are accounted for under ASC 606.
[2]	Revenues are accounted for under ASC 605.

Equity and Distributions, Nonco

Equity and Distributions, Noncontrolling Interests (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Breviloba LLC [Member]
Noncontrolling Interest
Noncontrolling Interest, Increase from Sale of Parent Equity Interest	$ 440.7
Pascagoula Gas Processing LLC [Member]
Noncontrolling Interest
Noncontrolling Interest, Increase from Sale of Parent Equity Interest	$ 36
Whitehorn Pipeline Company LLC [Member]
Noncontrolling Interest
Noncontrolling Interest, Increase from Sale of Parent Equity Interest		$ 189.6
Altus Midstream Processing LP [Member] | Breviloba LLC [Member]
Noncontrolling Interest
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners	33.00%
Third Coast Midstream, LLC [Member] | Pascagoula Gas Processing LLC [Member]
Noncontrolling Interest
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners	25.00%
Lavaca Pipe Line Company [Member] | Baymark Pipeline LLC [Member]
Noncontrolling Interest
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners	30.00%
Western Gas Partners, LP [Member] | Whitehorn Pipeline Company LLC [Member]
Noncontrolling Interest
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners	20.00%
Navigator Ethylene Terminals LLC [Member] | Enterprise Navigator Ethylene Terminal LLC [Member]
Noncontrolling Interest
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners	50.00%

Equity and Distributions, Distr

Equity and Distributions, Distributions (Details) - $ / shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Distributions to Partners [Abstract]
Number of days after quarter end to distribute available cash		45 days
Cash Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)		$ 1.7650
Quarterly increase in cash distribution per unit (in dollars per unit)		0.0025
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] | First Quarter 2018 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)			$ 0.4275
Record Date			Apr. 30, 2018
Payment Date			May 8, 2018
Cash Distribution [Member] | Second Quarter 2018 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)			$ 0.4300
Record Date			Jul. 31, 2018
Payment Date			Aug. 8, 2018
Cash Distribution [Member] | Third Quarter 2018 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)			$ 0.4325
Record Date			Oct. 31, 2018
Payment Date			Nov. 8, 2018
Cash Distribution [Member] | Fourth Quarter 2018 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)			$ 0.4350
Record Date			Jan. 31, 2019
Payment Date			Feb. 8, 2019
Cash Distribution [Member] | First Quarter 2019 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)		$ 0.4375
Record Date		Apr. 30, 2019
Payment Date		May 13, 2019
Cash Distribution [Member] | Second Quarter 2019 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)		$ 0.4400
Record Date		Jul. 31, 2019
Payment Date		Aug. 13, 2019
Cash Distribution [Member] | Third Quarter 2019 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)		$ 0.4425
Record Date		Oct. 31, 2019
Payment Date		Nov. 12, 2019
Cash Distribution [Member] | Fourth Quarter 2019 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)		$ 0.4450
Record Date		Jan. 31, 2020
Payment Date		Feb. 12, 2020
Cash Distribution [Member] | Forecast [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)	$ 1.8050
Forecasted rate of annual increase of distributions per unit	2.30%

Revenues, Revenues by Business

Revenues, Revenues by Business Segment and Revenue Type (Details) - USD ($) $ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2019

Sep. 30, 2019

Jun. 30, 2019

Mar. 31, 2019

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Revenue [Abstract]

Revenues

$ 8,005.3

$ 7,964.1

$ 8,276.3

$ 8,543.5

$ 9,182.3

$ 9,585.9

$ 8,467.5

$ 9,298.5

$ 32,789.2

[1]

$ 36,534.2

[1]

$ 29,241.5

[2]

Percentage increase in revenues due to addition of revenue stream for non-cash consideration

2.00%

Revenues [Member] | Vitol Holding B.V. [Member]

Revenue [Abstract]

Percent of revenues

10.10%

7.80%

11.20%

NGL Pipelines & Services [Member]

Revenue [Abstract]

Revenues

$ 13,470.7

[1]

$ 15,648.9

[1]

$ 12,468

[2]

NGL Pipelines & Services [Member] | Sales of NGLs and Related Products [Member]

Revenue [Abstract]

Revenues

10,934.3

[1]

12,920.9

[1]

10,521.3

[2]

NGL Pipelines & Services [Member] | Midstream Services [Member]

Revenue [Abstract]

Revenues

2,536.4

[1]

2,728

[1]

1,946.7

[2]

NGL Pipelines & Services [Member] | Midstream Services: Natural Gas Processing and Fractionation [Member]

Revenue [Abstract]

Revenues

1,069.9

[1]

1,341

[1]

719.1

[2]

NGL Pipelines & Services [Member] | Midstream Services: Transportation [Member]

Revenue [Abstract]

Revenues

1,054.3

[1]

1,007

[1]

891.7

[2]

NGL Pipelines & Services [Member] | Midstream Services: Storage and Terminals [Member]

Revenue [Abstract]

Revenues

412.2

[1]

380

[1]

335.9

[2]

Crude Oil Pipelines & Services [Member]

Revenue [Abstract]

Revenues

10,287.3

[1]

11,042.6

[1]

8,156.8

[2]

Crude Oil Pipelines & Services [Member] | Sales of Crude Oil [Member]

Revenue [Abstract]

Revenues

9,007.8

[1]

10,001.2

[1]

7,365.2

[2]

Crude Oil Pipelines & Services [Member] | Midstream Services [Member]

Revenue [Abstract]

Revenues

1,279.5

[1]

1,041.4

[1]

791.6

[2]

Crude Oil Pipelines & Services [Member] | Midstream Services: Transportation [Member]

Revenue [Abstract]

Revenues

801.8

[1]

676.5

[1]

473.9

[2]

Crude Oil Pipelines & Services [Member] | Midstream Services: Storage and Terminals [Member]

Revenue [Abstract]

Revenues

477.7

[1]

364.9

[1]

317.7

[2]

Natural Gas Pipelines & Services [Member]

Revenue [Abstract]

Revenues

3,169.4

[1]

3,454.4

[1]

3,145.6

[2]

Natural Gas Pipelines & Services [Member] | Sales of Natural Gas [Member]

Revenue [Abstract]

Revenues

2,075.4

[1]

2,411.7

[1]

2,238.5

[2]

Natural Gas Pipelines & Services [Member] | Midstream Services [Member]

Revenue [Abstract]

Revenues

1,094

[1]

1,042.7

[1]

907.1

[2]

Natural Gas Pipelines & Services [Member] | Midstream Services: Transportation [Member]

Revenue [Abstract]

Revenues

1,094

[1]

1,042.7

[1]

907.1

[2]

Petrochemical & Refined Products Services [Member]

Revenue [Abstract]

Revenues

5,861.8

[1]

6,388.3

[1]

5,471.1

[2]

Petrochemical & Refined Products Services [Member] | Sales of Petrochemicals and Refined Products [Member]

Revenue [Abstract]

Revenues

4,985.2

[1]

5,535.4

[1]

4,696.3

[2]

Petrochemical & Refined Products Services [Member] | Midstream Services [Member]

Revenue [Abstract]

Revenues

876.6

[1]

852.9

[1]

774.8

[2]

Petrochemical & Refined Products Services [Member] | Midstream Services: Fractionation and Isomerization [Member]

Revenue [Abstract]

Revenues

166.6

[1]

188.3

[1]

156.3

[2]

Petrochemical & Refined Products Services [Member] | Midstream Services: Transportation [Member]

Revenue [Abstract]

Revenues

539.4

[1]

481.8

[1]

430.7

[2]

Petrochemical & Refined Products Services [Member] | Midstream Services: Storage and Terminals [Member]

Revenue [Abstract]

Revenues

$ 170.6

[1]

$ 182.8

[1]

$ 187.8

[2]

[1]

Revenues are accounted for under ASC 606.

[2]

Revenues are accounted for under ASC 605.

Revenues, Unbilled Revenue and

Revenues, Unbilled Revenue and Deferred Revenue (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Contracts with Customers, Assets and Liabilities [Abstract]
Unbilled revenue	$ 17.6	$ 13.3	$ 0
Deferred revenue	314.9	291.2	$ 224.7
Other Current Assets [Member]
Contracts with Customers, Assets and Liabilities [Abstract]
Unbilled revenue (current amount)	17.6	13.3
Other Current Liabilities [Member]
Contracts with Customers, Assets and Liabilities [Abstract]
Deferred revenue (current amount)	117.9	80.9
Other Liabilities [Member]
Contracts with Customers, Assets and Liabilities [Abstract]
Deferred revenue (noncurrent)	$ 197	$ 210.3

Revenues, Significant Changes i

Revenues, Significant Changes in Unbilled Revenue (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018
Significant Changes in Unbilled Revenue [Roll Forward]
Balance at beginning of period		$ 13.3	$ 0
Unbilled revenue included in opening balance transferred to other accounts during period	[1]	(13.3)	0
Unbilled revenue recorded during period		340	321.7
Unbilled revenue recorded during period transferred to other accounts	[1]	(322.4)	(310.6)
Unbilled revenue recorded in connection with business combination		0	2.2
Other changes		0	0
Balance at end of period		$ 17.6	$ 13.3
[1]	Unbilled revenues are transferred to accounts receivable once we have an unconditional right to consideration from the customer.  Deferred revenues are recognized as revenue upon satisfaction of our performance obligation to the customer.

Revenues, Significant Changes_2

Revenues, Significant Changes in Deferred Revenue (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018
Significant Changes in Deferred Revenue [Roll Forward]
Balance at beginning of period		$ 291.2	$ 224.7
Deferred revenue included in opening balance transferred to other accounts during period	[1]	(126.4)	(90.8)
Deferred revenue recorded during period		539.8	432.5
Deferred revenue recorded during period transferred to other accounts	[1]	(384.8)	(274.8)
Deferred revenue recorded in connection with business combination		0	0
Other changes		(4.9)	(0.4)
Balance at end of period		$ 314.9	$ 291.2
[1]	Unbilled revenues are transferred to accounts receivable once we have an unconditional right to consideration from the customer.  Deferred revenues are recognized as revenue upon satisfaction of our performance obligation to the customer.

Revenues, Remaining Performance

Revenues, Remaining Performance Obligations (Details) $ in Millions	Dec. 31, 2019USD ($)
Remaining Performance Obligation to be Recognized in the Future [Abstract]
Remaining performance obligation	$ 29,789.5
Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Remaining Performance Obligation to be Recognized in the Future [Abstract]
Remaining performance obligation	$ 3,654.6
Expected timing of satisfaction, period	1 year
Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Remaining Performance Obligation to be Recognized in the Future [Abstract]
Remaining performance obligation	$ 3,363.9
Expected timing of satisfaction, period	1 year
Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Remaining Performance Obligation to be Recognized in the Future [Abstract]
Remaining performance obligation	$ 3,062.7
Expected timing of satisfaction, period	1 year
Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Remaining Performance Obligation to be Recognized in the Future [Abstract]
Remaining performance obligation	$ 2,857.8
Expected timing of satisfaction, period	1 year
Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Remaining Performance Obligation to be Recognized in the Future [Abstract]
Remaining performance obligation	$ 2,743.8
Expected timing of satisfaction, period	1 year
Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Remaining Performance Obligation to be Recognized in the Future [Abstract]
Remaining performance obligation	$ 14,106.7
Expected timing of satisfaction, period

Business Segments (Details)

Business Segments (Details)	12 Months Ended
	Dec. 31, 2019Segmentmi
Segment Reporting Information [Line Items]
Number of reportable segments | Segment	4
Number of miles of pipelines	50,000
NGL Pipelines and Services [Member]
Segment Reporting Information [Line Items]
Number of miles of pipelines	19,900
Crude Oil Pipelines & Services [Member]
Segment Reporting Information [Line Items]
Number of miles of pipelines	5,300
Natural Gas Pipelines & Services [Member]
Segment Reporting Information [Line Items]
Number of miles of pipelines	19,400
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	3,300

Business Segments, Gross Operat

Business Segments, Gross Operating Margin (Details) - USD ($) $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Business Segments [Abstract]
Operating income		$ 1,418	$ 1,474.2	$ 1,560.3	$ 1,626.2	$ 1,640.4	$ 1,643.3	$ 986.4	$ 1,138.5	$ 6,078.7	$ 5,408.6	$ 3,928.9
Adjustments to reconcile operating income to total gross operating margin (addition or subtraction indicated by sign):
Depreciation, amortization and accretion expense in operating costs and expenses										1,848.3	1,687	1,531.3
Asset impairment and related charges in operating costs and expenses										132.7	50.5	49.8
Net gains attributable to asset sales in operating costs and expenses										(5.7)	(28.7)	(10.7)
General and administrative costs										211.7	208.3	181.1
Non-refundable payments received from shippers attributable to make-up rights	[1]									47	21.5	24.1
Subsequent recognition of revenues attributable to make-up rights	[2]									(22.9)	(56.2)	(29.9)
Total segment gross operating margin										$ 8,289.8	$ 7,291	$ 5,674.6
[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, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Information by business segment [Abstract]
Gross operating margin										$ 8,289.8		$ 7,291		$ 5,674.6
Revenues from third parties										32,721.9		36,426.5		29,196.5
Revenues from related parties										67.3		107.7		45
Intersegment and intrasegment revenues										0		0		0
Total revenues		$ 8,005.3	$ 7,964.1	$ 8,276.3	$ 8,543.5	$ 9,182.3	$ 9,585.9	$ 8,467.5	$ 9,298.5	32,789.2	[1]	36,534.2	[1]	29,241.5	[2]
Equity in income (loss) of unconsolidated affiliates										563		480		426
Property, plant and equipment, net		41,603.4				38,737.6				41,603.4		38,737.6		35,620.4
Investments in unconsolidated affiliates		2,600.2				2,615.1				2,600.2		2,615.1		2,659.4
Intangible assets, net		3,449				3,608.4				3,449		3,608.4		3,690.3
Goodwill		5,745.2				5,745.2				5,745.2		5,745.2		5,745.2
Segment assets		53,397.8				50,706.3				53,397.8		50,706.3		47,715.3
NGL Pipelines and Services [Member]
Information by business segment [Abstract]
Total revenues										13,470.7	[1]	15,648.9	[1]	12,468	[2]
Equity in income (loss) of unconsolidated affiliates										114.5		117		73.4
Intangible assets, net		360.2				380.1				360.2		380.1
Crude Oil Pipelines & Services [Member]
Information by business segment [Abstract]
Total revenues										10,287.3	[1]	11,042.6	[1]	8,156.8	[2]
Equity in income (loss) of unconsolidated affiliates										449.2		365.4		358.4
Intangible assets, net		2,001.9				2,094.6				2,001.9		2,094.6
Natural Gas Pipelines & Services [Member]
Information by business segment [Abstract]
Total revenues										3,169.4	[1]	3,454.4	[1]	3,145.6	[2]
Equity in income (loss) of unconsolidated affiliates										6.3		6.8		3.8
Intangible assets, net		941.2				979.3				941.2		979.3
Petrochemical & Refined Products Services [Member]
Information by business segment [Abstract]
Total revenues										5,861.8	[1]	6,388.3	[1]	5,471.1	[2]
Equity in income (loss) of unconsolidated affiliates	[3]									(7)		(9.2)		(9.6)
Intangible assets, net		145.7				154.4				145.7		154.4
Reportable Business Segments [Member] | NGL Pipelines and Services [Member]
Information by business segment [Abstract]
Gross operating margin										4,069.8		3,830.7		3,258.3
Revenues from third parties										13,460.8		15,630.5		12,455.7
Revenues from related parties										9.9		18.4		12.3
Intersegment and intrasegment revenues										20,840.4		26,453.6		27,278.6
Total revenues										34,311.1		42,102.5		39,746.6
Equity in income (loss) of unconsolidated affiliates										114.5		117		73.4
Property, plant and equipment, net		16,652.1				14,845.4				16,652.1		14,845.4		13,831.2
Investments in unconsolidated affiliates		703.8				662				703.8		662		733.9
Intangible assets, net		360.2				380.1				360.2		380.1		322.3
Goodwill		2,651.7				2,651.7				2,651.7		2,651.7		2,651.7
Segment assets		20,367.8				18,539.2				20,367.8		18,539.2		17,539.1
Reportable Business Segments [Member] | Crude Oil Pipelines & Services [Member]
Information by business segment [Abstract]
Gross operating margin										2,087.8		1,511.3		987.2
Revenues from third parties										10,244.6		10,968.2		8,137.2
Revenues from related parties										42.7		74.4		19.6
Intersegment and intrasegment revenues										34,613		35,490.4		15,943
Total revenues										44,900.3		46,533		24,099.8
Equity in income (loss) of unconsolidated affiliates										449.2		365.4		358.4
Property, plant and equipment, net		6,324.4				5,847.7				6,324.4		5,847.7		5,208.4
Investments in unconsolidated affiliates		1,866.5				1,867.5				1,866.5		1,867.5		1,839.2
Intangible assets, net		2,001.9				2,094.6				2,001.9		2,094.6		2,186.5
Goodwill		1,841				1,841				1,841		1,841		1,841
Segment assets		12,033.8				11,650.8				12,033.8		11,650.8		11,075.1
Reportable Business Segments [Member] | Natural Gas Pipelines & Services [Member]
Information by business segment [Abstract]
Gross operating margin										1,062.6		891.2		714.5
Revenues from third parties										3,154.7		3,439.5		3,132.5
Revenues from related parties										14.7		14.9		13.1
Intersegment and intrasegment revenues										624.7		721.9		850.8
Total revenues										3,794.1		4,176.3		3,996.4
Equity in income (loss) of unconsolidated affiliates										6.3		6.8		3.8
Property, plant and equipment, net		8,432.5				8,303.8				8,432.5		8,303.8		8,375
Investments in unconsolidated affiliates		27.3				22.8				27.3		22.8		20.8
Intangible assets, net		941.2				979.3				941.2		979.3		1,018.4
Goodwill		296.3				296.3				296.3		296.3		296.3
Segment assets		9,697.3				9,602.2				9,697.3		9,602.2		9,710.5
Reportable Business Segments [Member] | Petrochemical & Refined Products Services [Member]
Information by business segment [Abstract]
Gross operating margin										1,069.6		1,057.8		714.6
Revenues from third parties										5,861.8		6,388.3		5,471.1
Revenues from related parties										0		0		0
Intersegment and intrasegment revenues										2,481.3		2,917.5		1,766.9
Total revenues										8,343.1		9,305.8		7,238
Equity in income (loss) of unconsolidated affiliates										(7)		(9.2)		(9.6)
Property, plant and equipment, net		7,553.2				6,213.9				7,553.2		6,213.9		3,507.7
Investments in unconsolidated affiliates		2.6				62.8				2.6		62.8		65.5
Intangible assets, net		145.7				154.4				145.7		154.4		163.1
Goodwill		956.2				956.2				956.2		956.2		956.2
Segment assets		8,657.7				7,387.3				8,657.7		7,387.3		4,692.5
Eliminations [Member]
Information by business segment [Abstract]
Revenues from third parties										0		0		0
Revenues from related parties										0		0		0
Intersegment and intrasegment revenues										(58,559.4)		(65,583.4)		(45,839.3)
Total revenues										(58,559.4)		(65,583.4)		(45,839.3)
Equity in income (loss) of unconsolidated affiliates										0		0		0
Adjustments [Member]
Information by business segment [Abstract]
Property, plant and equipment, net		2,641.2				3,526.8				2,641.2		3,526.8		4,698.1
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		$ 2,641.2				$ 3,526.8				$ 2,641.2		$ 3,526.8		$ 4,698.1
[1]	Revenues are accounted for under ASC 606.
[2]	Revenues are accounted for under ASC 605.
[3]	The losses recorded for this segment are primarily due to protection, maintenance and pipeline integrity costs of the idled Centennial Pipeline, which was purged and filled with nitrogen in 2013. Although we wrote off our investment in Centennial in 2019, we, as a 50% owner of Centennial, have a continuing obligation to fund the pipeline’s costs in its idled state.

Business Segments, Consolidated

Business Segments, Consolidated Revenues and Expenses (Details) - USD ($) $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Consolidated Revenues [Abstract]
Total consolidated revenues		$ 8,005.3	$ 7,964.1	$ 8,276.3	$ 8,543.5	$ 9,182.3	$ 9,585.9	$ 8,467.5	$ 9,298.5	$ 32,789.2	[1]	$ 36,534.2	[1]	$ 29,241.5	[2]
Operating costs and expenses:
Cost of sales	[3]									22,065.8		26,789.8		21,487
Other operating costs and expenses	[4]									3,020.7		2,898.7		2,500.1
Depreciation, amortization and accretion										1,848.3		1,687		1,531.3
Asset impairment and related charges										132.7		50.5		49.8
Net gains attributable to asset sales										(5.7)		(28.7)		(10.7)
General and administrative costs										211.7		208.3		181.1
Total costs and expenses										27,273.5		31,605.6		25,738.6
NGL Pipelines and Services [Member]
Consolidated Revenues [Abstract]
Total consolidated revenues										13,470.7	[1]	15,648.9	[1]	12,468	[2]
Crude Oil Pipelines & Services [Member]
Consolidated Revenues [Abstract]
Total consolidated revenues										10,287.3	[1]	11,042.6	[1]	8,156.8	[2]
Natural Gas Pipelines & Services [Member]
Consolidated Revenues [Abstract]
Total consolidated revenues										3,169.4	[1]	3,454.4	[1]	3,145.6	[2]
Petrochemical and Refined Products Services [Member]
Consolidated Revenues [Abstract]
Total consolidated revenues										$ 5,861.8	[1]	$ 6,388.3	[1]	$ 5,471.1	[2]
[1]	Revenues are accounted for under ASC 606.
[2]	Revenues are accounted for under ASC 605.
[3]	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.
[4]	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.

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, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
BASIC EARNINGS PER UNIT
Net income attributable to limited partners		$ 1,096.9	$ 1,019.2	$ 1,214.7	$ 1,260.5	$ 1,284.7	$ 1,313.2	$ 673.8	$ 900.7	$ 4,591.3	$ 4,172.4	$ 2,799.3
Earnings allocated to phantom unit awards	[1]									(27.7)	(21.5)	(15.9)
Net income available to common unitholders										$ 4,563.6	$ 4,150.9	$ 2,783.4
Basic weighted-average number of common units outstanding (in units)										2,188.6	2,176.5	2,145
Basic earnings per unit (in dollars per unit)		$ 0.50	$ 0.46	$ 0.55	$ 0.57	$ 0.59	$ 0.60	$ 0.31	$ 0.41	$ 2.09	$ 1.91	$ 1.30
DILUTED EARNINGS PER UNIT
Net income attributable to limited partners		$ 1,096.9	$ 1,019.2	$ 1,214.7	$ 1,260.5	$ 1,284.7	$ 1,313.2	$ 673.8	$ 900.7	$ 4,591.3	$ 4,172.4	$ 2,799.3
Diluted weighted-average number of units outstanding:
Distribution-bearing common units (in units)										2,188.6	2,176.5	2,145
Phantom units (in units)	[1]									13.1	10.5	9.3
Total (in units)										2,201.7	2,187	2,154.3
Diluted earnings per unit (in dollars per unit)		$ 0.50	$ 0.46	$ 0.55	$ 0.57	$ 0.59	$ 0.60	$ 0.31	$ 0.41	$ 2.09	$ 1.91	$ 1.30
[1]	Phantom units are considered participating securities for purposes of computing basic earnings per unit. See Note 13 for information regarding our phantom units.

Business Combinations (Details)

Business Combinations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Mar. 29, 2018
Business Combination
Investments in unconsolidated affiliates	$ 2,600.2	$ 2,615.1	$ 2,659.4
Gain on step acquisition of Delaware Processing	0	39.4	0
Cash used for business combinations, net of cash received	$ 0	150.6	198.7
Delaware Basin Gas Processing LLC [Member]
Business Combination
Business acquisition, description	Delaware Processing owns a cryogenic natural gas processing facility having a capacity of 150 million cubic feet per day (“MMcf/d”). The facility, which is located in Reeves County, Texas and entered service in August 2016, serves producers in the Delaware Basin in West Texas and southern New Mexico.
Remaining membership interest acquired				50.00%
Ownership interest				50.00%
Investments in unconsolidated affiliates				$ 107
Gain on step acquisition of Delaware Processing		39.4
Cash used for business combinations, net of cash received		$ 151
Azure Midstream Partners, L.P. [Member]
Business Combination
Business acquisition, description	The acquired business consists of approximately 750 miles of natural gas gathering pipelines and two natural gas processing facilities located in East Texas. These assets serve producers working in the Haynesville Shale and Bossier, Cotton Valley and Travis Peak formations.
Cash used for business combinations, net of cash received			$ 191.4

Business Combinations, Purchase

Business Combinations, Purchase Price Allocation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2019	Mar. 29, 2018	Dec. 31, 2017	Apr. 30, 2017
Liabilities assumed in business combination:
Goodwill	$ 5,745.2	$ 5,745.2		$ 5,745.2
Delaware Basin Gas Processing LLC [Member]
Consideration:
Purchase price for remaining 50% equity interest in Delaware Processing	154.5
Fair value of our 50% equity interest in Delaware Processing held before the acquisition	146.4
Total consideration	$ 300.9
Assets acquired in business combination:
Current assets, including cash			$ 10.8
Property, plant, and equipment			200
Total assets acquired			303.3
Liabilities assumed in business combination:
Current liabilities			(1.8)
Long-term liabilities			(0.6)
Total liabilities assumed			(2.4)
Total identifiable net assets			300.9
Goodwill			0
Description of Business Combination:
Cash acquired			3.9
Delaware Basin Gas Processing LLC [Member] | Contract-based intangibles [Member]
Assets acquired in business combination:
Intangible assets			82.6
Delaware Basin Gas Processing LLC [Member] | Customer relationship intangibles [Member]
Assets acquired in business combination:
Intangible assets			$ 9.9
Azure Midstream Partners, L.P. [Member]
Assets acquired in business combination:
Current assets, including cash					$ 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 identifiable net assets					$ 191.4

Equity-Based Awards (Details)

Equity-Based Awards (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Equity-based compensation expense [Abstract]
Total compensation expense	$ 143.9	$ 106.1	$ 99.7
Phantom Unit Awards [Member]
Equity-based compensation expense [Abstract]
Total compensation expense	132.2	99.7	92.8
Restricted Common Unit Awards [Member]
Equity-based compensation expense [Abstract]
Total compensation expense	0	0	0.5
Profits Interest Awards [Member]
Equity-based compensation expense [Abstract]
Total compensation expense	11.6	6.1	6
Liability-classified awards [Member]
Equity-based compensation expense [Abstract]
Total compensation expense	$ 0.1	$ 0.3	$ 0.4
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)	50,000,000
Remaining number of common units available to be issued as awards (in units)	17,106,486

Equity-Based Awards, Phantom Un

Equity-Based Awards, Phantom Unit Awards (Details) - USD ($) $ / shares in Units, $ in Millions		12 Months Ended
		Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Summary of awards activity, equity instruments other than options [Roll Forward]
Vested (in units)		(3,895,049)		(3,479,958)		(2,485,580)
Summary of awards activity, equity instruments other than options, additional disclosures [Abstract]
Cash payments made in connection with DERs		$ 22.1		$ 17.7		$ 15.1
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)		10,333,277		9,289,501		7,767,501
Granted (in units)		6,854,920	[1]	5,006,181	[2]	4,268,920	[3]
Vested (in units)		(3,895,049)		(3,479,958)		(2,490,081)
Forfeited (in units)		(318,464)		(482,447)		(256,839)
End of period (in units)		12,974,684		10,333,277		9,289,501
Common units issued in connection with the vesting of phantom unit awards, net (in units)		2,720,603		2,442,436		1,687,692
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]	$ 26.97		$ 27.65		$ 27.20
Granted weighted-average grant date fair value per unit (in dollars per unit)	[4]	27.75	[1]	26.82	[2]	28.83	[3]
Vested weighted-average grant date fair value per unit (in dollars per unit)	[4]	27.53		28.57		28.30
Forfeited weighted-average grant date fair value per unit (in dollars per unit)	[4]	27.21		26.88		27.60
Weighted-average grant date fair value per unit, at end of period (in dollars per unit)	[4]	$ 27.21		$ 26.97		$ 27.65
Summary of awards activity, equity instruments other than options, additional disclosures [Abstract]
Aggregate grant date fair value		$ 190.2		$ 134.3		$ 123.1
Estimated forfeiture rate		3.00%		3.20%		3.80%
Cash payments made in connection with DERs		$ 22.1		$ 17.7		$ 15.1
Total intrinsic value of phantom unit awards that vested during period		111.1		$ 90.7		$ 69.8
Unrecognized Compensation Expense [Abstract]
Unrecognized compensation cost		$ 138.1
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)		$ 26.32		$ 25.40		$ 24.55
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)		$ 29.29		$ 29.22		$ 28.87
Phantom Unit Awards [Member] | Enterprise [Member]
Unrecognized Compensation Expense [Abstract]
Unrecognized compensation cost		$ 113.3
[1]	The aggregate grant date fair value of phantom unit awards issued during 2019 was $190.2 million based on a grant date market price of EPD common units ranging from $26.32 to $29.29 per unit.  An estimated annual forfeiture rate of 3.0% was applied to these awards.
[2]	The aggregate grant date fair value of phantom unit awards issued during 2018 was $134.3 million based on a grant date market price of EPD common units ranging from $25.40 to $29.22 per unit.  An estimated annual forfeiture rate of 3.2% was applied to these awards.
[3]	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 EPD common units ranging from $24.55 to $28.87 per unit.  An estimated annual forfeiture rate of 3.8% 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, 2019USD ($)$ / 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	$ 0.3900
Estimated grant date fair value of profits interest awards	$ 12.9	[2]
Unrecognized Compensation Expense [Abstract]
Unrecognized compensation cost	$ 0.8	[3]
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	5.90%
Expected unit price volatility	15.00%
EPD PubCo I [Member] | Maximum [Member]
Estimated Grant Date Fair Value Assumptions [Abstract]
Risk-free interest rate	2.70%
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	$ 0.3900
Estimated grant date fair value of profits interest awards	$ 14.9	[2]
Unrecognized Compensation Expense [Abstract]
Unrecognized compensation cost	$ 4	[3]
Recognition period for total unrecognized compensation cost	1 year 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	5.90%
Expected unit price volatility	19.00%
EPD PubCo II [Member] | Maximum [Member]
Estimated Grant Date Fair Value Assumptions [Abstract]
Risk-free interest rate	3.00%
Expected distribution yield	7.00%
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	$ 0.3900
Estimated grant date fair value of profits interest awards	$ 5.8	[2]
Unrecognized Compensation Expense [Abstract]
Unrecognized compensation cost	$ 0.3	[3]
Recognition period for total unrecognized compensation cost	1 year 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%
EPD IV [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	6,400,000
Class A capital base	$ 172.9	[1]
Class A preference return | $ / shares	$ 0.4325
Estimated grant date fair value of profits interest awards	$ 26.7	[2]
Unrecognized Compensation Expense [Abstract]
Unrecognized compensation cost	$ 18.4	[3]
Recognition period for total unrecognized compensation cost	3 years 10 months 24 days
Estimated Grant Date Fair Value Assumptions [Abstract]
Expected life of award	5 years
EPD IV [Member] | Minimum [Member]
Estimated Grant Date Fair Value Assumptions [Abstract]
Risk-free interest rate	2.80%
Expected distribution yield	6.50%
Expected unit price volatility	27.00%
EPD IV [Member] | Maximum [Member]
Estimated Grant Date Fair Value Assumptions [Abstract]
Risk-free interest rate	2.80%
Expected distribution yield	6.50%
Expected unit price volatility	27.00%
EPCO Unit 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	1,600,000
Class A capital base	$ 43.2	[1]
Class A preference return | $ / shares	$ 0.4325
Estimated grant date fair value of profits interest awards	$ 6.6	[2]
Unrecognized Compensation Expense [Abstract]
Unrecognized compensation cost	$ 0.5	[3]
Recognition period for total unrecognized compensation cost	3 years 10 months 24 days
Estimated Grant Date Fair Value Assumptions [Abstract]
Expected life of award	5 years
EPCO Unit II [Member] | Minimum [Member]
Estimated Grant Date Fair Value Assumptions [Abstract]
Risk-free interest rate	1.60%
Expected distribution yield	6.30%
Expected unit price volatility	24.00%
EPCO Unit II [Member] | Maximum [Member]
Estimated Grant Date Fair Value Assumptions [Abstract]
Risk-free interest rate	2.80%
Expected distribution yield	6.80%
Expected unit price volatility	27.00%
[1]	Represents the fair market value of EPD common units contributed to each Employee Partnership at the applicable contribution date.
[2]	Represents the total grant date fair value of the profits interest awards awarded to the Class B limited partners of each Employee Partnership irrespective of how such costs will be allocated between us and EPCO and its privately held affiliates.
[3]	Represents our expected share of the unrecognized compensation cost at December 31, 2019. We expect to recognize our share of the unrecognized compensation cost for PubCo II, PrivCo I, EPD IV and EPCO II over a weighted-average period of 1.1 years, 1.1 years, 3.9 years and 3.9 years, respectively.  The Class B limited partner interests of PubCo I vested on February 22, 2020.

Derivative Instruments, Hedgi_3

Derivative Instruments, Hedging Activities and Fair Value Measurements (Details) bbl in Millions, $ in Millions, ft³ in Billions		12 Months Ended
		Dec. 31, 2019USD ($)Contractbblft³	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Derivative [Line Items]
Proceeds from the settlement of interest rate derivative instruments | $		$ 0	$ 22.1	$ 30.6
Gain on the sale of swaption | $		23.1	29.4
Carrying amount of hedged asset | $		31.7	50.2
Forward Starting Swaps [Member] | Derivatives in cash flow hedging relationships [Member]
Derivative [Line Items]
Notional Amount | $		$ 1,150
Average Rate Locked		2.16%
Life of associated future debt		30 years
Notional amount of settled derivative instruments | $			275	275
Proceeds from the settlement of interest rate derivative instruments | $			$ 22.1	$ 30.6
Forward Starting Swaps A [Member] | Derivatives in cash flow hedging relationships [Member]
Derivative [Line Items]
Number of Derivatives Outstanding | Contract	[1]	1
Notional Amount | $		$ 75
Average Rate Locked		2.39%
Forward Starting Swaps B [Member] | Derivatives in cash flow hedging relationships [Member]
Derivative [Line Items]
Number of Derivatives Outstanding | Contract	[1]	1
Notional Amount | $		$ 75
Average Rate Locked		2.41%
Forward Starting Swaps - September 2019 [Member] | Derivatives in cash flow hedging relationships [Member]
Derivative [Line Items]
Number of Derivatives Outstanding | Contract		10
Notional Amount | $		$ 1,000
Forward Starting Swap C [Member] | Derivatives in cash flow hedging relationships [Member]
Derivative [Line Items]
Number of Derivatives Outstanding | Contract	[2]	5
Notional Amount | $		$ 500
Average Rate Locked		2.12%
Forward Starting Swaps D [Member] | Derivatives in cash flow hedging relationships [Member]
Derivative [Line Items]
Number of Derivatives Outstanding | Contract	[2]	5
Notional Amount | $		$ 500
Average Rate Locked		2.13%
Designated as Hedging Instrument [Member] | Natural gas processing: Forecasted natural gas purchases for plant thermal reduction (PTR) [Member] | Derivatives in cash flow hedging relationships [Member]
Derivative [Line Items]
Derivative instruments, current volume | ft³	[3],[4]	3.9
Designated as Hedging Instrument [Member] | Natural gas processing: Forecasted sales of NGLs [Member] | Derivatives in cash flow hedging relationships [Member]
Derivative [Line Items]
Derivative instruments, current volume	[3],[4]	0.8
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	[3],[4]	0.6
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	[3],[4]	11.2
Derivative instruments, long-term volume	[3],[4]	0.1
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	[3],[4]	1.1
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	[3],[4]	3
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	[3],[4]	103.5
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	[3],[4]	128.1
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	[3],[4]	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	[3],[4]	0.2
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	[3],[4]	0.2
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	[3],[4]	15.3
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	[3],[4]	19.9
Designated as Hedging Instrument [Member] | Propylene marketing: Forecasted sales of NGLs for propylene marketing activities [Member] | Derivatives in cash flow hedging relationships [Member]
Derivative [Line Items]
Derivative instruments, current volume	[3],[4]	0.5
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	[3],[4],[5]	52.3
Derivative instruments, long-term volume | ft³	[3],[4],[5]	0.2
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	[3],[4],[5]	6.5
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	[3],[4],[5]	9.4
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	[3],[4],[5]	27.3
Derivative instruments, long-term volume	[3],[4],[5]	11
[1]	These swaps were entered into in May 2019.
[2]	These swaps were entered into in September 2019 as a result of the exercise of swaptions.
[3]	The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is January 2021, April 2020 and December 2022, respectively.
[4]	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.
[5]	Reflects the use of derivative instruments to manage risks associated with transportation, processing and storage assets.

Derivative Instruments, Hedgi_4

Derivative Instruments, Hedging Activities and Fair Value Measurements, Derivative Fair Value Amounts (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Interest rate derivatives [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	$ 13.5
Commodity derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	127.8	$ 161.9
Liability Derivatives	116.2	162.4
Derivatives designated as hedging instruments [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	116.5	144.1
Liability Derivatives	120.6	126.1
Derivatives designated as hedging instruments [Member] | Interest rate derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	0	0
Liability Derivatives	13.5	0
Derivatives designated as hedging instruments [Member] | Interest rate derivatives [Member] | Current assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	0	0
Derivatives designated as hedging instruments [Member] | Interest rate derivatives [Member] | Other assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	0	0
Derivatives designated as hedging instruments [Member] | Interest rate derivatives [Member] | Current liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	6.7	0
Derivatives designated as hedging instruments [Member] | Interest rate derivatives [Member] | Other liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	6.8	0
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	116.5	144.1
Liability Derivatives	107.1	126.1
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member] | Current assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	116.5	138.5
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member] | Other assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	0	5.6
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member] | Current liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	107.1	115
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member] | Other liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	0	11.1
Derivatives not designated as hedging instruments [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	11.3	17.8
Liability Derivatives	9.1	36.3
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	11.3	17.8
Liability Derivatives	9.1	36.3
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Current assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	10.7	15.9
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Other assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	0.6	1.9
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Current liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	8.6	33.2
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Other liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	$ 0.5	$ 3.1

Derivative Instruments, Hedgi_5

Derivative Instruments, Hedging Activities and Fair Value Measurements, Asset Balance Sheet Offsetting (Details) - Commodity Derivatives [Member] - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	$ 127.8	$ 161.9
Gross Amounts Offset in the Balance Sheet	0	0
Amounts of Assets Presented in the Balance Sheet	127.8	161.9
Financial Instruments	(115.3)	(158.6)
Cash Collateral Paid	(11)	0
Cash Collateral Received	0	0
Amounts That Would Have Been Presented On Net Basis	$ 1.5	$ 3.3

Derivative Instruments, Hedgi_6

Derivative Instruments, Hedging Activities and Fair Value Measurements, Liability Balance Sheet Offsetting (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Interest rate derivatives [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	$ 13.5
Gross Amounts Offset in the Balance Sheet	0
Amounts of Liabilities Presented in the Balance Sheet	13.5
Financial Instruments	0
Cash Collateral Paid	0
Amounts That Would Have Been Presented On Net Basis	13.5
Commodity Derivatives [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	116.2	$ 162.4
Gross Amounts Offset in the Balance Sheet	0	0
Amounts of Liabilities Presented in the Balance Sheet	116.2	162.4
Financial Instruments	(115.3)	(158.6)
Cash Collateral Paid	0	(2.3)
Amounts That Would Have Been Presented On Net Basis	$ 0.9	$ 1.5

Derivative Instruments, Hedgi_7

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, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gains (losses)		$ 67.7	$ (17.7)	$ (23)
Mark-to-market gains (losses) in interest expense		(94.9)	(0.1)	0.2
Total mark-to-market gains (losses)		(27.2)	(17.8)	(22.8)
NGL Pipelines & Services [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gains (losses)		(5.5)	18	(11.2)
Crude Oil Pipelines & Services [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gains (losses)		80.6	(44.1)	(4.8)
Natural Gas Pipelines & Services [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gains (losses)		(0.2)	6.7	(9.4)
Petrochemical & Refined Products Services [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gains (losses)		(7.2)	1.7	2.4
Derivatives in fair value hedging relationships [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Derivative		2.2	11.2	0.9
Gain (Loss) Recognized in Income on Hedged Item		6.9	(8.3)	27.8
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	1.3	(0.2)
Gain (Loss) Recognized in Income on Hedged Item		0	(1.4)	0.4
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		2.2	9.9	1.1
Gain (Loss) Recognized in Income on Hedged Item		6.9	(6.9)	27.4
Derivatives in cash flow hedging relationships [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Change in Value Recognized in Other Comprehensive Income (Loss) on Derivative		125.5	315.4	(44.2)
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income		104.4	92.3	(152.6)
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		81.4	22.2	(5.7)
Accumulated other comprehensive loss related to interest rate derivative instruments expected to be reclassified to earnings in interest expense over the next twelve months		(39.7)
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		(37.3)	(38.1)	(40.4)
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		55.7
Accumulated other comprehensive income (loss) related to commodity derivative instruments expected to be reclassified to revenue over the next twelve months		55.4
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	[1]	55.8	293	(33.7)
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income		152.4	131.7	(111.6)
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	[1]	(11.7)	0.2	(4.8)
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income		(10.7)	(1.3)	(0.6)
Derivatives not designated as hedging instruments [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Derivative		(5.1)	(454.7)	(42.6)
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		(94.9)	0	0
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized gains (losses)		24.2
Unrealized gains (losses)		65.6
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		102.2	(462.9)	(42.7)
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		$ (12.4)	$ 8.2	$ 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, Hedgi_8

Derivative Instruments, Hedging Activities and Fair Value Measurements, Recurring Fair Value Measurements (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Financial liabilities [Abstract]
Liquidity Option		$ 509.6		$ 390
Total gains (losses) included in:
Unrealized gain (loss) recognized as a component of net income related to financial assets and liabilities		(27.2)		(17.8)		$ (22.8)
Fair Value, Measurements, Recurring [Member]
Financial assets [Abstract]
Value before application of CME Rule 814		397.2		456.9
Impact of CME Rule 814		(269.4)		(295)
Total commodity derivatives		127.8		161.9
Financial assets		127.8		161.9
Financial liabilities [Abstract]
Liquidity Option		509.6		390
Interest rate derivatives		13.5
Commodity derivatives:
Value before application of CME Rule 814		362		398.1
Impact of CME Rule 814		(245.8)		(235.7)
Total commodity derivatives		116.2		162.4
Financial liabilities		639.3		552.4
Net value before application of CME Rule 814 to commodity hedging portfolio		35.2
Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Financial assets [Abstract]
Value before application of CME Rule 814		53.4		172.3
Impact of CME Rule 814		(47)		(134.8)
Total commodity derivatives		6.4		37.5
Financial assets		6.4		37.5
Financial liabilities [Abstract]
Liquidity Option		0		0
Interest rate derivatives		0
Commodity derivatives:
Value before application of CME Rule 814		88.1		85.5
Impact of CME Rule 814		(81.9)		(48.6)
Total commodity derivatives		6.2		36.9
Financial liabilities		6.2		36.9
Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Financial assets [Abstract]
Value before application of CME Rule 814		343.7		282.4
Impact of CME Rule 814		(222.4)		(159.3)
Total commodity derivatives		121.3		123.1
Financial assets		121.3		123.1
Financial liabilities [Abstract]
Liquidity Option		0		0
Interest rate derivatives		13.5
Commodity derivatives:
Value before application of CME Rule 814		273.6		291.2
Impact of CME Rule 814		(163.9)		(172.9)
Total commodity derivatives		109.7		118.3
Financial liabilities		123.2		118.3
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Financial assets [Abstract]
Value before application of CME Rule 814		0.1		2.2
Impact of CME Rule 814		0		(0.9)
Total commodity derivatives		0.1		1.3
Financial assets		0.1		1.3
Financial liabilities [Abstract]
Liquidity Option		509.6		390
Interest rate derivatives		0
Commodity derivatives:
Value before application of CME Rule 814		0.3		21.4
Impact of CME Rule 814		0		(14.2)
Total commodity derivatives		0.3		7.2
Financial liabilities		509.9		397.2
Reconciliation of changes in the fair value of Level 3 financial assets and liabilities [Roll Forward]
Financial liability balance, net, beginning of period		(395.9)	[1]	(332.7)
Total gains (losses) included in:
Transfers out of Level 3	[1]	7.6		(2.7)
Financial liability balance, net, end of period		(509.8)	[1]	(395.9)	[1]	$ (332.7)
Unrealized gain (loss) recognized as a component of net income related to financial assets and liabilities		0.2		(1.2)
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Other Comprehensive Income (Loss) [Member]
Total gains (losses) included in:
Other comprehensive income (loss)		(2.1)		(3.2)
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Revenue [Member]
Total gains (losses) included in:
Net income	[2]	3.7		0.7
Settlements	[2]	(3.5)		(1.9)
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Other Expense [Member]
Total gains (losses) included in:
Net income		$ (119.6)		$ (56.1)
[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, 2019 and 2018.
[2]	There were $0.2 million of unrealized gains and $1.2 million of unrealized losses included in these amounts for the years ended December 31, 2019 and 2018, respectively.

Derivative Instruments, Hedgi_9

Derivative Instruments, Hedging Activities and Fair Value Measurements, Level 3 Recurring Valuation Techniques (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)$ / bbl	Dec. 31, 2018USD ($)$ / gal$ / bbl
Asset commodity derivatives - Crude oil [Member] | Liability commodity derivatives - Crude oil [Member] | Level 3 [Member] | Measurement Input, Commodity Forward Price [Member] | Minimum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, forward commodity price (in dollars per unit) | $ / bbl	61.05	37.59
Asset commodity derivatives - Crude oil [Member] | Liability commodity derivatives - Crude oil [Member] | Level 3 [Member] | Measurement Input, Commodity Forward Price [Member] | Maximum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, forward commodity price (in dollars per unit) | $ / bbl	62.14	51.99
Asset Commodity derivatives - Ethane [Member] | Liability Commodity Derivatives - Ethane [Member] | Level 3 [Member] | Measurement Input, Commodity Forward Price [Member] | Minimum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, forward commodity price (in dollars per unit) | $ / gal		0.28
Asset Commodity derivatives - Ethane [Member] | Liability Commodity Derivatives - Ethane [Member] | Level 3 [Member] | Measurement Input, Commodity Forward Price [Member] | Maximum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, forward commodity price (in dollars per unit) | $ / gal		0.31
Asset commodity derivatives - Propane [Member] | Liability commodity derivatives - Propane [Member] | Level 3 [Member] | Measurement Input, Commodity Forward Price [Member] | Minimum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, forward commodity price (in dollars per unit) | $ / gal		0.61
Asset commodity derivatives - Propane [Member] | Liability commodity derivatives - Propane [Member] | Level 3 [Member] | Measurement Input, Commodity Forward Price [Member] | Maximum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, forward commodity price (in dollars per unit) | $ / gal		0.66
Asset commodity derivatives - Normal butane [Member] | Liability commodity derivatives - Normal butane [Member] | Level 3 [Member] | Measurement Input, Commodity Forward Price [Member] | Minimum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, forward commodity price (in dollars per unit) | $ / gal		0.66
Asset commodity derivatives - Normal butane [Member] | Liability commodity derivatives - Normal butane [Member] | Level 3 [Member] | Measurement Input, Commodity Forward Price [Member] | Maximum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, forward commodity price (in dollars per unit) | $ / gal		0.72
Asset commodity derivatives - Natural gasoline [Member] | Liability commodity derivatives - Natural gasoline [Member] | Level 3 [Member] | Measurement Input, Commodity Forward Price [Member] | Minimum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, forward commodity price (in dollars per unit) | $ / gal		0.99
Asset commodity derivatives - Natural gasoline [Member] | Liability commodity derivatives - Natural gasoline [Member] | Level 3 [Member] | Measurement Input, Commodity Forward Price [Member] | Maximum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, forward commodity price (in dollars per unit) | $ / gal		1.01
Fair Value, Measurements, Recurring [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Commodity asset derivatives	$ 127.8	$ 161.9
Commodity liability derivatives	116.2	162.4
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Commodity asset derivatives	0.1	1.3
Commodity liability derivatives	0.3	7.2
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Valuation Technique, Discounted Cash Flow [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Commodity asset derivatives	0.1	1.3
Commodity liability derivatives	0.3	7.2
Fair Value, Measurements, Recurring [Member] | Liability commodity derivatives - Crude oil [Member] | Level 3 [Member] | Valuation Technique, Discounted Cash Flow [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Commodity liability derivatives	0.3	0.8
Fair Value, Measurements, Recurring [Member] | Liability Commodity Derivatives - Ethane [Member] | Level 3 [Member] | Valuation Technique, Discounted Cash Flow [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Commodity liability derivatives		0.6
Fair Value, Measurements, Recurring [Member] | Liability commodity derivatives - Normal butane [Member] | Level 3 [Member] | Valuation Technique, Discounted Cash Flow [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Commodity liability derivatives		0.7
Fair Value, Measurements, Recurring [Member] | Liability commodity derivatives - Natural gasoline [Member] | Level 3 [Member] | Valuation Technique, Discounted Cash Flow [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Commodity liability derivatives		4.1
Fair Value, Measurements, Recurring [Member] | Liability commodity derivatives - Propane [Member] | Level 3 [Member] | Valuation Technique, Discounted Cash Flow [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Commodity liability derivatives		1
Fair Value, Measurements, Recurring [Member] | Asset commodity derivatives - Crude oil [Member] | Level 3 [Member] | Valuation Technique, Discounted Cash Flow [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Commodity asset derivatives	$ 0.1	0.9
Fair Value, Measurements, Recurring [Member] | Asset Commodity derivatives - Ethane [Member] | Level 3 [Member] | Valuation Technique, Discounted Cash Flow [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Commodity asset derivatives		0.4
Fair Value, Measurements, Recurring [Member] | Asset commodity derivatives - Propane [Member] | Level 3 [Member] | Valuation Technique, Discounted Cash Flow [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Commodity asset derivatives		0
Fair Value, Measurements, Recurring [Member] | Asset commodity derivatives - Normal butane [Member] | Level 3 [Member] | Valuation Technique, Discounted Cash Flow [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Commodity asset derivatives		0
Fair Value, Measurements, Recurring [Member] | Asset commodity derivatives - Natural gasoline [Member] | Level 3 [Member] | Valuation Technique, Discounted Cash Flow [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Commodity asset derivatives		$ 0

Derivative Instruments, Hedg_10

Derivative Instruments, Hedging Activities and Fair Value Measurements, Nonrecurring Fair Value Measurements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Asset Impairment Charges [Abstract]
Asset impairment and related charges	$ 132.8	$ 50.5	$ 49.8
Impairment of other current assets	5.3	3.7	12
Impairment of long-lived assets disposed of other than by sale	50.6	43.7	16.7
Impairment of long-lived assets held and used	0.5	3.1	15.4
Impairment of long-lived assets held for sale			2.5
Impairment of long-lived assets disposed of by sale			3.2
Impairment of long-lived assets	51.1	46.8	37.8
Non-cash asset impairment charge of unconsolidated affiliate	76.4
Centennial Pipeline LLC [Member]
Asset Impairment Charges [Abstract]
Non-cash asset impairment charge of unconsolidated affiliate	76.4
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
Fair Value, Measurements, Nonrecurring [Member] | Long-lived Assets Held and Used [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value	0.3	0	1.5
Fair Value, Measurements, Nonrecurring [Member] | Long-lived Assets Held For Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value			2.5
Fair Value, Measurements, Nonrecurring [Member] | Long-lived Assets Disposed of By Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value			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	0	0
Fair Value, Measurements, Nonrecurring [Member] | Level 1 [Member] | Long-lived Assets Held For Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value			0
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
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	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
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
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
Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Long-lived Assets Held and Used [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value	$ 0.3	$ 0	1.5
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
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

Derivative Instruments, Hedg_11

Derivative Instruments, Hedging Activities and Fair Value Measurements, Other Fair Value Measurements (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Carrying Value [Member]
Financial Liabilities: [Abstract]
Fixed-rate debt obligations	$ 27,150	$ 26,150
Level 2 [Member] | Fair Value [Member]
Financial Liabilities: [Abstract]
Fixed-rate debt obligations	$ 30,370	$ 25,970

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenues - related parties:
Total revenue - related parties	$ 67.3	$ 107.7	$ 45
Costs and expenses - related parties:
Operating costs and expenses	1,412	1,406.1	1,112.8
General and administrative expenses	136.4	130.9	121.5
Total costs and expenses - related parties	1,548.4	1,537	1,234.3
Accounts receivable - related parties:
Total accounts receivable - related parties	2.5	3.5
Accounts payable - related parties:
Total accounts payable - related parties	162.3	140.2
EPCO and its privately held affiliates [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	1,145.3	1,089.6	1,010.9
Accounts payable - related parties:
Total accounts payable - related parties	143.7	116.3
Distributions:
Total cash distributions	$ 1,190	1,160	1,120
Relationship with Affiliates [Abstract]
Number of Units (in units)	700,783,776
Percentage of Total Units Outstanding	32.00%
Enterprise common units pledged as security (in units)	108,222,618
EPCO and its privately held affiliates [Member] | Distribution Reinvestment Plan [Member]
Relationship with Affiliates [Abstract]
Gross proceeds from the sale of common units	$ 29	213	100
EPCO and its privately held affiliates [Member] | Administrative Services Agreement [Member]
Costs and expenses - related parties:
Operating costs and expenses	1,000.2	948.8	882.1
General and administrative expenses	127.6	124.2	110.4
Total costs and expenses - related parties	1,127.8	1,073	992.5
EPCO and its privately held affiliates [Member] | Related Party Operating Leases [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	14.9	13.9	15.8
Unconsolidated affiliates [Member]
Revenues - related parties:
Total revenue - related parties	67.3	107.7	45
Costs and expenses - related parties:
Total costs and expenses - related parties	403.1	447.4	223.4
Accounts receivable - related parties:
Total accounts receivable - related parties	2.5	3.5
Accounts payable - related parties:
Total accounts payable - related parties	18.6	23.9
Unconsolidated affiliates [Member] | Seaway Crude Holdings LLC [Member]
Revenues - related parties:
Total revenue - related parties	42.7	74.4	19.6
Costs and expenses - related parties:
Total costs and expenses - related parties	194.5	163.2	98.8
Unconsolidated affiliates [Member] | Venice Energy Service Company, L.L.C. [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	89.2	157.9
Unconsolidated affiliates [Member] | K/D/S Promix, L.L.C. [Member]
Revenues - related parties:
Total revenue - related parties	9.1	9.5	7.8
Costs and expenses - related parties:
Total costs and expenses - related parties	34.8	31.9	27.8
Unconsolidated affiliates [Member] | Texas Express Pipeline LLC [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	33.5	57.6	29.5
Unconsolidated affiliates [Member] | Eagle Ford Pipeline LLC [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	36	18.5	42.8
Unconsolidated affiliates [Member] | Management/Operator Fees [Member] | Other investments in unconsolidated subsidiaries [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	$ (9.9)	$ (11.6)	$ (10.6)

Provision for Income Taxes (Det

Provision for Income Taxes (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Provision for Income Taxes [Abstract]
Maximum percent of qualifying income for publicly traded partnerships to be treated as corporations		90.00%
Current portion of income tax provision (benefit):
Federal		$ (1.3)	$ 5.3	$ 0.1
State		25.7	33.1	18.5
Foreign		1.2	0.5	1
Total current portion		25.6	38.9	19.6
Deferred portion of income tax provision (benefit):
Federal		1.6	(0.3)	(1.8)
State		18.5	21.7	7.9
Foreign		(0.1)	0	0
Total deferred portion		20	21.4	6.1
Total provision for income taxes		45.6	60.3	25.7
Reconciliation of the provision for (benefit from) income taxes [Abstract]
Pre-Tax Net Book Income ("NBI")		4,732.7	4,298.8	2,881.3
Texas Margin Tax	[1]	44.2	54.8	26.4
State income taxes (net of federal benefit)		0.5	0.2	0.5
Federal income taxes computed by applying the federal statutory rate to NBI of corporate entities		0.9	2.1	0.1
Other permanent differences		0	3.2	(1.3)
Total provision for income taxes		$ 45.6	$ 60.3	$ 25.7
Effective income tax rate		1.00%	1.40%	0.90%
Deferred tax liabilities:
Attributable to property, plant and equipment		$ 100.2	$ 80.8
Attributable to investments in partnerships		3.3	2.3
Total deferred tax liabilities		103.5	83.1
Less: Deferred tax assets:
Net operating loss carryovers	[2]	0.1	0.1
Temporary differences related to Texas Margin Tax		3	2.6
Total deferred tax assets		3.1	2.7
Total net deferred tax liabilities		$ 100.4	$ 80.4
[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.
[2]	These losses expire in various years between 2020 and 2037 and are subject to limitations on their utilization.

Commitments and Contingencies_2

Commitments and Contingencies (Details) bbl in Millions, $ in Millions, BTU in Trillions	12 Months Ended
	Dec. 31, 2019USD ($)BTUbbl	Dec. 31, 2014	Dec. 31, 2018USD ($)
Redelivery commitments:
Redelivery commitments of natural gas | BTU	8.9
Redelivery commitments of crude oil | bbl	20.4
Redelivery commitments of NGL and petrochemical products | bbl	38.1
Operating lease obligations:
Renewal option years for certain leases	20 years
Liabilities, Other than Long-term Debt, Noncurrent [Abstract]
Noncurrent portion of AROs	$ 126.9		$ 121.4
Deferred revenues - non-current portion	197		210.3
Liquidity Option liability	509.6		390
Lease liability - non-current portion	171.6		0
Derivative liabilities	7.3		14.2
Other	20		15.7
Total	1,032.4		751.6
Junior Subordinated Note [Member]
Debt Instrument [Line Items]
Debt obligations	$ 2,650
Minimum [Member]
Operating lease obligations:
Term of material lease agreements	5 years
Maximum [Member]
Operating lease obligations:
Term of material lease agreements	30 years
Litigation matters [Member]
Loss Contingencies [Line Items]
Litigation accruals on an undiscounted basis	$ 0.2		$ 0.5
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%
Positive Outcome of Litigation [Member]
Gain Contingencies [Line Items]
Counterclaim settlement awarded	$ 0.8

Commitments and Contingencies,

Commitments and Contingencies, Contractual Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Scheduled maturities of debt obligations [Abstract]
2020	$ 1,982
2021	1,325
2022	1,400
2023	1,250
2024	850
Thereafter	21,071.4
Total	27,878.4	$ 26,420.6
Estimated cash interest payments [Abstract]
2020	1,224.7
2021	1,154
2022	1,101.2
2023	1,061.1
2024	1,023
Thereafter	20,700.5
Total	26,264.5
Operating lease obligations [Abstract]
2020	45.2
2021	40.1
2022	28.6
2023	20.2
2024	15.7
Thereafter	121.4
Total	271.2
Natural Gas [Member]
Estimated payment obligations:
2020	345.4
2021	264.8
2022	0
2023	0
2024	0
Thereafter	0
Total	610.2
NGLs [Member]
Estimated payment obligations:
2020	844
2021	911.1
2022	627.5
2023	548.1
2024	513.5
Thereafter	2,090.5
Total	5,534.7
Crude Oil [Member]
Estimated payment obligations:
2020	1,436.9
2021	1,677.2
2022	1,659.8
2023	1,532.1
2024	1,536.3
Thereafter	6,183.2
Total	14,025.5
Petrochemicals And Refined Products [Member]
Estimated payment obligations:
2020	164.1
2021	77.2
2022	48.9
2023	48.9
2024	44.9
Thereafter	0
Total	384
Estimated Payment Obligations Other [Member]
Estimated payment obligations:
2020	7.6
2021	4.8
2022	2.8
2023	2.9
2024	1.5
Thereafter	0
Total	19.6
Service Payment Commitments [Member]
Estimated payment obligations:
2020	66.6
2021	59.7
2022	57.7
2023	43.3
2024	14.5
Thereafter	93.9
Total	335.7
Capital Expenditure Commitments [Member]
Estimated payment obligations:
2020	45.8
2021	0
2022	0
2023	0
2024	0
Thereafter	0
Total	45.8
EFS Midstream Contract with Producers [Member]
Contractual obligation [Line Items]
Contractual obligation	270
Capital expenditures to date	$ 151
Contract term	10 years

Commitments and Contingencies_3

Commitments and Contingencies, Operating Leases (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018
Operating Leases [Abstract]
ROU asset carrying value	[1]	$ 210.2
Lease liability carrying value	[2]	212
Lease liability, current		$ 40.4
Lease liability, current, Consolidated Balance Sheet line item		us-gaap:OtherLiabilitiesCurrent
Lease liability, noncurrent		$ 171.6	$ 0
Lease liability, noncurrent, Consolidated Balance Sheet line item		us-gaap:OtherLiabilitiesNoncurrent
Cash payments for operating lease liabilities		$ 48.1
Storage and Pipeline Facilities [Member]
Operating Leases [Abstract]
ROU asset carrying value	[1]	137.9
Lease liability carrying value	[2]	$ 138.6
Weighted-average remaining term		16 years
Weighted-average discount rate	[3]	4.30%
Transportation Equipment [Member]
Operating Leases [Abstract]
ROU asset carrying value	[1]	$ 49.9
Lease liability carrying value	[2]	$ 52.4
Weighted-average remaining term		3 years
Weighted-average discount rate	[3]	3.50%
Office Building and Warehouse Space [Member]
Operating Leases [Abstract]
ROU asset carrying value	[1]	$ 22.4
Lease liability carrying value	[2]	$ 21
Weighted-average remaining term		2 years
Weighted-average discount rate	[3]	3.40%
[1]	ROU asset amounts are a component of “Other assets” on our consolidated balance sheet.
[2]	At December 31, 2019, lease liabilities of $40.4 million and $171.6 million were included within “ Other current liabilities Other liabilities
[3]	The discount rate for each category of assets represents the weighted average of either (i) the implicit rate applicable to the underlying leases (where determinable) or (ii) our incremental borrowing rate adjusted for collateralization (if the implicit rate is not determinable).  In general, the discount rates are based on either (i) information available at the lease commencement date or (ii) January 1, 2019 for leases existing at the adoption date for ASC 842.

Commitments and Contingencies_4

Commitments and Contingencies, Consolidated Lease Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Consolidated Lease Expense [Abstract]
Non-cash lease expense (amortization of ROU assets)	$ 42.8	$ 0	$ 0
Related accretion expense on lease liability balances	9
Total fixed lease expense	51.8
Variable lease expense	6.2
Subtotal operating lease expense	58
Short-term operating leases	48.6
Total operating lease expense	$ 106.6	$ 86.4	$ 103.6

Commitments and Contingencies_5

Commitments and Contingencies, Additional Lease Information (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Jan. 02, 2019	Dec. 31, 2018
Lease Accounting Standard [Abstract]
Right-of-use assets	[1]	$ 210.2
Lease liabilities	[2]	212
Undiscounted total			$ 314.4
Operating lease income		$ 14.4
ASC 842 [Member]
Lease Accounting Standard [Abstract]
Right-of-use assets				$ 246.1
Lease liabilities				$ 246.1
[1]	ROU asset amounts are a component of “Other assets” on our consolidated balance sheet.
[2]	At December 31, 2019, lease liabilities of $40.4 million and $171.6 million were included within “ Other current liabilities Other liabilities

Commitments and Contingencies_6

Commitments and Contingencies, Liquidity Option Agreement (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)shares	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2014
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Limited partner interests of Oiltanking acquired				65.90%
Number of units held by limited partner (in units) | shares	54,807,352
Deferred tax liability	$ 103.5	$ 83.1
Liquidity Option Agreement [Abstract]
Change in fair value of Liquidity Option Agreement	$ 119.6	56.1	$ 64.3
Percentage of capital stock agreed to purchase under liquidity option agreement	100.00%
Liquidity Option exercise period	90 days
Level 3 [Member] | Liquidity Option Agreement [Member]
Liquidity Option Agreement [Abstract]
Derivative Liability	$ 509.6	$ 390
Level 3 [Member] | Liquidity Option Agreement [Member] | Minimum [Member]
Liquidity Option Agreement [Abstract]
Fair value inputs, Estimated growth rates in Enterprise earnings before interest, taxes, depreciation and amortization	0.70%
Fair value inputs, OTA ownership interest in Enterprise common units	2.30%
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	2.20%
Fair value inputs, OTA ownership interest in Enterprise common units	2.50%
Level 3 [Member] | Liquidity Option Agreement [Member] | Measurement Input, Aggregate Tax Rate [Member]
Liquidity Option Agreement [Abstract]
Derivative Liability, Measurement Input	0.228
Level 3 [Member] | Liquidity Option Agreement [Member] | Measurement Input, Discount Rate [Member]
Liquidity Option Agreement [Abstract]
Derivative Liability, Measurement Input	0.057

Significant Risks and Uncerta_2

Significant Risks and Uncertainties (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
Insurance Matters [Abstract]
Insurance deductible per incident	$ 30
Minimum business interruption period	60 days
Named windstorm insurance coverage	$ 200

Supplemental Cash Flow Inform_3

Supplemental Cash Flow Information (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Decrease (increase) in:
Accounts receivable - trade		$ (1,248.8)	$ 730.2	$ (1,076.2)
Accounts receivable - related parties		0.9	(2.3)	(0.7)
Inventories		(558)	121.4	194.6
Prepaid and other current assets		(69.6)	214.4	226
Other assets		(63.5)	(9.7)	(111)
Increase (decrease) in:
Accounts payable - trade		(43.9)	18.3	66.6
Accounts payable - related parties		67.8	51.4	56
Accrued product payables		1,447.8	(1,132)	952.3
Accrued interest		36.1	37.6	17.3
Other current liabilities		58.1	(70.9)	(291.4)
Other liabilities		(84.3)	57.8	(1.3)
Net effect of changes in operating accounts		(457.4)	16.2	32.2
Cash payments for interest, net of $143.8, $147.9 and $192.1 capitalized in 2019, 2018 and 2017, respectively		1,080.3	1,017.9	912.1
Capitalized interest	[1]	143.8	147.9	192.1
Cash payments for federal and state income taxes		23.6	15.5	20.9
Liability for construction in progress expenditures		432	567.6	373
Contributions in aid of construction costs				46.1
Sale of Assets:
Proceeds from asset sales		20.6	161.2	40.1
Net gains attributable to asset sales		5.7	28.7	10.7
Red River System [Member]
Sale of Assets:
Proceeds from asset sales		0	134.9	0
Net gains attributable to asset sales		0	20.6	0
Other Disposal of Assets [Member]
Sale of Assets:
Proceeds from asset sales		20.6	26.3	40.1
Net gains attributable to asset sales		$ 5.7	$ 8.1	$ 10.7
[1]	Capitalized interest is a component of “Interest expense” as presented on our Statements of Consolidated Operations.

Quarterly Financial Informati_3

Quarterly Financial Information (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Quarterly Financial Information (Unaudited) [Abstract]
Revenues	$ 8,005.3	$ 7,964.1	$ 8,276.3	$ 8,543.5	$ 9,182.3	$ 9,585.9	$ 8,467.5	$ 9,298.5	$ 32,789.2	[1]	$ 36,534.2	[1]	$ 29,241.5	[2]
Operating income	1,418	1,474.2	1,560.3	1,626.2	1,640.4	1,643.3	986.4	1,138.5	6,078.7		5,408.6		3,928.9
Net income	1,125.4	1,044.8	1,236.5	1,280.4	1,305.2	1,334.6	687.2	911.5	4,687.1		4,238.5		2,855.6
Net income attributable to limited partners	$ 1,096.9	$ 1,019.2	$ 1,214.7	$ 1,260.5	$ 1,284.7	$ 1,313.2	$ 673.8	$ 900.7	$ 4,591.3		$ 4,172.4		$ 2,799.3
Earnings per unit:
Basic earnings per unit (in dollars per unit)	$ 0.50	$ 0.46	$ 0.55	$ 0.57	$ 0.59	$ 0.60	$ 0.31	$ 0.41	$ 2.09		$ 1.91		$ 1.30
Diluted earnings per unit (in dollars per unit)	$ 0.50	$ 0.46	$ 0.55	$ 0.57	$ 0.59	$ 0.60	$ 0.31	$ 0.41	$ 2.09		$ 1.91		$ 1.30
[1]	Revenues are accounted for under ASC 606.
[2]	Revenues are accounted for under ASC 605.

Condensed Consolidating Finan_3

Condensed Consolidating Financial Information, Balance Sheets (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents and restricted cash	$ 410	$ 410.1	$ 70.3	$ 417.6
Accounts receivable - trade, net	4,873.6	3,659.1
Accounts receivable - related parties	2.5	3.5
Inventories	2,091.4	1,522.1
Derivative assets	127.2	154.4
Prepaid and other current assets	358.2	311.5
Total current assets	7,862.9	6,060.7
Property, plant and equipment, net	41,603.4	38,737.6	35,620.4
Investments in unconsolidated affiliates	2,600.2	2,615.1	2,659.4
Intangible assets, net	3,449	3,608.4	3,690.3
Goodwill	5,745.2	5,745.2	5,745.2
Other assets	472.5	202.8
Total assets	61,733.2	56,969.8
Current liabilities:
Current maturities of debt	1,981.9	1,500.1
Accounts payable - trade	1,004.5	1,102.8
Accounts payable - related parties	162.3	140.2
Accrued product payables	4,915.7	3,475.8
Accrued interest	431.7	395.6
Derivative liabilities	122.4	148.2
Other current liabilities	511.2	404.8
Total current liabilities	9,129.7	7,167.5
Long-term debt	25,643.2	24,678.1
Deferred tax liabilities	100.4	80.4
Other long-term liabilities	1,032.4	751.6
Commitments and contingencies
Equity:
Partners' and other owners' equity	24,764	23,853.5
Noncontrolling interests	1,063.5	438.7
Total equity	25,827.5	24,292.2	22,772.4	22,266
Total liabilities and equity	61,733.2	56,969.8
Eliminations and Adjustments [Member]
Current assets:
Cash and cash equivalents and restricted cash	0	0	0	0
Accounts receivable - trade, net	0	0
Accounts receivable - related parties	(6.9)	(32.7)
Inventories	0	0
Derivative assets	0	0
Prepaid and other current assets	0	0.6
Total current assets	(6.9)	(32.1)
Property, plant and equipment, net	0	0
Investments in unconsolidated affiliates	(25,279.3)	(24,273.6)
Intangible assets, net	0	0
Goodwill	0	0
Other assets	0	0
Total assets	(25,286.2)	(24,305.7)
Current liabilities:
Current maturities of debt	0	0
Accounts payable - trade	0	0
Accounts payable - related parties	(6.9)	(32.6)
Accrued product payables	0	0
Accrued interest	0	0
Derivative liabilities	0	0
Other current liabilities	(0.2)	0
Total current liabilities	(7.1)	(32.6)
Long-term debt	0	0
Deferred tax liabilities	3.4	2.3
Other long-term liabilities	0	0
Commitments and contingencies
Equity:
Partners' and other owners' equity	(25,247.1)	(24,247.4)
Noncontrolling interests	(35.4)	(28)
Total equity	(25,282.5)	(24,275.4)
Total liabilities and equity	(25,286.2)	(24,305.7)
Subsidiary Issuer (EPO) [Member]
Current assets:
Cash and cash equivalents and restricted cash	109.2	393.4	65.2	366.2
Accounts receivable - trade, net	1,471.1	1,303.1
Accounts receivable - related parties	233.1	141.8
Inventories	1,351.3	889.3
Derivative assets	115.2	105
Prepaid and other current assets	221	166
Total current assets	3,500.9	2,998.6
Property, plant and equipment, net	6,413.3	6,112.7
Investments in unconsolidated affiliates	45,514	43,962.6
Intangible assets, net	636.7	659.2
Goodwill	459.5	459.5
Other assets	404.9	292.1
Total assets	56,929.3	54,484.7
Current liabilities:
Current maturities of debt	1,981.9	1,500
Accounts payable - trade	301.4	404
Accounts payable - related parties	977.5	1,557.3
Accrued product payables	1,895.4	1,574.7
Accrued interest	431.6	395.5
Derivative liabilities	114.2	86.2
Other current liabilities	120.5	87.9
Total current liabilities	5,822.5	5,605.6
Long-term debt	25,628.6	24,663.4
Deferred tax liabilities	22.2	17
Other long-term liabilities	161.2	65.2
Commitments and contingencies
Equity:
Partners' and other owners' equity	25,294.8	24,133.5
Noncontrolling interests	0	0
Total equity	25,294.8	24,133.5
Total liabilities and equity	56,929.3	54,484.7
Other Subsidiaries (Non-guarantor) [Member]
Current assets:
Cash and cash equivalents and restricted cash	315.8	50.3	31.5	58.9
Accounts receivable - trade, net	3,403.8	2,356.8
Accounts receivable - related parties	799.9	1,423.7
Inventories	740.4	633.2
Derivative assets	12	49.1
Prepaid and other current assets	183.5	155.1
Total current assets	5,455.4	4,668.2
Property, plant and equipment, net	35,233.6	32,628.7
Investments in unconsolidated affiliates	4,165.7	4,170.6
Intangible assets, net	2,852.3	2,963
Goodwill	5,285.7	5,285.7
Other assets	288.5	131.9
Total assets	53,281.2	49,848.1
Current liabilities:
Current maturities of debt	0	0.1
Accounts payable - trade	717.7	734.3
Accounts payable - related parties	222.3	127.5
Accrued product payables	3,021.9	1,902.3
Accrued interest	0.9	0.9
Derivative liabilities	8.2	61.7
Other current liabilities	438.2	326.3
Total current liabilities	4,409.2	3,153.1
Long-term debt	14.6	14.7
Deferred tax liabilities	75.6	62
Other long-term liabilities	608.9	518.4
Commitments and contingencies
Equity:
Partners' and other owners' equity	48,107.6	46,031.8
Noncontrolling interests	65.3	68.1
Total equity	48,172.9	46,099.9
Total liabilities and equity	53,281.2	49,848.1
Consolidated EPO and Subsidiaries [Member]
Current assets:
Cash and cash equivalents and restricted cash	409.9	410.1	70.3	417.6
Accounts receivable - trade, net	4,873.6	3,659.1
Accounts receivable - related parties	9.4	35.4
Inventories	2,091.4	1,522.1
Derivative assets	127.2	154.4
Prepaid and other current assets	358.2	310.9
Total current assets	7,869.7	6,092
Property, plant and equipment, net	41,603.4	38,737.6
Investments in unconsolidated affiliates	2,600.2	2,615.1
Intangible assets, net	3,449	3,608.4
Goodwill	5,745.2	5,745.2
Other assets	471.5	201.9
Total assets	61,739	57,000.2
Current liabilities:
Current maturities of debt	1,981.9	1,500.1
Accounts payable - trade	1,004.5	1,102.8
Accounts payable - related parties	162.3	140.9
Accrued product payables	4,915.7	3,475.8
Accrued interest	431.7	395.6
Derivative liabilities	122.4	148.2
Other current liabilities	511.4	404.8
Total current liabilities	9,129.9	7,168.2
Long-term debt	25,643.2	24,678.1
Deferred tax liabilities	97	78.1
Other long-term liabilities	522.9	361.7
Commitments and contingencies
Equity:
Partners' and other owners' equity	25,247.1	24,247.4
Noncontrolling interests	1,098.9	466.7
Total equity	26,346	24,714.1
Total liabilities and equity	61,739	57,000.2
Consolidated EPO and Subsidiaries [Member] | Eliminations and Adjustments [Member]
Current assets:
Cash and cash equivalents and restricted cash	(15.1)	(33.6)	(26.4)	(7.5)
Accounts receivable - trade, net	(1.3)	(0.8)
Accounts receivable - related parties	(1,023.6)	(1,530.1)
Inventories	(0.3)	(0.4)
Derivative assets	0	0.3
Prepaid and other current assets	(46.3)	(10.2)
Total current assets	(1,086.6)	(1,574.8)
Property, plant and equipment, net	(43.5)	(3.8)
Investments in unconsolidated affiliates	(47,079.5)	(45,518.1)
Intangible assets, net	(40)	(13.8)
Goodwill	0	0
Other assets	(221.9)	(222.1)
Total assets	(48,471.5)	(47,332.6)
Current liabilities:
Current maturities of debt	0	0
Accounts payable - trade	(14.6)	(35.5)
Accounts payable - related parties	(1,037.5)	(1,543.9)
Accrued product payables	(1.6)	(1.2)
Accrued interest	(0.8)	(0.8)
Derivative liabilities	0	0.3
Other current liabilities	(47.3)	(9.4)
Total current liabilities	(1,101.8)	(1,590.5)
Long-term debt	0	0
Deferred tax liabilities	(0.8)	(0.9)
Other long-term liabilities	(247.2)	(221.9)
Commitments and contingencies
Equity:
Partners' and other owners' equity	(48,155.3)	(45,917.9)
Noncontrolling interests	1,033.6	398.6
Total equity	(47,121.7)	(45,519.3)
Total liabilities and equity	(48,471.5)	(47,332.6)
Enterprise Products Partners L.P. (Guarantor) [Member]
Current assets:
Cash and cash equivalents and restricted cash	0.1	0	$ 0	$ 0
Accounts receivable - trade, net	0	0
Accounts receivable - related parties	0	0.8
Inventories	0	0
Derivative assets	0	0
Prepaid and other current assets	0	0
Total current assets	0.1	0.8
Property, plant and equipment, net	0	0
Investments in unconsolidated affiliates	25,279.3	24,273.6
Intangible assets, net	0	0
Goodwill	0	0
Other assets	1	0.9
Total assets	25,280.4	24,275.3
Current liabilities:
Current maturities of debt	0	0
Accounts payable - trade	0	0
Accounts payable - related parties	6.9	31.9
Accrued product payables	0	0
Accrued interest	0	0
Derivative liabilities	0	0
Other current liabilities	0	0
Total current liabilities	6.9	31.9
Long-term debt	0	0
Deferred tax liabilities	0	0
Other long-term liabilities	509.5	389.9
Commitments and contingencies
Equity:
Partners' and other owners' equity	24,764	23,853.5
Noncontrolling interests	0	0
Total equity	24,764	23,853.5
Total liabilities and equity	$ 25,280.4	$ 24,275.3

Condensed Consolidating Finan_4

Condensed Consolidating Financial Information, Statements of Operations (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Condensed Consolidated Statement of Operations Information [Abstract]
Revenues	$ 8,005.3	$ 7,964.1	$ 8,276.3	$ 8,543.5	$ 9,182.3	$ 9,585.9	$ 8,467.5	$ 9,298.5	$ 32,789.2	[1]	$ 36,534.2	[1]	$ 29,241.5	[2]
Costs and expenses:
Operating costs and expenses									27,061.8		31,397.3		25,557.5
General and administrative costs									211.7		208.3		181.1
Total costs and expenses									27,273.5		31,605.6		25,738.6
Equity in income of unconsolidated affiliates									563		480		426
Operating income	1,418	1,474.2	1,560.3	1,626.2	1,640.4	1,643.3	986.4	1,138.5	6,078.7		5,408.6		3,928.9
Other income (expense):
Interest expense									(1,243)		(1,096.7)		(984.6)
Other, net									(103)		(13.1)		(63)
Total other expense, net									(1,346)		(1,109.8)		(1,047.6)
Income before income taxes									4,732.7		4,298.8		2,881.3
Provision for income taxes									(45.6)		(60.3)		(25.7)
Net income	1,125.4	1,044.8	1,236.5	1,280.4	1,305.2	1,334.6	687.2	911.5	4,687.1		4,238.5		2,855.6
Net loss (income) attributable to noncontrolling interests									(95.8)		(66.1)		(56.3)
Net income attributable to entity	$ 1,096.9	$ 1,019.2	$ 1,214.7	$ 1,260.5	$ 1,284.7	$ 1,313.2	$ 673.8	$ 900.7	4,591.3		4,172.4		2,799.3
Eliminations and Adjustments [Member]
Condensed Consolidated Statement of Operations Information [Abstract]
Revenues									0		0		0
Costs and expenses:
Operating costs and expenses									0		0		0
General and administrative costs									0		0.1		0
Total costs and expenses									0		0.1		0
Equity in income of unconsolidated affiliates									(4,713)		(4,230.8)		(2,865.4)
Operating income									(4,713)		(4,230.9)		(2,865.4)
Other income (expense):
Interest expense									0		0		0
Other, net									0		0		0
Total other expense, net									0		0		0
Income before income taxes									(4,713)		(4,230.9)		(2,865.4)
Provision for income taxes									(1.1)		(1.5)		0
Net income									(4,714.1)		(4,232.4)		(2,865.4)
Net loss (income) attributable to noncontrolling interests									5.5		5.3		5.3
Net income attributable to entity									(4,708.6)		(4,227.1)		(2,860.1)
Subsidiary Issuer (EPO) [Member]
Condensed Consolidated Statement of Operations Information [Abstract]
Revenues									35,396.9		42,946.4		40,696.8
Costs and expenses:
Operating costs and expenses									34,074.1		41,718.2		39,809.6
General and administrative costs									32.2		31.8		31.4
Total costs and expenses									34,106.3		41,750		39,841
Equity in income of unconsolidated affiliates									4,667.1		4,148.3		2,990.1
Operating income									5,957.7		5,344.7		3,845.9
Other income (expense):
Interest expense									(1,243.8)		(1,097.1)		(982.5)
Other, net									19.8		12.1		9.2
Total other expense, net									(1,224)		(1,085)		(973.3)
Income before income taxes									4,733.7		4,259.7		2,872.6
Provision for income taxes									(16.5)		(29.2)		(12)
Net income									4,717.2		4,230.5		2,860.6
Net loss (income) attributable to noncontrolling interests									0		0		0
Net income attributable to entity									4,717.2		4,230.5		2,860.6
Other Subsidiaries (Non-guarantor) [Member]
Condensed Consolidated Statement of Operations Information [Abstract]
Revenues									21,849		23,756.4		18,451.2
Costs and expenses:
Operating costs and expenses									17,438.7		19,845.2		15,654.9
General and administrative costs									174.2		172		148
Total costs and expenses									17,612.9		20,017.2		15,802.9
Equity in income of unconsolidated affiliates									648.7		587.2		566.8
Operating income									4,884.8		4,326.4		3,215.1
Other income (expense):
Interest expense									(10.5)		(10.5)		(11.8)
Other, net									8		41.8		1.8
Total other expense, net									(2.5)		31.3		(10)
Income before income taxes									4,882.3		4,357.7		3,205.1
Provision for income taxes									(28.3)		(29.6)		(13.7)
Net income									4,854		4,328.1		3,191.4
Net loss (income) attributable to noncontrolling interests									(6.6)		(7.6)		(6.5)
Net income attributable to entity									4,847.4		4,320.5		3,184.9
Consolidated EPO and Subsidiaries [Member]
Condensed Consolidated Statement of Operations Information [Abstract]
Revenues									32,789.2		36,534.2		29,241.5
Costs and expenses:
Operating costs and expenses									27,061.8		31,397.3		25,557.5
General and administrative costs									209.5		205.9		179.3
Total costs and expenses									27,271.3		31,603.2		25,736.8
Equity in income of unconsolidated affiliates									563		480		426
Operating income									6,080.9		5,411		3,930.7
Other income (expense):
Interest expense									(1,243)		(1,096.7)		(984.6)
Other, net									16.5		43		1.3
Total other expense, net									(1,226.5)		(1,053.7)		(983.3)
Income before income taxes									4,854.4		4,357.3		2,947.4
Provision for income taxes									(44.5)		(58.8)		(25.7)
Net income									4,809.9		4,298.5		2,921.7
Net loss (income) attributable to noncontrolling interests									(101.3)		(71.4)		(61.6)
Net income attributable to entity									4,708.6		4,227.1		2,860.1
Consolidated EPO and Subsidiaries [Member] | Eliminations and Adjustments [Member]
Condensed Consolidated Statement of Operations Information [Abstract]
Revenues									(24,456.7)		(30,168.6)		(29,906.5)
Costs and expenses:
Operating costs and expenses									(24,451)		(30,166.1)		(29,907)
General and administrative costs									3.1		2.1		(0.1)
Total costs and expenses									(24,447.9)		(30,164)		(29,907.1)
Equity in income of unconsolidated affiliates									(4,752.8)		(4,255.5)		(3,130.9)
Operating income									(4,761.6)		(4,260.1)		(3,130.3)
Other income (expense):
Interest expense									11.3		10.9		9.7
Other, net									(11.3)		(10.9)		(9.7)
Total other expense, net									0		0		0
Income before income taxes									(4,761.6)		(4,260.1)		(3,130.3)
Provision for income taxes									0.3		0		0
Net income									(4,761.3)		(4,260.1)		(3,130.3)
Net loss (income) attributable to noncontrolling interests									(94.7)		(63.8)		(55.1)
Net income attributable to entity									(4,856)		(4,323.9)		(3,185.4)
Enterprise Products Partners L.P. (Guarantor) [Member]
Condensed Consolidated Statement of Operations Information [Abstract]
Revenues									0		0		0
Costs and expenses:
Operating costs and expenses									0		0		0
General and administrative costs									2.2		2.3		1.8
Total costs and expenses									2.2		2.3		1.8
Equity in income of unconsolidated affiliates									4,713		4,230.8		2,865.4
Operating income									4,710.8		4,228.5		2,863.6
Other income (expense):
Interest expense									0		0		0
Other, net									(119.5)		(56.1)		(64.3)
Total other expense, net									(119.5)		(56.1)		(64.3)
Income before income taxes									4,591.3		4,172.4		2,799.3
Provision for income taxes									0		0		0
Net income									4,591.3		4,172.4		2,799.3
Net loss (income) attributable to noncontrolling interests									0		0		0
Net income attributable to entity									$ 4,591.3		$ 4,172.4		$ 2,799.3
[1]	Revenues are accounted for under ASC 606.
[2]	Revenues are accounted for under ASC 605.

Condensed Consolidating Finan_5

Condensed Consolidating Financial Information, Statements of Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Condensed Consolidating Statement of Comprehensive Income
Comprehensive income	$ 4,707.6	$ 4,461.1	$ 2,963.9
Comprehensive loss (income) attributable to noncontrolling interests	(95.8)	(66.1)	(56.3)
Comprehensive income attributable to entity	4,611.8	4,395	2,907.6
Eliminations and Adjustments [Member]
Condensed Consolidating Statement of Comprehensive Income
Comprehensive income	(4,734.6)	(4,454.9)	(2,973.8)
Comprehensive loss (income) attributable to noncontrolling interests	5.5	5.3	5.3
Comprehensive income attributable to entity	(4,729.1)	(4,449.6)	(2,968.5)
Subsidiary Issuer (EPO) [Member]
Condensed Consolidating Statement of Comprehensive Income
Comprehensive income	4,890.2	4,312.6	2,951.7
Comprehensive loss (income) attributable to noncontrolling interests	0	0	0
Comprehensive income attributable to entity	4,890.2	4,312.6	2,951.7
Other Subsidiaries (Non-guarantor) [Member]
Condensed Consolidating Statement of Comprehensive Income
Comprehensive income	4,701.5	4,468.5	3,208.6
Comprehensive loss (income) attributable to noncontrolling interests	(6.6)	(7.6)	(6.5)
Comprehensive income attributable to entity	4,694.9	4,460.9	3,202.1
Consolidated EPO and Subsidiaries [Member]
Condensed Consolidating Statement of Comprehensive Income
Comprehensive income	4,830.4	4,521	3,030.1
Comprehensive loss (income) attributable to noncontrolling interests	(101.3)	(71.4)	(61.6)
Comprehensive income attributable to entity	4,729.1	4,449.6	2,968.5
Consolidated EPO and Subsidiaries [Member] | Eliminations and Adjustments [Member]
Condensed Consolidating Statement of Comprehensive Income
Comprehensive income	(4,761.3)	(4,260.1)	(3,130.2)
Comprehensive loss (income) attributable to noncontrolling interests	(94.7)	(63.8)	(55.1)
Comprehensive income attributable to entity	(4,856)	(4,323.9)	(3,185.3)
Enterprise Products Partners L.P. (Guarantor) [Member]
Condensed Consolidating Statement of Comprehensive Income
Comprehensive income	4,611.8	4,395	2,907.6
Comprehensive loss (income) attributable to noncontrolling interests	0	0	0
Comprehensive income attributable to entity	$ 4,611.8	$ 4,395	$ 2,907.6

Condensed Consolidating Finan_6

Condensed Consolidating Financial Information, Statements of Cash Flows (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating activities:
Net income	$ 1,125.4	$ 1,044.8	$ 1,236.5	$ 1,280.4	$ 1,305.2	$ 1,334.6	$ 687.2	$ 911.5	$ 4,687.1	$ 4,238.5	$ 2,855.6
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion									1,949.3	1,791.6	1,644
Equity in income of unconsolidated affiliates									(563)	(480)	(426)
Distributions received from unconsolidated affiliates attributable to earnings									568	479.4	433.7
Net effect of changes in operating accounts and other operating activities									(120.9)	96.8	159
Net cash flows provided by operating activities									6,520.5	6,126.3	4,666.3
Investing activities:
Capital expenditures									(4,531.7)	(4,223.2)	(3,101.8)
Cash used for business combinations, net of cash received									0	(150.6)	(198.7)
Proceeds from asset sales									20.6	161.2	40.1
Other investing activities									(64.4)	(69)	(25.7)
Cash used in investing activities									(4,575.5)	(4,281.6)	(3,286.1)
Financing activities:
Borrowings under debt agreements									58,172.6	79,588.7	69,315.3
Repayments of debt									(56,716.5)	(77,957.1)	(68,459.6)
Cash distributions paid to owners									(3,839.8)	(3,726.9)	(3,569.9)
Cash payments made in connection with DERs									(22.1)	(17.7)	(15.1)
Cash distributions paid to noncontrolling interests									(106.2)	(81.6)	(49.2)
Cash contributions from noncontrolling interests									632.8	238.1	0.4
Net cash proceeds from the issuance of common units									82.2	538.4	1,073.4
Repurchase of common units under buyback programs									(81.1)	(30.8)	0
Cash contributions from owners									0	0	0
Other financing activities									(67)	(56)	(22.8)
Cash provided by (used in) financing activities									(1,945.1)	(1,504.9)	(1,727.5)
Net change in cash and cash equivalents, including restricted cash									(0.1)	339.8	(347.3)
Cash and cash equivalents, including restricted cash, at beginning of period				410.1				70.3	410.1	70.3	417.6
Cash and cash equivalents, including restricted cash, at end of period	410				410.1				410	410.1	70.3
Eliminations and Adjustments [Member]
Operating activities:
Net income									(4,714.1)	(4,232.4)	(2,865.4)
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									4,713	4,230.8	2,865.4
Distributions received from unconsolidated affiliates attributable to earnings									(4,005.8)	(3,780)	(3,574.6)
Net effect of changes in operating accounts and other operating activities									0.2	0.6	(1)
Net cash flows provided by operating activities									(4,006.7)	(3,781)	(3,575.6)
Investing activities:
Capital expenditures									0	0	0
Cash used for business combinations, net of cash received										0	0
Proceeds from asset sales									0	0	0
Other investing activities									119.3	523.3	1,060.5
Cash used in investing activities									119.3	523.3	1,060.5
Financing activities:
Borrowings under debt agreements									0	0	0
Repayments of debt									0	0	0
Cash distributions paid to owners									4,005.8	3,780	3,574.6
Cash payments made in connection with DERs									0	0	0
Cash distributions paid to noncontrolling interests									0.9	1	1
Cash contributions from noncontrolling interests									0	0	0
Net cash proceeds from the issuance of common units									0	0	0
Repurchase of common units under buyback programs									0	0
Cash contributions from owners									(119.3)	(523.3)	(1,060.5)
Other financing activities									0	0	0
Cash provided by (used in) financing activities									3,887.4	3,257.7	2,515.1
Net change in cash and cash equivalents, including restricted cash									0	0	0
Cash and cash equivalents, including restricted cash, at beginning of period				0				0	0	0	0
Cash and cash equivalents, including restricted cash, at end of period	0				0				0	0	0
Subsidiary Issuer (EPO) [Member]
Operating activities:
Net income									4,717.2	4,230.5	2,860.6
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion									309	279.9	216.6
Equity in income of unconsolidated affiliates									(4,667.1)	(4,148.3)	(2,990.1)
Distributions received from unconsolidated affiliates attributable to earnings									1,560.7	1,248.9	1,162.8
Net effect of changes in operating accounts and other operating activities									3,007.5	3,221.5	2,812.2
Net cash flows provided by operating activities									4,927.3	4,832.5	4,062.1
Investing activities:
Capital expenditures									(675.4)	(692)	(846.8)
Cash used for business combinations, net of cash received										0	(7.3)
Proceeds from asset sales									2.3	129.3	17
Other investing activities									(2,080.6)	(2,288.2)	(1,908.5)
Cash used in investing activities									(2,753.7)	(2,850.9)	(2,745.6)
Financing activities:
Borrowings under debt agreements									58,172.6	79,588.7	69,349.3
Repayments of debt									(56,716.4)	(77,956.7)	(68,459.5)
Cash distributions paid to owners									(4,005.8)	(3,780)	(3,574.6)
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
Repurchase of common units under buyback programs									0	0
Cash contributions from owners									119.3	523.3	1,060.5
Other financing activities									(27.5)	(28.7)	6.8
Cash provided by (used in) financing activities									(2,457.8)	(1,653.4)	(1,617.5)
Net change in cash and cash equivalents, including restricted cash									(284.2)	328.2	(301)
Cash and cash equivalents, including restricted cash, at beginning of period				393.4				65.2	393.4	65.2	366.2
Cash and cash equivalents, including restricted cash, at end of period	109.2				393.4				109.2	393.4	65.2
Other Subsidiaries (Non-guarantor) [Member]
Operating activities:
Net income									4,854	4,328.1	3,191.4
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion									1,642.7	1,512.1	1,427.8
Equity in income of unconsolidated affiliates									(648.7)	(587.2)	(566.8)
Distributions received from unconsolidated affiliates attributable to earnings									317.7	263	272.7
Net effect of changes in operating accounts and other operating activities									(3,294)	(3,244.2)	(2,726.3)
Net cash flows provided by operating activities									2,871.7	2,271.8	1,598.8
Investing activities:
Capital expenditures									(3,850.2)	(3,476)	(2,255)
Cash used for business combinations, net of cash received										(150.6)	(191.4)
Proceeds from asset sales									18.3	31.9	23.1
Other investing activities									3.7	196.2	(28)
Cash used in investing activities									(3,828.2)	(3,398.5)	(2,451.3)
Financing activities:
Borrowings under debt agreements									0	11.5	0
Repayments of debt									(0.1)	(0.4)	(0.1)
Cash distributions paid to owners									(1,871.7)	(1,333.1)	(1,065.3)
Cash payments made in connection with DERs									0	0	0
Cash distributions paid to noncontrolling interests									(9.5)	(9.2)	(9.6)
Cash contributions from noncontrolling interests									0	0	0.1
Net cash proceeds from the issuance of common units									0	0	0
Repurchase of common units under buyback programs									0	0
Cash contributions from owners									3,109	2,476.7	1,900
Other financing activities									(5.7)	0	0
Cash provided by (used in) financing activities									1,222	1,145.5	825.1
Net change in cash and cash equivalents, including restricted cash									265.5	18.8	(27.4)
Cash and cash equivalents, including restricted cash, at beginning of period				50.3				31.5	50.3	31.5	58.9
Cash and cash equivalents, including restricted cash, at end of period	315.8				50.3				315.8	50.3	31.5
Consolidated EPO and Subsidiaries [Member]
Operating activities:
Net income									4,809.9	4,298.5	2,921.7
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion									1,949.3	1,791.6	1,644
Equity in income of unconsolidated affiliates									(563)	(480)	(426)
Distributions received from unconsolidated affiliates attributable to earnings									568	479.4	433.7
Net effect of changes in operating accounts and other operating activities									(251)	(25)	66.8
Net cash flows provided by operating activities									6,513.2	6,064.5	4,640.2
Investing activities:
Capital expenditures									(4,531.7)	(4,168)	(3,101.8)
Cash used for business combinations, net of cash received										(150.6)	(198.7)
Proceeds from asset sales									20.6	161.2	40.1
Other investing activities									(64.4)	(69)	(25.7)
Cash used in investing activities									(4,575.5)	(4,226.4)	(3,286.1)
Financing activities:
Borrowings under debt agreements									58,172.6	79,588.7	69,315.3
Repayments of debt									(56,716.5)	(77,957.1)	(68,459.6)
Cash distributions paid to owners									(4,005.8)	(3,780)	(3,574.6)
Cash payments made in connection with DERs									0	0	0
Cash distributions paid to noncontrolling interests									(107.1)	(82.6)	(50.2)
Cash contributions from noncontrolling interests									632.8	238.1	0.4
Net cash proceeds from the issuance of common units									0	0	0
Repurchase of common units under buyback programs									0	0
Cash contributions from owners									119.3	523.3	1,060.5
Other financing activities									(33.2)	(28.7)	6.8
Cash provided by (used in) financing activities									(1,937.9)	(1,498.3)	(1,701.4)
Net change in cash and cash equivalents, including restricted cash									(0.2)	339.8	(347.3)
Cash and cash equivalents, including restricted cash, at beginning of period				410.1				70.3	410.1	70.3	417.6
Cash and cash equivalents, including restricted cash, at end of period	409.9				410.1				409.9	410.1	70.3
Consolidated EPO and Subsidiaries [Member] | Eliminations and Adjustments [Member]
Operating activities:
Net income									(4,761.3)	(4,260.1)	(3,130.3)
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion									(2.4)	(0.4)	(0.4)
Equity in income of unconsolidated affiliates									4,752.8	4,255.5	3,130.9
Distributions received from unconsolidated affiliates attributable to earnings									(1,310.4)	(1,032.5)	(1,001.8)
Net effect of changes in operating accounts and other operating activities									35.5	(2.3)	(19.1)
Net cash flows provided by operating activities									(1,285.8)	(1,039.8)	(1,020.7)
Investing activities:
Capital expenditures									(6.1)	0	0
Cash used for business combinations, net of cash received										0	0
Proceeds from asset sales									0	0	0
Other investing activities									2,012.5	2,023	1,910.8
Cash used in investing activities									2,006.4	2,023	1,910.8
Financing activities:
Borrowings under debt agreements									0	(11.5)	(34)
Repayments of debt									0	0	0
Cash distributions paid to owners									1,871.7	1,333.1	1,065.3
Cash payments made in connection with DERs									0	0	0
Cash distributions paid to noncontrolling interests									(97.6)	(73.4)	(40.6)
Cash contributions from noncontrolling interests									632.8	238.1	0.3
Net cash proceeds from the issuance of common units									0	0	0
Repurchase of common units under buyback programs									0	0
Cash contributions from owners									(3,109)	(2,476.7)	(1,900)
Other financing activities									0	0	0
Cash provided by (used in) financing activities									(702.1)	(990.4)	(909)
Net change in cash and cash equivalents, including restricted cash									18.5	(7.2)	(18.9)
Cash and cash equivalents, including restricted cash, at beginning of period				(33.6)				(26.4)	(33.6)	(26.4)	(7.5)
Cash and cash equivalents, including restricted cash, at end of period	(15.1)				(33.6)				(15.1)	(33.6)	(26.4)
Enterprise Products Partners L.P. (Guarantor) [Member]
Operating activities:
Net income									4,591.3	4,172.4	2,799.3
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									(4,713)	(4,230.8)	(2,865.4)
Distributions received from unconsolidated affiliates attributable to earnings									4,005.8	3,780	3,574.6
Net effect of changes in operating accounts and other operating activities									129.9	121.2	93.2
Net cash flows provided by operating activities									4,014	3,842.8	3,601.7
Investing activities:
Capital expenditures									0	(55.2)	0
Cash used for business combinations, net of cash received										0	0
Proceeds from asset sales									0	0	0
Other investing activities									(119.3)	(523.3)	(1,060.5)
Cash used in investing activities									(119.3)	(578.5)	(1,060.5)
Financing activities:
Borrowings under debt agreements									0	0	0
Repayments of debt									0	0	0
Cash distributions paid to owners									(3,839.8)	(3,726.9)	(3,569.9)
Cash payments made in connection with DERs									(22.1)	(17.7)	(15.1)
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									82.2	538.4	1,073.4
Repurchase of common units under buyback programs									(81.1)	(30.8)
Cash contributions from owners									0	0	0
Other financing activities									(33.8)	(27.3)	(29.6)
Cash provided by (used in) financing activities									(3,894.6)	(3,264.3)	(2,541.2)
Net change in cash and cash equivalents, including restricted cash									0.1	0	0
Cash and cash equivalents, including restricted cash, at beginning of period				$ 0				$ 0	0	0	0
Cash and cash equivalents, including restricted cash, at end of period	$ 0.1				$ 0				$ 0.1	$ 0	$ 0

Subsequent Event (Details)

Subsequent Event (Details) - USD ($) $ in Millions	1 Months Ended		12 Months Ended
	Sep. 30, 2020	Jan. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Debt Obligations [Abstract]
Repayment of debt obligations			$ 56,716.5	$ 77,957.1	$ 68,459.6
Summary of Derivative Instruments [Abstract]
Payment on the settlement of interest rate derivative instruments			0	(22.1)	(30.6)
Forward Starting Swaps [Member] | Derivatives in cash flow hedging relationships [Member]
Summary of Derivative Instruments [Abstract]
Notional amount of settled derivative instruments				275	275
Payment on the settlement of interest rate derivative instruments				(22.1)	$ (30.6)
Senior Notes [Member]
Debt Obligations [Abstract]
Aggregate debt principal issued			$ 2,500	$ 5,000
Forecast [Member] | Senior Notes [Member] | EPO Senior Notes Y due September 2020 [Member]
Debt Obligations [Abstract]
Repayment of debt obligations	$ 1,000
Subsequent Event [Member] | Forward Starting Swaps [Member] | Derivatives in cash flow hedging relationships [Member]
Summary of Derivative Instruments [Abstract]
Notional amount of settled derivative instruments		$ 575
Payment on the settlement of interest rate derivative instruments		33.3
Subsequent Event [Member] | Senior Notes [Member]
Debt Obligations [Abstract]
Aggregate debt principal issued		3,000
Subsequent Event [Member] | Senior Notes [Member] | EPO Senior Notes AAA due January 2030 [Member]
Debt Obligations [Abstract]
Aggregate debt principal issued		$ 1,000
Interest rate, stated percentage		2.80%
Debt issued as percent of principal amount		99.921%
Subsequent Event [Member] | Senior Notes [Member] | EPO Senior Notes BBB due January 2051 [Member]
Debt Obligations [Abstract]
Aggregate debt principal issued		$ 1,000
Interest rate, stated percentage		3.70%
Debt issued as percent of principal amount		99.413%
Subsequent Event [Member] | Senior Notes [Member] | EPO Senior Notes CCC due January 2060 [Member]
Debt Obligations [Abstract]
Aggregate debt principal issued		$ 1,000
Interest rate, stated percentage		3.95%
Debt issued as percent of principal amount		99.36%
Subsequent Event [Member] | Senior Notes [Member] | EPO Senior Notes Q due January 2020 [Member]
Debt Obligations [Abstract]
Repayment of debt obligations		$ 500