0001061219-21-000009 | 10-K | XBRL Viewer | Enterprise Products Partners LP

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Document and Entity Information - USD ($) $ in Millions	12 Months Ended
Document and Entity Information - USD ($) $ in Millions	Dec. 31, 2020	Jan. 31, 2021	Jun. 30, 2020
Cover page.
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2020
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 Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
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 Public Float			$ 26,960
Entity Common Stock, Shares Outstanding		2,181,599,142
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
Entity Central Index Key	0001061219
Document Annual Report	true
Title of 12(b) Security	Common Units
Trading Symbol	EPD
Security Exchange Name	NYSE

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Current assets:
Cash and cash equivalents	$ 1,059.9	$ 334.7
Restricted cash	98.2	75.3
Accounts receivable - trade, net of allowance for doubtful accounts of $46.5 at December 31, 2020 and $12.4 at December 31, 2019	4,802.6	4,873.6
Accounts receivable - related parties	5.6	2.5
Inventories	3,303.5	2,091.4
Derivative assets	228.6	127.2
Prepaid and other current assets	411.0	358.2
Total current assets	9,909.4	7,862.9
Property, plant and equipment, net	41,912.8	41,603.4
Investments in unconsolidated affiliates	2,429.2	2,600.2
Intangible assets, net of accumulated amortization of $1,826.7 at December 31, 2020 and $1,687.5 at December 31, 2019	3,309.1	3,449.0
Goodwill	5,448.9	5,745.2
Other assets	1,097.3	472.5
Total assets	64,106.7	61,733.2
Current liabilities:
Current maturities of debt	1,325.0	1,981.9
Accounts payable - trade	704.6	1,004.5
Accounts payable - related parties	149.5	162.3
Accrued product payables	5,395.4	4,915.7
Accrued interest	455.6	431.7
Derivative liabilities	349.2	122.4
Other current liabilities	608.7	511.2
Total current liabilities	8,988.0	9,129.7
Long-term debt	28,540.7	25,643.2
Deferred tax liabilities	464.7	100.4
Other long-term liabilities	686.6	1,032.4
Commitments and contingent liabilities
Redeemable preferred limited partner interests:
Series A cumulative convertible preferred units (50,138 units outstanding at December 31, 2020)	49.3	0.0
Partners' equity:
Common limited partner interests (2,182,308,958 units issued and outstanding at December 31, 2020 and 2,189,226,130 units issued and outstanding at December 31, 2019)	25,766.6	24,692.6
Treasury units, at cost	(1,297.3)	0.0
Accumulated other comprehensive income (loss)	(165.2)	71.4
Total partners' equity	24,304.1	24,764.0
Noncontrolling interests in consolidated subsidiaries	1,073.3	1,063.5
Total equity	25,377.4	25,827.5
Total liabilities, preferred units, and equity	$ 64,106.7	$ 61,733.2

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
ASSETS
Accounts receivable, allowance for doubtful accounts	$ 46.5	$ 12.4
Intangible assets, accumulated amortization	$ 1,826.7	$ 1,687.5
Redeemable preferred limited partner interests:
Series A cumulative convertible preferred units outstanding (in units)	50,138
Limited partners:
Common units issued (in units)	2,182,308,958	2,189,226,130
Common units outstanding (in units)	2,182,308,958	2,189,226,130

STATEMENTS OF CONSOLIDATED OPERATIONS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Revenues:
Third parties	$ 27,163.0	$ 32,721.9	$ 36,426.5
Related parties	36.7	67.3	107.7
Total revenues	27,199.7	32,789.2	36,534.2
Operating costs and expenses:
Third party and other costs	21,160.5	25,649.8	29,991.2
Related parties	1,210.6	1,412.0	1,406.1
Total operating costs and expenses	22,371.1	27,061.8	31,397.3
General and administrative costs:
Third party and other costs	83.4	75.3	77.4
Related parties	136.2	136.4	130.9
Total general and administrative costs	219.6	211.7	208.3
Total costs and expenses	22,590.7	27,273.5	31,605.6
Equity in income of unconsolidated affiliates	426.1	563.0	480.0
Operating income	5,035.1	6,078.7	5,408.6
Other income (expense):
Interest expense	(1,287.4)	(1,243.0)	(1,096.7)
Change in fair market value of Liquidity Option	(2.3)	(119.6)	(56.1)
Gain on step acquisition of unconsolidated affiliate	0.0	0.0	39.4
Interest income	13.4	11.6	3.6
Other, net	2.6	5.0	0.0
Total other expense, net	(1,273.7)	(1,346.0)	(1,109.8)
Income before income taxes	3,761.4	4,732.7	4,298.8
Benefit from (provision for) income taxes	124.3	(45.6)	(60.3)
Net income	3,885.7	4,687.1	4,238.5
Net income attributable to noncontrolling interests	(110.1)	(95.8)	(66.1)
Net income attributable to preferred units	(0.9)	0.0	0.0
Net income attributable to common unitholders	$ 3,774.7	$ 4,591.3	$ 4,172.4
Earnings per unit:
Basic earnings per common unit (in dollars per unit)	$ 1.71	$ 2.09	$ 1.91
Diluted earnings per common unit (in dollars per unit)	$ 1.71	$ 2.09	$ 1.91

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
Net income	$ 3,885.7	$ 4,687.1	$ 4,238.5
Commodity hedging derivative instruments:
Changes in fair value of cash flow hedges	124.4	44.1	293.2
Reclassification of gains to net income	(272.7)	(141.7)	(130.4)
Interest rate hedging derivative instruments:
Changes in fair value of cash flow hedges	(127.5)	81.4	22.2
Reclassification of losses to net income	39.3	37.3	38.1
Total cash flow hedges	(236.5)	21.1	223.1
Other	(0.1)	(0.6)	(0.5)
Total other comprehensive income (loss)	(236.6)	20.5	222.6
Comprehensive income	3,649.1	4,707.6	4,461.1
Comprehensive income attributable to noncontrolling interests	(110.1)	(95.8)	(66.1)
Comprehensive income attributable to preferred units	(0.9)	0.0	0.0
Comprehensive income attributable to common unitholders	$ 3,538.1	$ 4,611.8	$ 4,395.0

STATEMENTS OF CONSOLIDATED CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Operating activities:
Net income	$ 3,885.7	$ 4,687.1	$ 4,238.5
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion	2,071.9	1,949.3	1,791.6
Impairment of goodwill	296.3	0.0	0.0
Impairment of assets other than goodwill	594.3	132.8	50.5
Equity in income of unconsolidated affiliates	(426.1)	(563.0)	(480.0)
Distributions received from unconsolidated affiliates attributable to earnings	426.6	568.0	479.4
Net gains attributable to asset sales	(4.4)	(5.7)	(28.7)
Deferred income tax expense (benefit)	(147.6)	20.0	21.4
Change in fair market value of derivative instruments	(79.3)	27.2	17.8
Change in fair market value of Liquidity Option	2.3	119.6	56.1
Gain on step acquisition of unconsolidated affiliate	0.0	0.0	(39.4)
Non-cash expense related to long-term operating leases	39.0	42.8	0.0
Net effect of changes in operating accounts	(767.5)	(457.4)	16.2
Other operating activities	0.3	(0.2)	2.9
Net cash flows provided by operating activities	5,891.5	6,520.5	6,126.3
Investing activities:
Capital expenditures	(3,287.9)	(4,531.7)	(4,223.2)
Cash used for business combinations, net of cash received	0.0	0.0	(150.6)
Investments in unconsolidated affiliates	(15.6)	(111.6)	(113.6)
Distributions received from unconsolidated affiliates attributable to the return of capital	187.5	63.3	50.0
Proceeds from asset sales	12.8	20.6	161.2
Other investing activities	(17.5)	(16.1)	(5.4)
Cash used in investing activities	(3,120.7)	(4,575.5)	(4,281.6)
Financing activities:
Borrowings under debt agreements	6,672.1	58,172.6	79,588.7
Repayments of debt	(4,406.6)	(56,716.5)	(77,957.1)
Debt issuance costs	(46.3)	(27.6)	(49.1)
Monetization of interest rate derivative instruments	(33.3)	0.0	22.1
Cash distributions paid to common unitholders	(3,891.0)	(3,839.8)	(3,726.9)
Cash payments made in connection with distribution equivalent rights	(27.1)	(22.1)	(17.7)
Cash distributions paid to noncontrolling interests	(131.3)	(106.2)	(81.6)
Cash contributions from noncontrolling interests	30.9	632.8	238.1
Net cash proceeds from the issuance of common units	0.0	82.2	538.4
Repurchase of common units under buyback programs	(186.3)	(81.1)	(30.8)
Net cash proceeds from the issuance of preferred units	31.5	0.0	0.0
Other financing activities	(35.3)	(39.4)	(29.0)
Cash used in financing activities	(2,022.7)	(1,945.1)	(1,504.9)
Net change in cash and cash equivalents, including restricted cash	748.1	(0.1)	339.8
Cash and cash equivalents, including restricted cash, at beginning of period	410.0	410.1	70.3
Cash and cash equivalents, including restricted cash, at end of period	$ 1,158.1	$ 410.0	$ 410.1

STATEMENTS OF CONSOLIDATED EQUITY - USD ($) $ in Millions	Total	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interests in Consolidated Subsidiaries [Member]	Common Limited Partners Interests [Member]	Treasury Units [Member]
Balance at Dec. 31, 2017	$ 22,772.4	$ (171.7)	$ 225.2	$ 22,718.9	$ 0.0
Increase (Decrease) in Partners' Equity [Roll Forward]
Net income	4,238.5	0.0	66.1	4,172.4	0.0
Cash distributions paid to common unitholders	(3,726.9)	0.0	0.0	(3,726.9)	0.0
Cash payments made in connection with distribution equivalent rights	(17.7)	0.0	0.0	(17.7)	0.0
Cash distributions paid to noncontrolling interests	(81.6)	0.0	(81.6)	0.0	0.0
Cash contributions from noncontrolling interests	238.1	0.0	238.1	0.0	0.0
Net cash proceeds from the issuance of common units	538.4	0.0	0.0	538.4	0.0
Common units issued in connection with employee compensation	39.1	0.0	0.0	39.1	0.0
Common units issued in connection with land acquisition	30.0	0.0	0.0	30.0	0.0
Repurchase and cancellation of common units under buyback programs	(30.8)	0.0	0.0	(30.8)	0.0
Amortization of fair value of equity-based awards	104.7	0.0	0.0	104.7	0.0
Cash flow hedges	223.1	223.1	0.0	0.0	0.0
Other, net	(35.1)	(0.5)	(9.1)	(25.5)	0.0
Balance at Dec. 31, 2018	24,292.2	50.9	438.7	23,802.6	0.0
Increase (Decrease) in Partners' Equity [Roll Forward]
Net income	4,687.1	0.0	95.8	4,591.3	0.0
Cash distributions paid to common unitholders	(3,839.8)	0.0	0.0	(3,839.8)	0.0
Cash payments made in connection with distribution equivalent rights	(22.1)	0.0	0.0	(22.1)	0.0
Cash distributions paid to noncontrolling interests	(106.2)	0.0	(106.2)	0.0	0.0
Cash contributions from noncontrolling interests	632.8	0.0	632.8	0.0	0.0
Net cash proceeds from the issuance of common units	82.2	0.0	0.0	82.2	0.0
Common units issued in connection with employee compensation	45.6	0.0	0.0	45.6	0.0
Repurchase and cancellation of common units under buyback programs	(81.1)	0.0	0.0	(81.1)	0.0
Amortization of fair value of equity-based awards	143.3	0.0	0.0	143.3	0.0
Cash flow hedges	21.1	21.1	0.0	0.0	0.0
Other, net	(27.6)	(0.6)	2.4	(29.4)	0.0
Balance at Dec. 31, 2019	25,827.5	71.4	1,063.5	24,692.6	0.0
Increase (Decrease) in Partners' Equity [Roll Forward]
Net income	3,884.8	0.0	110.1	3,774.7	0.0
Cash distributions paid to common unitholders	(3,891.0)	0.0	0.0	(3,891.0)	0.0
Cash payments made in connection with distribution equivalent rights	(27.1)	0.0	0.0	(27.1)	0.0
Cash distributions paid to noncontrolling interests	(131.3)	0.0	(131.3)	0.0	0.0
Cash contributions from noncontrolling interests	30.9	0.0	30.9	0.0	0.0
Repurchase and cancellation of common units under buyback programs	(186.3)	0.0	0.0	(186.3)	0.0
Common units issued to Skyline North Americas, Inc. in connection with settlement of Liquidity Option	1,297.3	0.0	0.0	1,297.3	0.0
Treasury units acquired in connection with settlement of Liquidity Option, at cost	(1,297.3)	0.0	0.0	0.0	(1,297.3)
Common units exchanged for preferred units, with common units received being immediately cancelled	(17.5)	0.0	0.0	(17.5)	0.0
Amortization of fair value of equity-based awards	158.6	0.0	0.0	158.6	0.0
Cash flow hedges	(236.5)	(236.5)	0.0	0.0	0.0
Other, net	(34.7)	(0.1)	0.1	(34.7)	0.0
Balance at Dec. 31, 2020	$ 25,377.4	$ (165.2)	$ 1,073.3	$ 25,766.6	$ (1,297.3)

Partnership Organization and Operations

12 Months Ended

Dec. 31, 2020

Partnership Organization and Operations [Abstract]

Partnership Organization and Operations

KEY REFERENCES USED IN THESE

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Unless the context requires otherwise, references to “we,” “us,” or “our” within these Notes to Consolidated Financial Statements are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries.

References to 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 the Partnership, and its consolidated subsidiaries, through which the Partnership conducts its business. We are managed by our 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) W. Randall Fowler, who is also a director and the Co-Chief Executive Officer and Chief Financial Officer of Enterprise GP. Ms. Duncan Williams and Messrs. Bachmann and Fowler also currently serve as managers of Dan Duncan LLC.

References to “EPCO” mean Enterprise Products Company, a privately held Texas corporation, and its privately held affiliates. 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) Mr. Bachmann, who serves as the President and Chief Executive Officer of EPCO; and (iii) Mr. Fowler, who serves as an Executive Vice President and the Chief Financial Officer of EPCO. Ms. Duncan Williams and Messrs. Bachmann and Fowler also currently serve as directors of EPCO.

We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates under the collective common control of the DD LLC Trustees and the EPCO Trustees. EPCO, together with its privately held affiliates, owned approximately 32.2% of the Partnership’s common units outstanding and 30.2% of its preferred units outstanding at December 31, 2020.

All statistical data (e.g., pipeline mileage, processing capacity and similar operating metrics) in these notes to consolidated financial statements are unaudited.

With the exception of per unit amounts, or as noted within the context of each disclosure,

the dollar amounts presented in the tabular data within these disclosures are

stated in millions of dollars.

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.” Our preferred units are not publicly traded. 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. We are owned by our limited partners (preferred and common unitholders) from an economic perspective. Enterprise GP, which owns a non-economic general partner interest in us, manages our Partnership. We conduct substantially all of our business operations through EPO and its consolidated subsidiaries.

Our fully integrated, midstream energy asset network (or “value chain”) 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 include:

•	natural gas gathering, treating, processing, transportation and storage;

•	NGL transportation, fractionation, storage, and marine terminals (including those used to export liquefied petroleum gases, or “LPG,” and ethane);

•	crude oil gathering, transportation, storage, and marine terminals;

•	propylene production facilities (including propane dehydrogenation (“PDH”) facilities), butane isomerization, octane enhancement, isobutane dehydrogenation (“iBDH”) and high purity isobutylene (“HPIB”) production facilities;

•	petrochemical and refined products transportation, storage, and marine terminals (including those used to export ethylene and polymer grade propylene; and

•	a marine transportation business that operates on key U.S. inland and intracoastal waterway systems.

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: NGL Pipelines & Services, Crude Oil Pipelines & Services, Natural Gas Pipelines & Services and Petrochemical & Refined Products Services. See Note 10 for additional information regarding our business segments.

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2020

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

We estimate our allowance for doubtful accounts at each reporting date using a current expected credit loss model, which requires the measurement of expected credit losses for financial assets (e.g., accounts receivable) based on historical experience with customers, current economic conditions, and reasonable and supportable forecasts. We may also increase the allowance for doubtful accounts in response to the specific identification of customers involved in bankruptcy proceedings and similar financial difficulties.

The following table presents our allowance for doubtful accounts activity for the years indicated:

	For the Year Ended December 31,
	2020			2019			2018
Balance at beginning of period	$	12.4		$	11.5		$	12.1
Charged to costs and expenses		8.4			1.2			0.7
Charged to other accounts (1)		28.7			–			–
Deductions		(3.0	)		(0.3	)		(1.3	)
Balance at end of period	$	46.5		$	12.4		$	11.5

(1)	Amount presented for 2020 primarily relates to the reclassification of deferred revenue balances to allowance for doubtful accounts in connection with customer bankruptcies and contractual disputes.

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, refined products and power. 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,
	2020		2019
Cash and cash equivalents	$	1,059.9	$	334.7
Restricted cash		98.2		75.3
Total cash, cash equivalents and restricted cash shown in the Statements of Consolidated Cash Flows	$	1,158.1	$	410.0

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, 2020, 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,
	2020			2019			2018
Balance at beginning of period	$	7.2		$	6.9		$	11.6
Charged to costs and expenses		6.2			12.3			8.2
Acquisition-related additions and other		2.6			2.5			1.7
Deductions		(11.5	)		(14.5	)		(14.6	)
Balance at end of period	$	4.5		$	7.2		$	6.9

At December 31, 2020 and 2019, $3.8 million and $5.8 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 recurring and nonrecurring 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 (such as the income or market approaches) employ inputs such as contractual prices, quoted market prices or rates, operating costs, discount factors and business growth rates. These inputs may be either readily observable, corroborated by market data or generally unobservable. In developing our estimates of fair value, we endeavor to utilize the best information available and apply market-based data to the extent possible.

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 fair value measures) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3 fair value measures). 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 value measures. 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., transactions on 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 value measures. Level 2 fair values are based on pricing inputs other than quoted prices in active markets (a Level 1 fair value measure) 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 value measures. 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 forecasts. Level 3 inputs are typically used in connection with internally developed valuation methodologies where we make our best estimate of fair value. Valuations using Level 3 inputs are reviewed and approved by members of senior management.

With regards to commodity derivatives, our Level 3 fair values primarily consist of the following commodity derivative instruments used to hedge 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.

Our nonrecurring fair value estimates are generally based on the income approach to fair value and reflect various Level 3 inputs. In many cases, there are no active markets (a Level 1 fair value measure) to rely on or other similar recent transactions (a Level 2 fair value measure) to compare to. Our nonrecurring fair value estimates often include management’s expectations of the residual market values for the underlying assets based on their knowledge and experience in the industry (a Level 3 fair value measure). Other examples of Level 3 inputs used in the valuation models include anticipated gross operating margins, throughput or processing volumes, utilization factors, sustaining capital expenditures, discount rates and business growth rates. When probability weights are used in cash flow modeling, the weights are generally obtained from management personnel having oversight responsibilities for the assets being tested.

Impairment Testing

The following table summarizes our asset impairment charges by type as presented on our Statements of Consolidated Cash Flows for the years indicated:

	For the Year Ended December 31,
	2020		2019		2018
Impairment charges reflected in operating costs and expenses:
Property, plant and equipment (see Note 4)	$	589.8	$	51.0	$	46.8
Investment in unconsolidated affiliate (see Note 5)		–		76.4		–
Goodwill (see Note 6)		296.3		–		–
Other (1)		4.5		5.3		3.7
Total asset impairment charges in operating costs and expenses		890.6		132.7		50.5
Other property, plant and equipment impairment charges (2)		–		0.1		–
Total asset impairment charges	$	890.6	$	132.8	$	50.5

(1)	Primarily represents the write-down of surplus materials classified as current assets and intangible assets other than goodwill.
(2)	Amounts presented are reflected in general and administrative costs.

Asset impairment charges related to operations are a component of “Third party and other costs” within the “Operating costs and expenses” section of our Statements of Consolidated Operations.

The following information describes our accounting policies regarding impairment testing for major asset categories:

•

Impairment Testing for Long-Lived Assets. Long-lived assets, which consist of intangible assets with finite 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 4 for information regarding impairment charges attributable to property, plant and equipment.

•

Impairment Testing for Investments in 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. See Note 5 for information regarding an impairment charge attributable to our investments in unconsolidated affiliates in 2019.

•

Impairment Testing for Goodwill. Goodwill, which represents the cost of an acquired business in excess of the fair value of its net assets at the acquisition date, is subject to annual impairment testing in the fourth quarter of each year or when events or changes in circumstances indicate that the carrying amount of the goodwill may not be recoverable. We test goodwill for impairment at the reporting unit (or operating segment) level following guidance in ASU 2017-04, “Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment,” the provisions of which we adopted on January 1, 2020. Goodwill impairment charges represent the amount by which a reporting unit’s carrying value (including its respective goodwill) exceeds its fair value, not to exceed the carrying amount of the reporting unit’s goodwill.

We determine the fair value of each reporting unit using accepted valuation techniques, primarily through the use of discounted cash flows (i.e., an income approach to fair value) supplemented by market-based assessments, if available. The estimated fair values of our reporting units 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 comprising the reporting unit, which, in turn, rely on management’s estimates of long-term operating margins, throughput volumes, capital investments and similar factors; (ii) long-term growth rates for the reporting unit’s cash flows beyond the discrete forecast period; and (iii) appropriate discount rates. The fair value estimates are based on Level 3 inputs of the fair value hierarchy. 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. However, due to uncertainties in the estimation process and volatility in the supply and demand for hydrocarbons and similar risk factors, actual results could differ significantly from our estimates. See Note 6 for information regarding an impairment charge attributable to goodwill in 2020.

We are closely monitoring the recoverability of our long-lived assets, investments in unconsolidated affiliates and goodwill in light of the adverse economic effects of the coronavirus disease 2019 (“COVID-19”) pandemic. If the adverse economic impacts of the pandemic persist for longer periods than currently expected, these developments could result in the recognition of additional non-cash impairment charges in the future.

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, which requires substantially all leases be recorded on the balance sheet. We adopted the new standard on January 1, 2019 and applied it to (i) all new leases entered into after January 1, 2019 and (ii) all existing lease contracts as of January 1, 2019. ASC 842 supersedes existing lease accounting guidance found under ASC 840, 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 effective interest method. 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 $246.1 million 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 facilities undergo periodic planned outages for major maintenance activities. The method of accounting for these activities depends on whether the plant utilizes either a distillation-based or reaction-based process. Our natural gas processing plants, NGL fractionators, deisobutanizers, propylene splitters and similar facilities utilize thermal distillation processes to separate hydrocarbons into more useful components. Our reaction-based plants, which primarily include our PDH, isomerization and octane enhancement facilities, utilize catalysts to facilitate chemical reactions that convert lower value hydrocarbons into higher value products. We use the expense-as-incurred method to account for the planned major maintenance activities of distillation-based plants. For reaction-based plants, we use the deferral method when accounting for major maintenance activities. Under the deferral method, major maintenance costs are capitalized and amortized over the period until the next major overhaul project. We adopted the deferral method for our reaction-based plants in November 2020. Historically, the costs of major maintenance activities attributable to our reaction-based facilities, principally our octane enhancement assets, were not material to our consolidated financial statements.

With regard to the planned major maintenance activities of our marine transportation assets and underground storage caverns, we continue to use the deferral method to account for such costs.

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

Substantially all of our revenues are accounted for under ASC 606, Revenue from Contracts with Customers, however, to a limited extent, some revenues are accounted for under other guidance such as ASC 842, Leases, ASC 845, Nonmonetary Transactions, or ASC 815, Derivatives and Hedging Activities.

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.

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. 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.

Inventories

12 Months Ended

Dec. 31, 2020

Inventories [Abstract]

Inventories

Note 3. Inventories

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

	December 31,
	2020		2019
NGLs	$	1,888.1	$	1,094.9
Petrochemicals and refined products		642.6		311.5
Crude oil		758.1		674.2
Natural gas		14.7		10.8
Total	$	3,303.5	$	2,091.4

Inventories of NGLs, refined products and crude oil increased since December 31, 2019 primarily due to the use of working capital in connection with our marketing activities.

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,
	2020			2019			2018
Cost of sales (1)		$	16,723.2		$	22,065.8		$	26,789.8
Lower of cost or net realizable value adjustments recognized in cost of sales			60.2			22.7			11.5

(1)	Cost of sales is a component of “Operating costs and expenses,” as presented on our Statements of Consolidated Operations. Fluctuations in these amounts are primarily due to changes in energy commodity prices and sales volumes associated with our marketing activities.

Due to fluctuating commodity prices, we recognize lower of cost or 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

12 Months Ended

Dec. 31, 2020

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			2020		2019
Plants, pipelines and facilities (1)		3-45	(5)	$	49,972.8	$	47,201.2
Underground and other storage facilities (2)		5-40	(6)		4,207.5		3,965.5
Transportation equipment (3)		3-10			204.9		198.9
Marine vessels (4)		15-30			932.7		905.9
Land					371.9		372.3
Construction in progress					1,807.7		2,641.2
Total					57,497.5		55,285.0
Less accumulated depreciation					15,584.7		13,681.6
Property, plant and equipment, net				$	41,912.8	$	41,603.4

(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,
	2020		2019		2018
Depreciation expense (1)	$	1,681.9	$	1,562.6	$	1,436.2
Capitalized interest (2)		115.0		143.8		147.9

(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, 2020 and 2019 includes $69.7 million and $69.6 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,
	2020			2019			2018
ARO liability beginning balance	$	132.1		$	126.3		$	86.7
Liabilities incurred		4.6			5.0			24.4
Liabilities settled		(1.5	)		(2.3	)		(2.5	)
Revisions in estimated cash flows		6.1			(4.8	)		11.5
Accretion expense		8.2			7.9			6.2
ARO liability ending balance	$	149.5		$	132.1		$	126.3

The following table presents our forecast of ARO-related accretion expense for the years indicated:

2021				2022				2023				2024				2025
$	8.6			$	9.1			$	9.6			$	10.3			$	10.9

Impairments of Property, Plant and Equipment

The following table presents our non-cash asset impairment charges involving property, plant and equipment by business segment for the years indicated:

	For the Year Ended December 31,
	2020		2019		2018
NGL Pipelines & Services:
South Texas natural gas processing plants	$	86.9	$	15.6
Other		121.2		23.5	$	18.6
Crude Oil Pipelines & Services:
Cancellation of Midland-to-ECHO 4 project		42.2
Other		3.3		2.6		11.2
Natural Gas Pipelines & Services:
South Texas natural gas gathering pipelines		37.8
Other		5.5		4.8		13.9
Petrochemical & Refined Products Services:
Marine transportation business		252.1
Other		40.8		4.6		3.1
Total impairment charges for property, plant and equipment	$	589.8	$	51.1	$	46.8

The following information summarizes our significant asset impairment charges involving property, plant and equipment that were recognized during the year ended December 31, 2020:

•

In December 2020, we evaluated our marine transportation business for impairment due to a lower demand outlook for such services. As a result of our review, we recognized an impairment charge of $256.7 million, which reduced the carrying value of this asset group to its estimated fair value of $410.0 million at December 31, 2020. The impairment charge reduced property, plant and equipment by $252.1 million and intangible assets by $4.6 million. Our marine transportation assets, which consist of 65 tow boats, 160 tank barges and shipyard and repair facilities, serve refinery and storage terminal customers along the Mississippi River, the intracoastal waterway between Texas and Florida, and the Tennessee-Tombigbee waterway system.

•

In December 2020, we evaluated certain of our natural gas gathering and processing assets in South Texas for impairment due to a lower production outlook. As a result of our review, we recognized an aggregate impairment charge of $125.7 million, which reduced the total carrying value of these assets to their estimated fair value of $21.3 million at December 31, 2020. The impairment charge reduced property, plant and equipment by $124.7 million and intangible assets by $1.0 million. The natural gas assets impacted by this review were our Armstrong, Gilmore, Shilling and Indian Springs natural gas processing facilities and our Indian Springs and Big Thicket Gathering Systems.

•

In September 2020, we recognized $42.2 million of impairment expense due to our cancellation of the Midland-to-ECHO 4 pipeline construction project. In connection with the cancellation, we reclassified $311.7 million of pipe and related items that were purchased for the project from construction in progress to long-term spare parts, where they will be held for future use. Long-term spare parts is a component of “Other assets” as presented on our Consolidated Balance Sheet. While being held as long-term spare parts, these assets are depreciated over their expected useful lives as spare parts.

•

The remainder of our impairment charges for 2020 (i.e., those classified as “Other” in the preceding table) are attributable to the complete write-off of assets that are no longer expected to be used or constructed.

For information regarding our non-recurring fair value estimates for the marine transportation business and our South Texas natural gas gathering and processing assets, see Note 14.

Investments in Unconsolidated Affiliates

12 Months Ended

Dec. 31, 2020

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,
	2020	2020		2019
NGL Pipelines & Services:
Venice Energy Service Company, L.L.C. (“VESCO”)	13.1%	$	23.4	$	23.2
K/D/S Promix, L.L.C. (“Promix”)	50%		23.0		25.7
Baton Rouge Fractionators LLC (“BRF”)	32.2%		13.8		15.6
Skelly-Belvieu Pipeline Company, L.L.C. (“Skelly-Belvieu”)	50%		31.6		33.1
Texas Express Pipeline LLC (“Texas Express”)	35%		342.8		358.1
Texas Express Gathering LLC (“TEG”)	45%		37.7		41.1
Front Range Pipeline LLC (“Front Range”)	33.3%		199.3		207.0
Crude Oil Pipelines & Services:
Seaway Crude Holdings LLC (“Seaway”)	50%		1,224.0		1,353.1
Eagle Ford Pipeline LLC (“Eagle Ford Crude Oil Pipeline”)	50%		376.8		386.5
Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Corpus Christi”)	50%		122.9		126.9
Natural Gas Pipelines & Services:
White River Hub, LLC (“White River Hub”)	50%		18.2		19.1
Old Ocean Pipeline, LLC (“Old Ocean”)	50%		13.2		8.2
Petrochemical & Refined Products Services:
Baton Rouge Propylene Concentrator LLC (“BRPC”)	30%		1.6		2.0
Transport 4, LLC (“Transport 4”)	25%		0.9		0.6
Total		$	2,429.2	$	2,600.2

NGL Pipelines & Services

The principal business activity of each investee included in our NGL Pipelines & Services segment is described as follows:

•	VESCO owns the Venice natural gas processing facility and a related gathering system located in south Louisiana.

•	Promix owns an NGL fractionation facility and a related gathering system located in south Louisiana.

•	BRF owns an NGL fractionation facility located in south Louisiana.

•	Skelly-Belvieu owns a pipeline that transports mixed NGLs from Skellytown, Texas to Mont Belvieu, Texas.

•

Texas Express owns an NGL pipeline that extends from Skellytown to our Mont Belvieu NGL fractionation and storage complex. Mixed NGLs from the Rocky Mountains, Permian Basin and Mid-Continent regions are delivered to the Texas Express Pipeline via an interconnect with our Mid-America Pipeline System near Skellytown. In addition, mixed NGLs from the Denver-Julesburg (“DJ”) Basin in Colorado are delivered to the Texas Express Pipeline via an interconnect with the Front Range Pipeline near Skellytown. The Texas Express Pipeline is also used to transport mixed NGLs gathered by TEG to Mont Belvieu.

•	TEG owns two NGL gathering systems that deliver mixed NGLs to the Texas Express Pipeline.

•	Front Range owns an NGL pipeline that transports mixed NGLs from natural gas processing facilities located in the DJ Basin to an interconnect with our Texas Express Pipeline and Mid-America Pipeline System and other third party facilities near Skellytown.

Crude Oil Pipelines & Services

The principal business activity of each investee included in our Crude Oil Pipelines & Services segment is described as follows:

•

Seaway owns a crude oil pipeline system that connects the Cushing, Oklahoma hub, which is a major industry trading hub and price settlement point for West Texas Intermediate on the NYMEX, with markets in Southeast Texas. The Seaway Pipeline is comprised of the Longhaul System, the Freeport System and the Texas City System.

•

Eagle Ford Crude Oil Pipeline owns a pipeline that transports crude oil and condensate for producers in South Texas. The system originates in Gardendale, Texas and extends to Three Rivers, Texas and further to Corpus Christi, Texas. The system interconnects with our South Texas Crude Oil Pipeline System and a marine terminal owned by Eagle Ford Corpus Christi.

•	Eagle Ford Corpus Christi owns a marine crude oil terminal located in Corpus Christi, Texas that can load ocean-going vessels with either crude oil or condensate.

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 owns a natural gas hub facility serving producers in the Piceance Basin of northwest Colorado.

•	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 owns a propylene fractionation facility located in south Louisiana.

•	Transport 4 provides pipeline and terminal logistics services used by our refined products pipelines.

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,
	2020			2019			2018
NGL Pipelines & Services	$	121.3		$	114.5		$	117.0
Crude Oil Pipelines & Services		301.2			449.2			365.4
Natural Gas Pipelines & Services		5.8			6.3			6.8
Petrochemical & Refined Products Services (1)		(2.2	)		(7.0	)		(9.2	)
Total	$	426.1		$	563.0		$	480.0

(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.

Impairment of Investment in Unconsolidated Affiliate

In December 2019, we recorded a $76.4 million impairment charge to fully write off our 50% equity method investment in Centennial Pipeline LLC (“Centennial”), which owns the idled Centennial Pipeline and related terminal infrastructure. Due to declines in the viability of potential commercial transactions involving this former refined products pipeline, we concluded that our investment was not recoverable and had no fair value at December 31, 2019. The impairment charge is a component of operating costs and expenses for the year ended December 31, 2019 as presented on our Statements of Consolidated Operations. 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.

Intangible Assets and Goodwill

12 Months Ended

Dec. 31, 2020

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, 2020							December 31, 2019
	Gross Value		Accumulated Amortization			Carrying Value		Gross Value		Accumulated Amortization			Carrying Value
NGL Pipelines & Services:
Customer relationship intangibles	$	447.8	$	(221.3	)	$	226.5	$	447.8	$	(206.3	)	$	241.5
Contract-based intangibles		162.6		(55.0	)		107.6		162.6		(43.9	)		118.7
Segment total		610.4		(276.3	)		334.1		610.4		(250.2	)		360.2
Crude Oil Pipelines & Services:
Customer relationship intangibles		2,195.0		(291.6	)		1,903.4		2,203.5		(243.5	)		1,960.0
Contract-based intangibles		283.1		(249.9	)		33.2		276.9		(235.0	)		41.9
Segment total		2,478.1		(541.5	)		1,936.6		2,480.4		(478.5	)		2,001.9
Natural Gas Pipelines & Services:
Customer relationship intangibles		1,350.3		(512.2	)		838.1		1,350.3		(481.6	)		868.7
Contract-based intangibles		470.7		(403.8	)		66.9		468.0		(395.5	)		72.5
Segment total		1,821.0		(916.0	)		905.0		1,818.3		(877.1	)		941.2
Petrochemical & Refined Products Services:
Customer relationship intangibles		181.4		(68.3	)		113.1		181.4		(57.5	)		123.9
Contract-based intangibles		44.9		(24.6	)		20.3		46.0		(24.2	)		21.8
Segment total		226.3		(92.9	)		133.4		227.4		(81.7	)		145.7
Total intangible assets	$	5,135.8	$	(1,826.7	)	$	3,309.1	$	5,136.5	$	(1,687.5	)	$	3,449.0

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

	For the Year Ended December 31,
	2020		2019		2018
NGL Pipelines & Services	$	25.2	$	31.9	$	34.7
Crude Oil Pipelines & Services		71.5		92.7		87.8
Natural Gas Pipelines & Services		38.8		41.4		39.1
Petrochemical & Refined Products Services		7.7		8.7		8.7
Total	$	143.2	$	174.7	$	170.3

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

2021				2022				2023				2024				2025
$	144.5			$	161.3			$	169.0			$	165.1			$	163.5

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, 2020, the carrying value of our portfolio of customer relationship intangible assets was $3.08 billion, the principal components of which were as follows:

a	Weighted Average Remaining Amortization Period	December 31, 2020
a	Weighted Average Remaining Amortization Period	Gross Value		Accumulated Amortization		Carrying Value
Basin-specific customer relationships:
EFS Midstream (acquired 2015)	21.4 years	$	1,409.8	$	(188.1)	$	1,221.7
State Line and Fairplay (acquired 2010)	26.2 years		895.0		(224.0)		671.0
San Juan Gathering (acquired 2004)	18.8 years		331.3		(245.3)		86.0
General customer relationships:
Oiltanking (acquired 2014)	23.0 years		1,192.5		(162.6)		1,029.9

•

The EFS Midstream customer relationships provide us with long-term access to condensate and natural gas producers in the Eagle Ford Shale served by our EFS Midstream System. 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 customer relationships provide us with long-term access to natural gas producers served by our Haynesville and Fairplay Gathering Systems. 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 customer relationships provide us with long-term access to natural gas producers in the San Juan Basin served by our San Juan Gathering System.

•	The Oiltanking customer relationships provide us with long-term access to crude oil and refined products storage and terminal customers served at our Houston Ship Channel and Beaumont, Texas terminals.

In December 2020, we recognized $5.6 million of impairment charges attributable to customer relationship intangible assets in connection with our writedowns of the marine transportation business and certain South Texas natural gas processing and gathering assets (see Note 4).

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, 2020, the carrying value of our portfolio of contract-based intangible assets was $228.0 million, the principal components of which were as follows:

a	Weighted Average Remaining Amortization Period	December 31, 2020
a	Weighted Average Remaining Amortization Period	Gross Value		Accumulated Amortization		Carrying Value
Oiltanking customer contracts	3.0 years	$	293.3	$	(261.7)	$	31.6
Jonah natural gas gathering agreements	21.0 years		224.4		(175.8)		48.6
Delaware Basin natural gas processing contracts	6.0 years		82.6		(23.7)		58.9

•

The Oiltanking customer contracts represent the estimated value we assigned to crude oil storage and terminal agreements we acquired in 2014 associated with our Houston and Beaumont marine terminals. Amortization expense attributable to these contracts is recorded using a straight-line approach over the terms of the underlying contracts.

•

The Jonah natural gas gathering agreements represent the estimated value we assigned to natural gas gathering contracts acquired in 2001 associated with the Jonah Gathering System. Amortization expense attributable to these intangible assets is recorded using a units-of-production method based on gathering volumes.

•

The Delaware Basin natural gas processing contracts represent the estimated value we assigned to natural gas processing contracts we acquired in March 2018 in connection with our step acquisition of the remaining 50% member interest in Delaware Basin Gas Processing LLC (“Delaware Processing”) (see Note 12). Amortization expense attributable to these contracts is recorded using a straight-line approach over the terms of the underlying contracts.

Impairment of Goodwill

Goodwill represents the cost of acquired businesses in excess of the fair value of their net assets at acquisition. Our goodwill balance was $5.45 billion and $5.75 billion at December 31, 2020 and 2019, respectively.

Based on our most recent goodwill impairment test at December 31, 2020, the estimated fair value of each of our reporting units, with the exception of our natural gas pipelines and services reporting unit (as described below), was at least 10% in excess of its carrying value. The following table presents changes in the carrying amount of goodwill by business segment during the periods indicated:

	NGL Pipelines & Services		Crude Oil Pipelines & Services		Natural Gas Pipelines & Services			Petrochemical & Refined Products Services		Consolidated Total
Balance at December 31, 2018	$	2,651.7	$	1,841.0	$	296.3		$	956.2	$	5,745.2

Balance at December 31, 2019	$	2,651.7	$	1,841.0	$	296.3		$	956.2	$	5,745.2
Impairment of goodwill		–		–		(296.3	)		–		(296.3	)
Balance at December 31, 2020	$	2,651.7	$	1,841.0	$	–		$	956.2	$	5,448.9

In December 2020, management determined that the carrying value of our natural gas pipelines and services reporting unit exceeded its estimated fair value. This reporting unit, which reflects the operations of our Natural Gas Pipelines & Services business segment, includes our natural gas gathering and transmission pipelines, storage facilities and related marketing activities. The long-term outlook for natural gas production in certain supply basins such as the Rocky Mountains and East Texas is expected to remain lower for longer due to reduced drilling activity. In addition, the decline in pipeline revenues attributable to lower regional natural gas price spreads is expected to adversely impact the future cash flows of our transmission pipelines. These factors, coupled with an increase in the estimated rate of return required for such businesses by market participants, resulted in the fair value of this reporting unit being less than its carrying value at December 31, 2020. The resulting goodwill impairment charge of $296.3 million represents the entire amount of goodwill attributable to this reporting unit and is reflected as a component of operating costs and expenses for the year ended December 31, 2020 as presented on our Statements of Consolidated Operations.

We did not record any goodwill impairment charges during the years ended December 31, 2019 or 2018.

Debt Obligations

12 Months Ended

Dec. 31, 2020

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,
	2020			2019
EPO senior debt obligations:
Commercial Paper Notes, variable-rates	$	–		$	482.0
Senior Notes Q, 5.25% fixed-rate, due January 2020		–			500.0
Senior Notes Y, 5.20% fixed-rate, due September 2020		–			1,000.0
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
September 2020 364-Day Revolving Credit Agreement, variable-rate, due September 2021		–			–
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			1,250.0
Senior Notes AAA, 2.80% fixed-rate, due January 2030		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			1,250.0
Senior Notes BBB, 3.70% fixed-rate, due January 2051		1,000.0			–
Senior Notes DDD, 3.20% fixed-rate, due February 2052		1,000.0			–
Senior Notes NN, 4.95% fixed-rate, due October 2054		400.0			400.0
Senior Notes CCC, 3.95% fixed rate, due January 2060		1,000.0			–
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		27,500.0			25,232.0
EPO Junior Subordinated Notes C, variable-rate, due June 2067 (1)		232.2			232.2
EPO Junior Subordinated Notes D, fixed/variable-rate, due August 2077 (2)		700.0			700.0
EPO Junior Subordinated Notes E, fixed/variable-rate, due August 2077 (3)		1,000.0			1,000.0
EPO Junior Subordinated Notes F, fixed/variable-rate, due February 2078 (4)		700.0			700.0
TEPPCO Junior Subordinated Notes, variable-rate, due June 2067 (1)		14.2			14.2
Total principal amount of senior and junior debt obligations		30,146.4			27,878.4
Other, non-principal amounts		(280.7	)		(253.3	)
Less current maturities of debt		(1,325.0	)		(1,981.9	)
Total long-term debt	$	28,540.7		$	25,643.2

(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, 2020:

	Range of Interest Rates Paid	Weighted-Average Interest Rate Paid
Commercial Paper Notes	1.78% to 2.08%	1.86%
EPO Junior Subordinated Notes C and TEPPCO Junior Subordinated Notes	3.00% to 4.68%	3.66%

Amounts borrowed under EPO’s 364-Day and Multi-Year Revolving Credit Agreements bear interest, at its 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 EPO's debt ratings.

In July 2017, the Financial Conduct Authority in the U.K. announced a desire to phase out LIBOR as a benchmark by the end of June 2023. Financial industry working groups are developing replacement rates and methodologies to transition existing agreements that depend on LIBOR as a reference rate. We currently do not expect the transition from LIBOR to have a material impact on us.

The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations at December 31, 2020 for the next five years, and in total thereafter:

				Scheduled Maturities of Debt
	Total			2021			2022			2023			2024			2025			Thereafter
Senior Notes		$	27,500.0		$	1,325.0		$	1,400.0		$	1,250.0		$	850.0		$	1,150.0		$	21,525.0
Junior Subordinated Notes			2,646.4			–			–			–			–			–			2,646.4
Total		$	30,146.4		$	1,325.0		$	1,400.0		$	1,250.0		$	850.0		$	1,150.0		$	24,171.4

In February 2021, EPO notified its trustee and paying agent to redeem all of the $575.0 million outstanding principal amount of its Senior Notes RR effective as of March 15, 2021 (one month prior to their scheduled maturity in April 2021). These notes are redeemable at EPO’s election at par (i.e., at a redemption price equal to the outstanding principal amount of such notes to be redeemed, plus accrued and unpaid interest thereon). On a short term basis, the redemption of EPO’s Senior Notes RR is expected to be made using proceeds from the issuance of short term notes under EPO’s commercial paper program.

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 the Partnership. As of December 31, 2020, EPO had no short-term notes outstanding under its commercial paper program.

364-Day Revolving Credit Agreements

In September 2020, EPO entered into a new 364-Day Revolving Credit Agreement (the “September 2020 364-Day Revolving Credit Agreement”) that replaced its September 2019 364-Day Revolving Credit Agreement. Under the terms of the September 2020 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. The September 2020 364-Day Revolving Credit Agreement matures in September 2021. 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 2022. Borrowings under the September 2020 364-Day Revolving Credit Agreement may be used for working capital, capital expenditures, acquisitions and general company purposes.

The September 2020 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 September 2020 364-Day Revolving Credit Agreement also restricts EPO’s ability to pay cash distributions to the Partnership, 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 September 2020 364-Day Revolving Credit Agreement are not secured by any collateral; however, they are guaranteed by the Partnership.

Multi-Year Revolving Credit Agreement

EPO has entered into a multi-year revolving credit agreement (as amended, the “Multi-Year Revolving Credit Agreement”) that provides for a borrowing capacity of $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, with a maturity date of September 10, 2024. The maturity date may be extended at EPO’s request by up to two years, with the consent of required lenders as set forth under the credit agreement. Borrowings under the Multi-Year 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 the Partnership, 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 the Partnership.

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 $4.25 billion, $2.5 billion and $5.0 billion of senior notes during the years ended December 31, 2020, 2019 and 2018, respectively.

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”). Senior Notes AAA were issued at 99.921% of their principal amount and have a fixed rate of interest of 2.80% per year. Senior Notes BBB were issued at 99.413% of their principal amount and have a fixed rate of interest of 3.70% per year. Senior Notes CCC were issued at 99.360% of their principal amount and have a fixed rate of interest of 3.95% per year. Net proceeds from the January 2020 senior notes offering were used by EPO for the repayment of $500.0 million principal amount of its Senior Notes Q that matured in January 2020, the repayment of amounts outstanding under its commercial paper program and for general company purposes. In addition, net proceeds from this offering were used by EPO for the repayment of $1.0 billion principal amount of its Senior Notes Y that matured in September 2020.

In August 2020, EPO issued $1.0 billion in principal amount of senior notes due February 2052 (“Senior Notes DDD”) and $250.0 million in principal amount of reopened Senior Notes AAA. The reopened Senior Notes AAA form a single series with the original notes of that series, trade under the same CUSIP number, and have the same terms as to status, redemption or otherwise as the original notes of that series. The reopened Senior Notes AAA were issued at 107.211% of their principal amount and have a fixed rate of interest of 2.80% per year. Senior Notes DDD were issued at 99.233% of their principal amount and have a fixed rate of interest of 3.20% per year. Net proceeds from the issuance of these senior notes were used for general company purposes, including for growth capital investments, and to repay a portion of the $750.0 million in principal amount of Senior Notes TT that matured in February 2021.

EPO’s senior notes are unconditionally guaranteed on an unsecured and unsubordinated basis by the Partnership.

EPO Junior Subordinated Notes

EPO’s payment obligations under its junior subordinated notes (“junior notes”) are subordinated to all of its current and future senior indebtedness. The indenture agreement governing the junior 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 the Partnership 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 with or are subordinate to the junior notes. Each series of EPO’s junior notes rank equal with each other and generally are not redeemable by EPO while such notes bear interest at a fixed annual rate. EPO issued $700.0 million of junior notes during the year ended December 31, 2018.

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.

EPO’s junior notes are unconditionally guaranteed on an unsecured and subordinated basis by the Partnership.

EPO repurchased and retired $24.2 million in principal amount of its Junior Subordinated Notes C in 2019. 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, 2020, EPO had $200.7 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, 2020.

Capital Accounts

12 Months Ended

Dec. 31, 2020

Capital Accounts [Abstract]

Equity and Distributions

Note 8. Capital Accounts

Common Limited Partner Interests

The following table summarizes changes in the number of our common units outstanding since December 31, 2017:

Common units outstanding at December 31, 2017	2,161,089,479
Common unit repurchases under Legacy Buyback Program	(1,236,800	)
Common units issued in connection with DRIP and EUPP	19,861,951
Common units issued in connection with the vesting of phantom unit awards, net	2,442,436
Common units issued in connection with employee compensation	1,443,586
Common units issued in connection with land acquisition	1,223,242
Other	45,135
Common units outstanding at December 31, 2018	2,184,869,029
Common unit repurchases under 2019 Buyback Program	(2,909,128	)
Common units issued in connection with DRIP and EUPP	2,897,990
Common units issued in connection with the vesting of phantom unit awards, net	2,720,603
Common units issued in connection with employee compensation	1,626,041
Other	21,595
Common units outstanding at December 31, 2019	2,189,226,130
Common units issued to Skyline North Americas, Inc. in connection with settlement of Liquidity Option in March 2020	54,807,352
Treasury units acquired in connection with settlement of the Liquidity Option in March 2020	(54,807,352	)
Common unit repurchases under 2019 Buyback Program	(8,978,317	)
Common units issued in connection with the vesting of phantom unit awards, net	3,162,095
Common units exchanged for preferred units in September 2020, with the common units received being immediately cancelled	(1,120,588	)
Other	19,638
Common units outstanding at December 31, 2020	2,182,308,958

The Partnership’s common units represent limited partner interests that give the holders thereof the right to participate in distributions and to exercise the other rights or privileges available to them under our Seventh Amended and Restated Agreement of Limited Partnership (as amended from time to time, the “Partnership Agreement”). In accordance with the 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 balances presented in our consolidated financial statements prepared in accordance with GAAP. Partnership earnings and cash distributions are allocated to holders of our common units in accordance with their respective percentage interests.

Registration Statements

We have a universal shelf registration statement (the “2019 Shelf”) on file with the SEC which allows the Partnership and EPO (each on a standalone basis) to issue an unlimited amount of equity and debt securities, respectively. EPO issued $4.25 billion of senior notes during 2020 using the 2019 Shelf (see Note 7).

In addition, the Partnership has a registration statement on file with the SEC covering the issuance of up to $2.54 billion of its common units in amounts, at prices and on terms based on market conditions and other factors at the time of such offerings (referred to as the Partnership’s at-the-market (“ATM”) program). The Partnership did not issue any common units under its ATM program during the three years ended December 31, 2020. The Partnership’s capacity to issue additional common units under the ATM program remains at $2.54 billion as of December 31, 2020.

We may issue additional equity and debt securities to assist us in meeting our future liquidity requirements, including those related to capital investments.

Issuance of Common Units due to Settlement of Liquidity Option in March 2020

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. (currently known as OTA Holdings, 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, as amended (the “Securities Act”), 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, we 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 of M&B’s election to exercise its rights under the Liquidity Option Agreement. On March 5, 2020, the Partnership settled its obligations under the Liquidity Option Agreement by issuing 54,807,352 new common units to Skyline North Americas, Inc. (“Skyline,” an affiliate of M&B) in exchange for the capital stock of OTA. As a result of the settlement, OTA became a consolidated subsidiary of ours and we indirectly acquired the 54,807,352 Partnership common units owned by OTA and assumed all future income tax obligations of OTA, including its deferred tax liability.

As a result of the Liquidity Option settlement, the partners’ equity balance for common units (as presented on our Consolidated Balance Sheet) increased by $1.30 billion, representing the market value of the 54,807,352 Partnership common units issued to Skyline on March 5, 2020 at a closing price of $23.67 per unit. Since OTA did not meet the definition of a business as described in ASC 805, Business Combinations, the OTA transaction was accounted for by the Partnership as the reacquisition of common units and the assumption of OTA’s related deferred tax liability. In consolidation, we present the common units owned by OTA as treasury units, with their historical cost equal to the $1.30 billion market value of the Partnership common units issued to Skyline. On September 30, 2020, OTA exchanged the common units it holds for preferred units issued by the Partnership. For information regarding the preferred units and exchange transaction, see “Redeemable Preferred Limited Partner Interests” within this Note 8.

The common units issued to Skyline upon settlement of the Liquidity Option constitute “restricted securities” in the meaning of Rule 144 under the Securities Act and may not be resold except pursuant to an effective registration statement or an available exemption under the Securities Act. In connection with the settlement of the Liquidity Option, the Partnership entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with Skyline. Pursuant to the Registration Rights Agreement, Skyline has the right to request that the Partnership prepare and file a registration statement to permit and otherwise facilitate the public resale of all or a portion of the Partnership’s common units owned by Skyline and its affiliates. The Partnership’s obligation to Skyline to effect such transactions is limited to five registration statements and underwritten offerings. In May 2020, the Partnership filed a registration statement on behalf of Skyline for the resale of up to 54,807,352 common units. This registration statement is effective and, in June 2020, the Partnership filed a prospectus supplement to this registration statement that allows Skyline to sell up to $500 million of the Partnership’s common units it owns in connection with an “at-the-market” program that it administers. We do not receive any proceeds from such offerings.

Upon settlement of the Liquidity Option on March 5, 2020, the Liquidity Option liability was effectively replaced by the deferred tax liability of OTA as calculated in accordance with ASC 740, Income Taxes. See Note 16 for additional information regarding OTA’s deferred tax liability. For information regarding the Liquidity Option prior to its settlement, see Note 17.

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 the Partnership with an additional method to return capital to investors. The 2019 Buyback Program authorizes the Partnership to repurchase its common units from time to time, including through open market purchases and negotiated transactions. No time limit has been set for completion of the program, and it may be suspended or discontinued at any time.

The Partnership repurchased 8,978,317 common units under the 2019 Buyback Program through open market and private purchases during the year ended December 31, 2020. The total purchase price of these repurchases was $186.3 million including commissions and fees. During the year ended December 31, 2019, the Partnership repurchased 2,909,128 common units under the 2019 Buyback Program for a total purchase price of $81.1 million including commissions and fees. Units repurchased under the 2019 Buyback Program are immediately cancelled upon acquisition. At December 31, 2020, the remaining available capacity under the 2019 Buyback Program was $1.73 billion.

In December 1998, we announced a common unit buyback program whereby we, together with certain affiliates, could repurchase up to 4,000,000 of the Partnership’s common units on the open market (the “Legacy Buyback Program”). The Partnership purchased the remaining authorized amount of 1,236,800 common units in December 2018 for $30.8 million. Units repurchased under the Legacy Buyback Program were immediately cancelled upon acquisition.

Common Units Delivered Under DRIP and EUPP

The Partnership has registration statements on file with the SEC in connection with its distribution reinvestment plan (“DRIP”) and employee unit purchase plan (“EUPP”). In July 2019, the Partnership announced that, beginning with the quarterly distribution payment 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. Agents of the Partnership purchased 6,982,963 common units and 2,801,196 common units on the open market and delivered them to participants in the DRIP and EUPP during the year ended December 31, 2020 and five months ended December 31, 2019, respectively. Apart from $2.4 million and $0.9 million attributable to the plan discount available to all participants in the EUPP during 2020 and 2019, respectively, the funds used to effect these purchases were sourced from the DRIP and EUPP participants. No other Partnership funds were used to satisfy these obligations. We used open market purchases to satisfy DRIP and EUPP reinvestments in connection with the distribution paid on February 11, 2021.

Prior to July 2019, the Partnership satisfied its delivery obligations under the DRIP and EUPP by issuing new common units to participants. An aggregate 2,897,990 common units and 19,861,951 common units were issued to DRIP and EUPP participants during the seven months ended July 31, 2019 and year ended December 31, 2018, respectively. These transactions generated net cash proceeds of $82.2 million in 2019 and $538.4 million in 2018. Privately held affiliates of EPCO reinvested $29 million and $213 million through the DRIP in each of the years ended December 31, 2019 and 2018, 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, 2020, we have the capacity to deliver an additional 50,615,246 common units under this plan. Likewise, we have the capacity to deliver an additional 3,318,607 common units under the EUPP.

Common Units Issued in Connection With the Vesting of Phantom Unit Awards

After taking into account tax withholding requirements, the Partnership issued 3,162,095, 2,720,603 and 2,442,436 new common units to employees in connection with the vesting of phantom unit awards during the years ended December 31, 2020, 2019 and 2018, respectively. See Note 13 for information regarding our phantom unit awards.

Common Units Issued in Connection With Employee Compensation

In February 2019 and 2018, 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 Partnership 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. 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 Partnership common units.

Redeemable Preferred Limited Partner Interests

The following table summarizes changes in the number of our preferred units outstanding during the year ended December 31, 2020:

Original issuance of preferred units on September 30, 2020:
Units sold to third party purchasers			35,000
Units sold to a related party			15,000
Total preferred units outstanding at September 30, 2020			50,000
Paid-in kind distribution to related party			138
Preferred units outstanding at December 31, 2020			50,138

On September 30, 2020, the Partnership issued and sold an aggregate of 50,000 Series A Cumulative Convertible Preferred Units in a private placement transaction. The preferred units represent a new class of limited partner interests authorized under the Partnership Agreement. The stated value of each preferred unit is $1,000 per unit. The total offering price for the preferred units was $50.0 million, of which $32.5 million was received in cash with the remaining $17.5 million funded through the exchange of 1,120,588 of the Partnership’s common units owned by the purchasers. Cash proceeds from the preferred unit offering include $15.0 million received from a privately held affiliate of EPCO for the purchase of 15,000 preferred units. Offering expenses were approximately $1.0 million.

Concurrently, the Partnership exchanged all of the 54,807,352 Partnership common units owned directly by OTA for 855,915 of the Partnership’s new preferred units having an equivalent value. The preferred units held by OTA, like the common units OTA held prior to the exchange, are accounted for as treasury units by the Partnership in consolidation. The historical cost of the treasury units did not change as a result of the exchange and remains at the $1.30 billion recognized on March 5, 2020 in connection with settlement of the Liquidity Option.

As described in the Partnership Agreement, key terms of the preferred units include the following:

•

With respect to distribution and liquidation rights, the preferred units rank senior to the Partnership’s common units. Preferred units held by persons other than the Partnership, its subsidiaries and its affiliates generally will vote on an as-converted basis with the Partnership’s common units and have certain class voting rights with respect to certain protective matters.

•

Holders of the preferred units are entitled to receive cumulative quarterly distributions at a rate of 7.25% per annum. The Partnership is prohibited from paying distributions on its common units unless full cumulative distributions on the preferred units are paid or set aside for payment. The Partnership may satisfy its obligation to pay distributions to the preferred unitholders through the issuance, in whole or in part, of additional preferred units (referred to as paid-in kind or “PIK” distributions), with the remainder in cash, subject to certain rights of a holder to elect all cash and other conditions as described in the Partnership Agreement. The exchange by OTA of its common units for PIK-eligible preferred units enables the Partnership to more effectively manage its consolidated cash balances.

In November 2020, the Partnership made its first quarterly distribution to third party and related party preferred unitholders. The distribution was valued at $0.5 million, consisting of PIK distributions of 138 new preferred units and $0.3 million in cash.

•

Subject to certain limitations, each preferred unitholder may elect to convert its preferred units on or after September 30, 2025 into a number of the Partnership’s common units equal to (a) the number of preferred units to be converted multiplied by (b) the quotient of (i) $1,000 plus any accrued and unpaid distributions per preferred unit, divided by (ii) 92.5% of the volume-weighted average price of the Partnership’s common units at the time of conversion (as defined in the underlying agreements). In addition, each preferred unitholder may convert its preferred units into common units if EPO’s senior notes cease to have an investment grade rating or a Change of Control (as defined in the Partnership Agreement) occurs, in each case based on the conversion ratio specified in the Partnership Agreement.

•	The Partnership may elect to redeem the preferred units for cash, in whole or in part, based on a redemption price outlined in the following schedule, plus any accrued and unpaid distributions at the redemption date:

•	$1,100 per preferred unit from September 30, 2020 through September 29, 2022;

•	$1,070 per preferred unit from September 30, 2022 through September 29, 2024;

•	$1,030 per preferred unit from September 30, 2024 through September 29, 2025;

•	$1,010 per preferred unit from September 30, 2025 through September 29, 2026; and

•	$1,000 per preferred unit on or after September 30, 2026; however,

•	if a Change of Control event occurs prior to September 30, 2026, the redemption price is $1,010 per preferred unit.

In connection with a redemption at the Partnership’s election, the Partnership may convert up to 50% of the preferred units being redeemed into common units (and to pay cash with respect to the remainder), with each such preferred unit being converted on the applicable redemption date into a number of common units equal to (i) the then-applicable preferred unit redemption price divided by (ii) 92.5% of the volume-weighted average price of the Partnership’s common units at the time of conversion (as defined in the underlying agreements).

The Partnership has agreed to prepare and file a registration statement that would permit or otherwise facilitate the public resale of any common units resulting from the conversion of the preferred units to common units.

Our Consolidated Balance Sheet at December 31, 2020 presents the capital accounts of the third-party and related party purchasers of the preferred units as mezzanine equity since the terms of the preferred units allow for cash redemption by the holders in a Change of Control event, without regard to the likelihood of such an event. The preferred units held by OTA are presented as treasury units in consolidation since their ultimate disposition remains under the control of the Partnership.

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, 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
Other comprehensive income (loss) for period, before reclassifications		124.4			(127.5	)		(0.1	)		(3.2	)
Reclassification of losses (gains) to net income during period		(272.7	)		39.3			–			(233.4	)
Total other comprehensive income (loss) for period		(148.3	)		(88.2	)		(0.1	)		(236.6	)
Accumulated Other Comprehensive Income (Loss), December 31, 2020	$	(93.2	)	$	(74.3	)	$	2.3		$	(165.2	)

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	2020			2019
Interest rate derivatives	Interest expense	$	39.3		$	37.3
Commodity derivatives	Revenue		(282.6	)		(152.4	)
Commodity derivatives	Operating costs and expenses		9.9			10.7
Total		$	(233.4	)	$	(104.4	)

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. The following table presents the components of noncontrolling interests as reported on our Consolidated Balance Sheets at the dates indicated:

	At December 31,
Consolidated Subsidiary	2020		2019
Breviloba LLC (“Breviloba”)(1)	$	480.4	$	492.9
Whitethorn Pipeline Company LLC (“Whitethorn”)(2)		193.0		198.9
Enterprise Navigator Ethylene Terminal LLC (“ENET”)(3)		142.2		124.3
Other (4)		257.7		247.4
Total noncontrolling interests in consolidated subsidiaries	$	1,073.3	$	1,063.5

(1)	Altus Midstream Processing LP acquired a noncontrolling 33% equity interest in Breviloba, which owns the Shin Oak NGL Pipeline, in July 2019 for $440.7 million in cash.
(2)	An affiliate of Western Gas Partners, LP acquired a noncontrolling 20% equity interest in Whitethorn, which owns the majority of our Midland-to-ECHO 1 pipeline, in June 2018 for $189.6 million in cash.
(3)	Navigator Ethylene Terminals LLC owns a noncontrolling 50% equity interest in ENET, which owns our ethylene export terminal located at Morgan’s Point on the Houston Ship Channel.
(4)	Primarily represents noncontrolling equity interests in NGL fractionation and pipeline businesses.

Net income attributable to noncontrolling interests was $110.1 million, $95.8 million and $66.1 million for the years ended December 31, 2020, 2019 and 2018, respectively.

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.

	Quarterly Distribution Per Common Unit		Record Date	Payment Date
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
2020:
1st Quarter	$	0.4450	4/30/2020	5/12/2020
2nd Quarter	$	0.4450	7/31/2020	8/12/2020
3rd Quarter	$	0.4450	10/30/2020	11/12/2020
4th Quarter	$	0.4500	1/29/2021	2/11/2021

On January 7, 2021, we announced that the Board of Enterprise GP declared a quarterly cash distribution of $0.45 per common unit with respect to the fourth quarter of 2020. The quarterly distribution was paid on February 11, 2021 to unitholders of record as of the close of business on January 29, 2021. The total amount paid was $988.8 million, which includes $7.1 million for distribution equivalent rights on phantom unit awards.

Revenues

12 Months Ended

Dec. 31, 2020

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,
	2020		2019		2018
NGL Pipelines & Services:
Sales of NGLs and related products	$	8,970.7	$	10,934.3	$	12,920.9
Segment midstream services:
Natural gas processing and fractionation		757.3		1,069.9		1,341.0
Transportation		1,036.8		1,054.3		1,007.0
Storage and terminals		412.4		412.2		380.0
Total segment midstream services		2,206.5		2,536.4		2,728.0
Total NGL Pipelines & Services		11,177.2		13,470.7		15,648.9
Crude Oil Pipelines & Services:
Sales of crude oil		5,410.8		9,007.8		10,001.2
Segment midstream services:
Transportation		804.9		801.8		676.5
Storage and terminals		473.3		477.7		364.9
Total segment midstream services		1,278.2		1,279.5		1,041.4
Total Crude Oil Pipelines & Services		6,689.0		10,287.3		11,042.6
Natural Gas Pipelines & Services:
Sales of natural gas		1,530.5		2,075.4		2,411.7
Segment midstream services:
Transportation		1,022.6		1,094.0		1,042.7
Total segment midstream services		1,022.6		1,094.0		1,042.7
Total Natural Gas Pipelines & Services		2,553.1		3,169.4		3,454.4
Petrochemical & Refined Products Services:
Sales of petrochemicals and refined products		5,942.6		4,985.2		5,535.4
Segment midstream services:
Fractionation and isomerization		187.7		166.6		188.3
Transportation, including marine logistics		482.9		539.4		481.8
Storage and terminals		167.2		170.6		182.8
Total segment midstream services		837.8		876.6		852.9
Total Petrochemical & Refined Products Services		6,780.4		5,861.8		6,388.3
Total consolidated revenues	$	27,199.7	$	32,789.2	$	36,534.2

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.

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 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 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.

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.

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.

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	2020		2019
Unbilled revenue (current amount)	Prepaid and other current assets	$	18.8	$	17.6
Total		$	18.8	$	17.6

		December 31,
Contract Liability	Location	2020		2019
Deferred revenue (current amount)	Other current liabilities	$	145.3	$	117.9
Deferred revenue (noncurrent)	Other long-term liabilities		198.2		197.0
Total		$	343.5	$	314.9

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 (2)		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 (2)		340.0			539.8
Amounts recorded during period transferred to other accounts (1)		(322.4	)		(384.8	)
Other changes		–			(4.9	)
Balance at December 31, 2019	$	17.6		$	314.9
Amount included in opening balance transferred to other accounts during period (1)		(17.6	)		(114.5	)
Amount recorded during period (2)		323.0			661.2
Amounts recorded during period transferred to other accounts (1)		(304.2	)		(496.7	)
Other changes		–			(21.4	)
Balance at December 31, 2020	$	18.8		$	343.5

(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.
(2)	Unbilled revenue represents revenue that has been recognized upon satisfaction of a performance obligation, but cannot be contractually invoiced (or billed) to the customer at the balance sheet date until a future period. Deferred revenue is recorded when payment is received from a customer prior to our satisfaction of the associated performance obligation.

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, 2020.

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, 2021	$	3,906.4
One Year Ended December 31, 2022		3,492.3
One Year Ended December 31, 2023		3,110.2
One Year Ended December 31, 2024		2,937.3
One Year Ended December 31, 2025		2,636.5
Thereafter		12,912.5
Total	$	28,995.2

- Definition

The entire disclosure of revenue from contract with customer to transfer good or service and to transfer nonfinancial asset. Includes, but is not limited to, disaggregation of revenue, credit loss recognized from contract with customer, judgment and change in judgment related to contract with customer, and asset recognized from cost incurred to obtain or fulfill contract with customer. Excludes insurance and lease contracts.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-URI http://asc.fasb.org/topic&trid=49130388

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 10
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130551-203045

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 13
-Subparagraph (b)(2)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130556-203045

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130554-203045

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 9
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130550-203045

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (e)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130554-203045

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130554-203045

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (d)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130554-203045

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 15
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130558-203045

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (c)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130554-203045

+ Details

Business Segments

12 Months Ended

Dec. 31, 2020

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 includes our natural gas processing and related NGL marketing activities, NGL pipelines, NGL fractionation facilities, NGL and related product storage facilities, and NGL marine terminals.

•	Our Crude Oil Pipelines & Services business segment includes our crude oil pipelines, crude oil storage and marine terminals, and related crude oil marketing activities.

•	Our Natural Gas Pipelines & Services business segment includes our natural gas pipeline systems that provide for the gathering, treating and transportation of natural gas. This segment also includes our natural gas marketing activities.

•

Our Petrochemical & Refined Products Services business segment includes our (i) propylene production facilities, which include propylene fractionation units and a PDH facility, and related pipelines and marketing activities, (ii) butane isomerization complex and related deisobutanizer (“DIB”) operations, (iii) octane enhancement, iBDH and HPIB production facilities, (iv) refined products pipelines, terminals and related marketing activities, (v) an ethylene export terminal and related operations; and (vi) marine transportation business.

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,
	2020			2019			2018
Operating income	$	5,035.1		$	6,078.7		$	5,408.6
Adjustments to reconcile operating income to total segment gross operating margin (addition or subtraction indicated by sign):
Depreciation, amortization and accretion expense in operating costs and expenses		1,961.5			1,848.3			1,687.0
Asset impairment and related charges in operating costs and expenses		890.6			132.7			50.5
Net gains attributable to asset sales in operating costs and expenses		(4.4	)		(5.7	)		(28.7	)
General and administrative costs		219.6			211.7			208.3
Non-refundable payments received from shippers attributable to make-up rights (1)		119.3			47.0			21.5
Subsequent recognition of revenues attributable to make-up rights (2)		(33.6	)		(22.9	)		(56.2	)
Total segment gross operating margin	$	8,188.1		$	8,289.8		$	7,291.0

(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,
	2020		2019		2018
Gross operating margin by segment:
NGL Pipelines & Services	$	4,182.4	$	4,069.8	$	3,830.7
Crude Oil Pipelines & Services		1,997.3		2,087.8		1,511.3
Natural Gas Pipelines & Services		926.6		1,062.6		891.2
Petrochemical & Refined Products Services		1,081.8		1,069.6		1,057.8
Total segment gross operating margin	$	8,188.1	$	8,289.8	$	7,291.0

Summarized Segment Financial Information

Information by business segment, together with reconciliations to amounts presented on, or included in, 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, 2020	$	11,170.6	$	6,668.8	$	2,543.2	$	6,780.4		$	–		$	27,163.0
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
Revenues from related parties:
Year ended December 31, 2020		6.6		20.2		9.9		–			–			36.7
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
Intersegment and intrasegment revenues:
Year ended December 31, 2020		29,010.3		24,531.3		460.1		5,379.4			(59,381.1	)		–
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	)		–
Total revenues:
Year ended December 31, 2020		40,187.5		31,220.3		3,013.2		12,159.8			(59,381.1	)		27,199.7
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
Equity in income (loss) of unconsolidated affiliates:
Year ended December 31, 2020		121.3		301.2		5.8		(2.2	)		–			426.1
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

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: (see Note 4)
At December 31, 2020	$	17,128.3	$	6,982.6	$	8,465.8	$	7,528.4	$	1,807.7	$	41,912.8
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
Investments in unconsolidated affiliates: (see Note 5)
At December 31, 2020		671.6		1,723.7		31.4		2.5		–		2,429.2
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
Intangible assets, net: (see Note 6)
At December 31, 2020		334.1		1,936.6		905.0		133.4		–		3,309.1
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
Goodwill: (see Note 6)
At December 31, 2020		2,651.7		1,841.0		–		956.2		–		5,448.9
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
Segment assets:
At December 31, 2020		20,785.7		12,483.9		9,402.2		8,620.5		1,807.7		53,100.0
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

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,
	2020			2019			2018
Consolidated revenues:
NGL Pipelines & Services	$	11,177.2		$	13,470.7		$	15,648.9
Crude Oil Pipelines & Services		6,689.0			10,287.3			11,042.6
Natural Gas Pipelines & Services		2,553.1			3,169.4			3,454.4
Petrochemical & Refined Products Services		6,780.4			5,861.8			6,388.3
Total consolidated revenues	$	27,199.7		$	32,789.2		$	36,534.2

Consolidated costs and expenses:
Operating costs and expenses:
Cost of sales	$	16,723.2		$	22,065.8		$	26,789.8
Other operating costs and expenses (1)		2,800.2			3,020.7			2,898.7
Depreciation, amortization and accretion		1,961.5			1,848.3			1,687.0
Impairment of goodwill		296.3			–			–
Impairment of assets other than goodwill		594.3			132.7			50.5
Net gains attributable to asset sales		(4.4	)		(5.7	)		(28.7	)
General and administrative costs		219.6			211.7			208.3
Total consolidated costs and expenses	$	22,590.7		$	27,273.5		$	31,605.6

(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.

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.

Major Customer Information

Substantially all of our consolidated revenues are earned in the U.S. and derived from a wide customer base. No single customer accounted for 10% or more of our consolidated revenues (thus constituting a “major customer”) during the years ended December 31, 2020 or 2018. However, Vitol Holding B.V. and its affiliates (collectively, “Vitol”) accounted for $3.31 billion, or 10.1%, of our consolidated revenues during the year ended December 31, 2019. Vitol is a global energy and commodity trading company. The following table presents our consolidated revenues from Vitol by business segment for the year ended December 31, 2019:

NGL Pipelines & Services	$	1,410.8
Crude Oil Pipelines & Services		1,670.7
Natural Gas Pipelines & Services		31.2
Petrochemical & Refined Products Services		202.1
Total	$	3,314.8

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 31
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8924-108599

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
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Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
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-Paragraph 21
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Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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Reference 5: http://www.xbrl.org/2003/role/disclosureRef
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Reference 6: http://www.xbrl.org/2003/role/disclosureRef
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Reference 7: http://www.xbrl.org/2003/role/disclosureRef
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Reference 8: http://www.xbrl.org/2003/role/disclosureRef
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Reference 9: http://www.xbrl.org/2003/role/disclosureRef
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Reference 12: http://www.xbrl.org/2003/role/disclosureRef
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Reference 13: http://www.xbrl.org/2003/role/disclosureRef
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Reference 14: http://www.xbrl.org/2003/role/disclosureRef
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+ Details

Earnings Per Unit

12 Months Ended

Dec. 31, 2020

Earnings Per Unit [Abstract]

Earnings Per Unit

Note 11. Earnings Per Unit

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

	For the Year Ended December 31,
	2020			2019			2018
BASIC EARNINGS PER COMMON UNIT
Net income attributable to common unitholders	$	3,774.7		$	4,591.3		$	4,172.4
Earnings allocated to phantom unit awards (1)		(32.0	)		(27.7	)		(21.5	)
Net income allocated to common unitholders	$	3,742.7		$	4,563.6		$	4,150.9

Basic weighted-average number of common units outstanding		2,185.8			2,188.6			2,176.5

Basic earnings per common unit	$	1.71		$	2.09		$	1.91

DILUTED EARNINGS PER COMMON UNIT
Net income attributable to common unitholders	$	3,774.7		$	4,591.3		$	4,172.4
Net income attributable to preferred units		0.9			–			–
Net income attributable to limited partners	$	3,775.6		$	4,591.3		$	4,172.4

Diluted weighted-average number of units outstanding:
Distribution-bearing common units		2,185.8			2,188.6			2,176.5
Phantom units (2)		15.7			13.1			10.5
Preferred units (2)		0.7			–			–
Total		2,202.2			2,201.7			2,187.0

Diluted earnings per common unit	$	1.71		$	2.09		$	1.91

(1)	Phantom units are considered participating securities for purposes of computing basic earnings per unit. See Note 13 for information regarding our phantom units.
(2)	We use the “if-converted method” to determine the potential dilutive effect of the vesting of phantom units and the conversion of preferred units outstanding. See Note 8 for information regarding the preferred units issued during 2020.

Business Combinations

12 Months Ended

Dec. 31, 2020

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 year ended December 31, 2018 would not have differed materially from those we reported had the acquisition been completed on January 1, 2018 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.

Equity-Based Awards

12 Months Ended

Dec. 31, 2020

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,
	2020		2019		2018
Equity-classified awards:
Phantom unit awards	$	150.3	$	132.2	$	99.7
Profits interest awards		8.7		11.6		6.1
Liability-classified awards		0.1		0.1		0.3
Total	$	159.1	$	143.9	$	106.1

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 (1)
Phantom unit awards at December 31, 2017		9,289,501		$	27.65
Granted (2)		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 (3)		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
Granted (4)		7,405,245		$	25.71
Vested		(4,532,269	)	$	26.35
Forfeited		(178,218	)	$	26.73
Phantom unit awards at December 31, 2020		15,669,442		$	26.76

(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 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 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.
(4)	The aggregate grant date fair value of phantom unit awards issued during 2020 was $190.4 million based on a grant date market price of EPD common units ranging from $16.95 to $25.76 per unit. An estimated annual forfeiture rate of 2.4% 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 55,000,000 at December 31, 2020. This amount automatically increased under the terms of the 2008 Plan by 5,000,000 common units on January 1, 2021 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, 2020, a total of 16,229,995 additional common units were available for issuance. After taking into account tax withholding requirements, we issued 3,162,095, 2,720,603 and 2,442,436 common units in connection with the vesting of phantom unit awards in the years ended December 31, 2020, 2019 and 2018, 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,
	2020		2019		2018
Cash payments made in connection with DERs	$	27.1	$	22.1	$	17.7
Total intrinsic value of phantom unit awards that vested during period	$	114.8	$	111.1	$	90.7

For the EPCO group of companies, the unrecognized compensation cost associated with phantom unit awards was $156.7 million at December 31, 2020, of which our share of such cost is currently estimated to be $129.6 million. Due to the graded vesting provisions of these awards, we expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 2.0 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. The Class B limited partner interests of PubCo I vested in February 2020.

In September 2020, the partners of PubCo II and PrivCo I amended their respective limited partnership agreements to provide for the vesting of their Class B limited partner interests on the earlier of (i) February 22, 2023, (ii) the first date on or after September 30, 2020 on which the closing market price of the Partnership’s common units is equal to or greater than $25.41 per unit, (iii) a change of control event, or (iv) dissolution of the applicable Employee Partnership. As a result of these modifications, PubCo II and PrivCo I will recognize incremental compensation cost of $1.2 million and $0.5 million, respectively, through February 22, 2023.

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, 2020:

Employee Partnership	Partnership Common Units Contributed by EPCO Holdings	Class A Capital Base (1)	Class A Preference Return	Expected Vesting/ Liquidation Date	Estimated Fair Value of Profits Interest Awards (2)	Unrecognized Compensation Cost (3)
PubCo II	2,834,198	$66.3 million	$0.3900	February 2023	$2.5 million	$2.3 million
PrivCo I	1,111,438	$26.0 million	$0.3900	February 2023	$0.9 million	$0.2 million
EPD IV	6,400,000	$172.9 million	$0.4325	December 2023	$26.7 million	$13.6 million
EPCO II	1,600,000	$43.2 million	$0.4325	December 2023	$6.6 million	$0.3 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 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. The fair value is as of the grant date or as of the plan modification date, as applicable.
(3)	Represents our expected share of the unrecognized compensation cost at December 31, 2020. 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 2.1 years, 2.1 years, 2.9 years and 2.9 years, respectively.

The fair value of each Employee Partnership (at either the grant date or modification date) is based on (i) the estimated value (as determined using a Black-Scholes option pricing model or Monte Carlo model, as applicable) 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 or Monte Carlo model, as applicable, to derive that portion of the estimated fair value of the profits interest awards (at either the grant date or modification date) for each Employee Partnership:

	Expected Life	Risk-Free	Expected	Expected Unit
Employee	of Award	Interest	Distribution	Price
Partnership	from Grant Date	Rate	Yield	Volatility
PubCo II	7.0 years	0.1% to 3.0%	5.9% to 7.0%	19% to 40%
PrivCo I	7.0 years	0.1% to 1.6%	6.1% to 6.7%	19% 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 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.

Hedging Activities and Fair Value Measurements

12 Months Ended

Dec. 31, 2020

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

Derivative Instruments, Hedging Activities and Fair Value Measurements

Note 14. 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 ten forward-starting swaps in September 2019 having an aggregate notional value of $1.0 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 $94.9 million that is reflected as an increase in interest expense for the year ended December 31, 2019. The ten forward-starting swaps resulting from the swaption exercise in September 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, 2020, 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	$75.0	4/2021	2.41%	Cash flow hedge
Future long-term debt offering	5 forward-starting swaps	$500.0	4/2021	2.13%	Cash flow hedge
Future long-term debt offering	2 forward-starting swaps (1)	$150.0	2/2022	1.72%	Cash flow hedge
Future long-term debt offering	1 forward starting swap (1)	$100.0	4/2021	1.46%	Cash flow hedge
Future long-term debt offering	2 forward starting swaps (1)	$150.0	2/2022	1.48%	Cash flow hedge
Future long-term debt offering	2 forward starting swaps (1)	$100.0	2/2022	0.95%	Cash flow hedge

(1)	These swaps were entered into during the first quarter of 2020.

In total, the notional amount of forward-starting swaps outstanding at December 31, 2020 was $1.08 billion. The weighted-average fixed interest rate of these derivative instruments is 1.83%.

As a result of market conditions, we terminated an aggregate $575 million notional amount of forward-starting swaps in 2020, which resulted in net cash payments of $33.3 million. As cash flow hedges, losses on these derivative instruments are reflected as a component of accumulated other comprehensive loss and are being amortized to earnings (as an increase in interest expense) over the 30-year life of the associated debt through January 2051. These swaps were unwound in connection with our issuance of Senior Notes BBB. During 2018, we terminated an aggregate $275 million notional amount of forward-starting swaps, which resulted in cash proceeds totaling $22.1 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 30-year life of the associated debt 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, 2020, 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, 2020 (volume measures as noted):

	Volume (1)		Accounting
Derivative Purpose	Current (2)	Long-Term (2)	Treatment
Derivatives designated as hedging instruments:
Natural gas processing:
Forecasted natural gas purchases for plant thermal reduction (Bcf)	6.0	n/a	Cash flow hedge
Forecasted sales of NGLs (MMBbls)	0.6	n/a	Cash flow hedge
Natural gas marketing:
Natural gas storage inventory management activities (Bcf)	4.0	n/a	Fair value hedge
NGL marketing:
Forecasted purchases of NGLs and related hydrocarbon products (MMBbls)	142.8	1.6	Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products (MMBbls)	172.1	4.5	Cash flow hedge
NGLs inventory management activities (MMBbls)	1.9	n/a	Fair value hedge
Refined products marketing:
Forecasted purchases of refined products (MMBbls)	41.2	n/a	Cash flow hedge
Forecasted sales of refined products (MMBbls)	51.1	3.3	Cash flow hedge
Refined products inventory management activities (MMBbls)	0.8	n/a	Fair value hedge
Crude oil marketing:
Forecasted purchases of crude oil (MMBbls)	32.9	n/a	Cash flow hedge
Forecasted sales of crude oil (MMBbls)	44.5	n/a	Cash flow hedge
Petrochemical marketing:
Forecasted purchases of petrochemical products (MMBbls)	0.4	n/a	Cash flow hedge
Forecasted sales of petrochemical products (MMBbls)	0.5	n/a	Cash flow hedge
Derivatives not designated as hedging instruments:
Natural gas risk management activities (Bcf) (3)	10.3	0.4	Mark-to-market
NGL risk management activities (MMBbls) (3)	26.5	7.9	Mark-to-market
Refined products risk management activities (MMBbls) (3)	6.9	n/a	Mark-to-market
Crude oil risk management activities (MMBbls) (3)	32.5	2.6	Mark-to-market

(1)	Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes.
(2)	The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is December 2022, December 2021 and October 2023, 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 $144.0 million and $31.7 million at December 31, 2020 and 2019, 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, 2020			December 31, 2019			December 31, 2020			December 31, 2019
	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	$	109.1	Current liabilities	$	6.7
Interest rate derivatives	Other assets		12.4	Other assets		–	Other liabilities		11.0	Other liabilities		6.8
Total interest rate derivatives			12.4			–			120.1			13.5
Commodity derivatives	Current assets		210.5	Current assets		116.5	Current liabilities		234.0	Current liabilities		107.1
Commodity derivatives	Other assets		0.4	Other assets		–	Other liabilities		6.1	Other liabilities		–
Total commodity derivatives			210.9			116.5			240.1			107.1
Total derivatives designated as hedging instruments		$	223.3		$	116.5		$	360.2		$	120.6

Derivatives not designated as hedging instruments
Commodity derivatives	Current assets		18.1	Current assets		10.7	Current liabilities		6.1	Current liabilities		8.6
Commodity derivatives	Other assets		0.2	Other assets		0.6	Other liabilities		0.1	Other liabilities		0.5
Total commodity derivatives			18.3			11.3			6.2			9.1
Total derivatives not designated as hedging instruments		$	18.3		$	11.3		$	6.2		$	9.1

Certain of our commodity derivative instruments are subject to master netting arrangements or similar agreements. The following tables present our derivative instruments subject to such arrangements at the dates indicated:

	Offsetting of Financial Assets and Derivative Assets
										Gross Amounts Not Offset in the Balance Sheet
	Gross Amounts of Recognized Assets			Gross Amounts Offset in the Balance Sheet			Amounts of Assets Presented in the Balance Sheet			Financial Instruments				Cash Collateral Paid			Cash Collateral Received		Amounts That Would Have Been Presented On Net Basis
	(i)			(ii)			(iii) = (i) – (ii)			(iv)									(v) = (iii) + (iv)
As of December 31, 2020:
Interest rate derivatives		$	12.4		$	–		$	12.4		$	–		$	–		$	–		$	12.4
Commodity derivatives			229.2			–			229.2			(228.5	)		–			–			0.7
As of December 31, 2019:
Commodity derivatives		$	127.8			–		$	127.8		$	(115.3	)	$	(11.0	)	$	–		$	1.5

	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, 2020:
Interest rate derivatives		$	120.1		$	–		$	120.1		$	–			$	–			$	120.1
Commodity derivatives			246.3			–			246.3			(228.5	)			(17.3	)			0.5
As of December 31, 2019:
Interest rate derivatives		$	13.5		$	–		$	13.5		$	–			$	–			$	13.5
Commodity derivatives			116.2			–			116.2			(115.3	)			–				0.9

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,
		2020			2019		2018
Interest rate derivatives	Interest expense	$	–		$	–	$	1.3
Commodity derivatives	Revenue		(88.0	)		2.2		9.9
Total		$	(88.0	)	$	2.2	$	11.2

Derivatives in Fair Value Hedging Relationships	Location	Gain (Loss) Recognized in Income on Hedged Item
		For the Year Ended December 31,
		2020		2019		2018
Interest rate derivatives	Interest expense	$	–	$	–	$	(1.4	)
Commodity derivatives	Revenue		168.1		6.9		(6.9	)
Total		$	168.1	$	6.9	$	(8.3	)

The gain (loss) corresponding to the hedge ineffectiveness on the fair value hedges was negligible for all periods presented. The remaining gain (loss) for each period presented is primarily attributable to prompt-to-forward month price differentials that were excluded from the assessment of hedge effectiveness.

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,
	2020				2019				2018
Interest rate derivatives		$	(127.5	)		$	81.4			$	22.2
Commodity derivatives – Revenue (1)			134.7				55.8				293.0
Commodity derivatives – Operating costs and expenses (1)			(10.3	)			(11.7	)			0.2
Total		$	(3.1	)		$	125.5			$	315.4

(1)	The fair value of these derivative instruments will be reclassified to their respective locations on the Statement of Consolidated Operations when the forecasted transactions affect earnings.

Derivatives in Cash Flow Hedging Relationships	Location	Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income
		For the Year Ended December 31,
		2020			2019			2018
Interest rate derivatives	Interest expense	$	(39.3	)	$	(37.3	)	$	(38.1	)
Commodity derivatives	Revenue		282.6			152.4			131.7
Commodity derivatives	Operating costs and expenses		(9.9	)		(10.7	)		(1.3	)
Total		$	233.4		$	104.4		$	92.3

Over the next twelve months, we expect to reclassify $41.2 million of losses attributable to interest rate derivative instruments from accumulated other comprehensive loss to earnings as an increase in interest expense. Likewise, we expect to reclassify $35.6 million of losses attributable to commodity derivative instruments from accumulated other comprehensive loss to earnings, with $36.0 million as a decrease in revenue and $0.4 million as a decrease in 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,
		2020			2019			2018
Interest rate derivatives	Interest expense	$	–		$	(94.9	)	$	–
Commodity derivatives	Revenue		166.0			102.2			(462.9	)
Commodity derivatives	Operating costs and expenses		(0.2	)		(12.4	)		8.2
Total		$	165.8		$	(5.1	)	$	(454.7	)

The $165.8 million gain recognized for the year ended December 31, 2020 (as noted in the preceding table) from derivatives not designated as hedging instruments consists of $92.1 million of realized gains and $73.7 million of net unrealized mark-to-market gains attributable to commodity 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,
	2020		2019			2018
Mark-to-market gains (losses) in gross operating margin:
NGL Pipelines & Services	$	48.4	$	(5.5	)	$	18.0
Crude Oil Pipelines & Services		20.1		80.6			(44.1	)
Natural Gas Pipelines & Services		6.3		(0.2	)		6.7
Petrochemical & Refined Products Services		4.5		(7.2	)		1.7
Total mark-to-market impact on gross operating margin		79.3		67.7			(17.7	)
Mark-to-market gains (losses) in interest expense		–		(94.9	)		(0.1	)
Total	$	79.3	$	(27.2	)	$	(17.8	)

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, 2020 Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total
Financial assets:
Interest rate derivatives	$	–		$	12.4		$	–		$	12.4
Commodity derivatives:
Value before application of CME Rule 814		678.6			878.6			12.9			1,570.1
Impact of CME Rule 814 change		(678.6	)		(650.4	)		(11.9	)		(1,340.9	)
Total commodity derivatives		–			228.2			1.0			229.2
Total	$	–		$	240.6		$	1.0		$	241.6

Financial liabilities:
Interest rate derivatives	$	–		$	120.1		$	–		$	120.1
Commodity derivatives:
Value before application of CME Rule 814		1,065.6			1,047.4			25.9			2,138.9
Impact of CME Rule 814 change		(1,065.6	)		(807.3	)		(19.7	)		(1,892.6	)
Total commodity derivatives		–			240.1			6.2			246.3
Total	$	–		$	360.2		$	6.2		$	366.4

In the aggregate, the fair value of our commodity hedging portfolios at December 31, 2020 was a net derivative liability of $568.8 million prior to the impact of CME Rule 814.

	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

Prior to being settled on March 5, 2020, the recurring fair value measurement pertaining to the Liquidity Option was based on a number of Level 3 inputs. For information regarding the Liquidity Option prior to its settlement, see Note 17.

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	2020			2019
Financial liability balance, net, January 1		$	(509.8	)	$	(395.9	)
Total gains (losses) included in:
Net income (1)	Revenue		(1.6	)		3.7
Net income	Other expense, net – Liquidity Option		(2.3	)		(119.6	)
Other comprehensive income (loss)	Commodity derivative instruments – changes in fair value of cash flow hedges		(23.7	)		(2.1	)
Settlements (1)	Revenue		3.2			(3.5	)
Transfer out of Level 3 – Liquidity Option (2)			511.9			–
Other transfers out of Level 3			17.1			7.6
Financial liability balance, net, December 31		$	(5.2	)	$	(509.8	)

(1)	There were $0.7 million and $0.2 million of unrealized gains included in these amounts for the years ended December 31, 2020 and 2019, respectively.
(2)	In March 2020, the Liquidity Option settled and was transferred out of Level 3. See Note 17 for information regarding the Liquidity Option.

Nonrecurring Fair Value Measurements

We wrote down the assets comprising our marine transportation business and certain natural gas gathering and processing activities to their estimated fair values in 2020 (see Note 4). Apart from these matters, we did not have any significant nonrecurring fair value measurements during the years ended December 31, 2020, 2019 or 2018. The following table presents information regarding our significant nonrecurring fair value measurements at December 31, 2020:

	Components of Carrying Value at December 31, 2020 by Level of Fair Value Measurement
	Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Carrying Values at December 31, 2020			Impairment Charges Recognized in 2020
Long-lived assets held and used: (1)
Marine transportation business		$	–		$	–		$	410.0		$	410.0		$	256.7
South Texas natural gas gathering and processing			–			–			21.3			21.3			125.7

(1)	Our fair value estimates for these assets were based on an income approach (i.e., a discounted cash flow approach).

Our fair value estimate of $410.0 million for the marine transportation business is based on the income approach to fair value, which relies on the use of a discounted cash flow model. Our valuation estimate for this business at December 31, 2020 incorporates several Level 3 inputs such as: (i) management’s long-term forecast of cash flows generated by the business; (ii) a discount rate of 9.3%; and (iii) a growth rate of 2.1% for terminal year cash flows. The discount rate used in this analysis is based on an estimated weighted-average cost of capital for market participants engaged in marine transportation activities.

Our fair value estimate for the South Texas natural gas gathering and processing assets of $21.3 million is based primarily on management expectations of the residual values of such facilities and pipelines based on historical experience.

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 $35.00 billion and $30.37 billion at December 31, 2020 and 2019, respectively. The aggregate carrying value of these debt obligations was $29.90 billion and $27.15 billion at December 31, 2020 and 2019, 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

12 Months Ended

Dec. 31, 2020

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,
	2020		2019		2018
Revenues – related parties:
Unconsolidated affiliates	$	36.7	$	67.3	$	107.7
Costs and expenses – related parties:
EPCO and its privately held affiliates	$	1,143.7	$	1,145.3	$	1,089.6
Unconsolidated affiliates		203.1		403.1		447.4
Total	$	1,346.8	$	1,548.4	$	1,537.0

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

	December 31,
	2020		2019
Accounts receivable - related parties:
EPCO and its privately held affiliates	$	1.9	$	–
Unconsolidated affiliates		3.7		2.5
Total	$	5.6	$	2.5

Accounts payable - related parties:
EPCO and its privately held affiliates	$	139.6	$	143.7
Unconsolidated affiliates		9.9		18.6
Total	$	149.5	$	162.3

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, 2020, 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 Limited Partner Interests Held	Percentage of Limited Partner Interests Outstanding
701,993,298 common units		32.2	%
15,138 preferred units		30.2	%

Of the total number of units held by EPCO and its privately held affiliates, 92,976,464 have been pledged as security under the credit facilities of EPCO and its privately held affiliates at December 31, 2020. 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.

The Partnership 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, 2020, 2019 and 2018, we paid EPCO and its privately held affiliates cash distributions totaling $1.21 billion, $1.19 billion and $1.16 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 and 2018, privately held affiliates of EPCO reinvested $29 million and $213 million, respectively, through our DRIP. See Note 8 for additional information regarding our DRIP and ATM program.

We lease office space from privately held affiliates of EPCO at rental rates that approximate market rates. In January 2020, we amended an office space lease with an affiliate of EPCO that extended the term through June 2037. For the years ended December 31, 2020, 2019 and 2018, we recognized $13.0 million, $14.9 million and $13.9 million, respectively, of related party operating lease expense in connection with these office space leases.

EPCO ASA. We have no employees. All of our administrative and operating functions are provided either by employees of EPCO (pursuant to the ASA) or by other service providers. We and our general partner are parties to the 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,
	2020		2019		2018
Operating costs and expenses	$	999.0	$	1,000.2	$	948.8
General and administrative expenses		128.9		127.6		124.2
Total costs and expenses	$	1,127.9	$	1,127.8	$	1,073.0

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, 2020, 2019 and 2018, we paid Seaway $71.5 million, $194.5 million and $163.2 million, respectively, for pipeline transportation and storage services in connection with our crude oil marketing activities. Revenues from Seaway were $20.2 million, $42.7 million and $74.4 million for the years ended December 31, 2020, 2019 and 2018, respectively.

•	For the years ended December 31, 2020, 2019 and 2018, we purchased $51.3 million, $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 $23.5 million, $34.8 million and $31.9 million for the years ended December 31, 2020, 2019 and 2018, respectively. In addition, we sell natural gas to Promix for its plant fuel requirements. Revenues from Promix were $6.0 million, $9.1 million and $9.5 million for the years ended December 31, 2020, 2019 and 2018, respectively.

•	For the years ended December 31, 2020, 2019 and 2018, we paid Texas Express $29.1 million, $33.5 million and $57.6 million, respectively, for pipeline transportation services.

•	For the years ended December 31, 2020, 2019 and 2018, we paid Eagle Ford Crude Oil Pipeline $20.9 million, $36.0 million and $18.5 million, respectively, for pipeline transportation services.

•	We perform management services for certain of our unconsolidated affiliates. We charged such affiliates $10.1 million, $9.9 million and $11.6 million for the years ended December 31, 2020, 2019 and 2018, respectively.

Income Taxes

12 Months Ended

Dec. 31, 2020

Income Taxes [Abstract]

Provision for Income Taxes

Note 16. 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, 2020, 2019 and 2018 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.

The following table presents the components of our consolidated benefit from (provision for) income taxes for the years indicated:

	For the Year Ended December 31,
	2020			2019			2018
Deferred tax benefit attributable to OTA	$	155.3		$	–		$	–
Texas Margin Tax		(32.1	)		(44.2	)		(54.8	)
Other		1.1			(1.4	)		(5.5	)
Benefit from (provision for) income taxes	$	124.3		$	(45.6	)	$	(60.3	)

In addition to income tax amounts attributable to OTA (as described below), the provision for income taxes includes our state tax obligations under the Revised Texas Franchise Tax (the “Texas Margin Tax”).

Income taxes are accounted for under the asset-and-liability method. Deferred income tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

We recognize the effect of income tax positions only if those positions are more likely than not of being sustained. Recognized income tax positions are measured at the largest amount that is greater than 50% likely of being realized. Changes in recognition or measurement are reflected in the period in which the change in judgment occurs. 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, 2020, 2019 and 2018.

OTA Deferred Tax Liability

On March 5, 2020, the Partnership settled its obligations under the Liquidity Option Agreement (see Note 8) and indirectly assumed OTA’s deferred tax liability, which reflects OTA’s outside basis difference in the limited partner interests it received from the Partnership in October 2014. Upon settlement of the Liquidity Option, the Liquidity Option liability was effectively replaced by the deferred tax liability of OTA calculated in accordance with ASC 740, Income Taxes.

At March 5, 2020, the Liquidity Option liability amount was $511.9 million. Since the book value of the Liquidity Option liability exceeded OTA’s estimated deferred tax liability of $439.7 million on that date, we recognized a non-cash benefit in earnings of $72.2 million, which is reflected in the “Benefit from (provision for) income tax” line on our Statement of Consolidated Operations for the year ended December 31, 2020. OTA recognized an additional net, non-cash deferred income tax benefit of $83.1 million primarily due to a decrease in the outside basis difference of its investment in the Partnership attributable to a decline in the market price of the Partnership’s common units subsequent to March 5, 2020 through September 30, 2020. In total, earnings for the year ended December 31, 2020 reflect $155.3 million of net deferred income tax benefit attributable to OTA.

On September 30, 2020, OTA exchanged the Partnership common units it owned for non-publicly traded preferred units having a stated value of $1,000 per unit (see Note 8). As a result and beginning September 30, 2020, OTA’s deferred tax liability no longer fluctuates due to market price changes in the Partnership’s common units. Our subsidiary OTA is a corporation for U.S. federal income tax purposes, and the exchange of common units for preferred units did not constitute a taxable transaction for OTA.

Tabular Disclosures Regarding Income Taxes

Our federal, state and foreign income tax benefit (provision) is summarized below:

	For the Year Ended December 31,
	2020			2019			2018
Current portion of income tax benefit (provision):
Federal	$	2.9		$	1.3		$	(5.3	)
State		(25.6	)		(25.7	)		(33.1	)
Foreign		(0.6	)		(1.2	)		(0.5	)
Total current portion		(23.3	)		(25.6	)		(38.9	)
Deferred portion of income tax benefit (provision):
Federal		142.0			(1.6	)		0.3
State		5.6			(18.5	)		(21.7	)
Foreign		–			0.1			–
Total deferred portion		147.6			(20.0	)		(21.4	)
Total benefit from (provision for) income taxes	$	124.3		$	(45.6	)	$	(60.3	)

A reconciliation of the benefit from (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,
	2020			2019			2018
Pre-Tax Net Book Income (“NBI”)	$	3,761.4		$	4,732.7		$	4,298.8

Texas Margin Tax (1)	$	(32.1	)	$	(44.2	)	$	(54.8	)
State income tax benefit (provision), net of federal benefit (2)		9.2			(0.5	)		(0.2	)
Federal income tax benefit (provision) computed by applying the federal statutory rate to NBI of corporate entities		80.1			(0.9	)		(2.1	)
Federal benefit attributable to settlement of Liquidity Option (2)		67.8			–			–
Other differences		(0.7	)		–			(3.2	)
Benefit from (provision for) income taxes	$	124.3		$	(45.6	)	$	(60.3	)

Effective income tax rate		3.3	%		(1.0	)%		(1.4	)%

(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)	The total benefit recognized in income tax expense on March 5, 2020 from settlement of the Liquidity Option was $72.2 million, which is comprised of $4.4 million of state income tax benefit and $67.8 million of federal income tax benefit.

Deferred income taxes are determined based on the temporary differences between the financial statement and income tax bases of assets and liabilities as measured by the enacted tax rates, which will be in effect when these differences reverse.

The following table presents the significant components of deferred tax assets and deferred tax liabilities at the dates indicated:

	December 31,
	2020		2019
Deferred tax liabilities:
Attributable to investment in OTA	$	356.6	$	–
Attributable to property, plant and equipment		106.4		100.2
Attributable to investments in other entities		4.1		3.3
Total deferred tax liabilities		467.1		103.5
Less deferred tax assets:
Net operating loss carryovers (1)		0.1		0.1
Temporary differences related to Texas Margin Tax		2.3		3.0
Total deferred tax assets		2.4		3.1
Total net deferred tax liabilities	$	464.7	$	100.4

(1)	These losses expire in various years between 2021 and 2037 and are subject to limitations on their utilization.

- Definition

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

+ References + Details

Commitments and Contingent Liabilities

12 Months Ended

Dec. 31, 2020

Commitments and Contingencies [Abstract]

Commitments and Contingencies

Note 17. Commitments and Contingent Liabilities

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, 2020 and 2019, our accruals for litigation contingencies were $6.1 million and $0.2 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.

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 first propane dehydrogenation facility (“PDH 1”). 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, 2020, we had approximately 9.9 trillion British thermal units (“TBtus”) of natural gas, 19.4 MMBbls of crude oil, and 31.1 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, 2020. A description of each type of contractual obligation follows:

	Payment or Settlement due by Period
Contractual Obligations	Total		2021		2022		2023		2024		2025		Thereafter
Scheduled maturities of debt obligations	$	30,146.4	$	1,325.0	$	1,400.0	$	1,250.0	$	850.0	$	1,150.0	$	24,171.4
Estimated cash interest payments	$	28,834.6	$	1,294.0	$	1,241.2	$	1,201.0	$	1,162.8	$	1,121.4	$	22,814.2
Operating lease obligations	$	460.5	$	33.7	$	36.1	$	33.2	$	29.9	$	28.8	$	298.8
Purchase obligations:
Product purchase commitments:
Estimated payment obligations:
Natural gas	$	155.0	$	84.6	$	70.4	$	–	$	–	$	–	$	–
NGLs	$	3,908.4	$	685.2	$	696.8	$	494.4	$	436.4	$	336.8	$	1,258.8
Crude oil	$	10,365.7	$	1,390.1	$	1,390.1	$	1,390.1	$	1,354.9	$	1,297.2	$	3,543.3
Petrochemicals and refined products	$	346.1	$	100.9	$	100.9	$	76.0	$	68.3	$	–	$	–
Other	$	25.5	$	5.8	$	5.9	$	6.0	$	5.1	$	2.7	$	–
Service payment commitments	$	278.8	$	62.0	$	59.7	$	42.3	$	16.1	$	12.9	$	85.8

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, 2020, 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 2020, 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 2020.

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 agreements to lease office space from affiliates of EPCO and those relating to underground NGL storage caverns we lease from a third party include renewal options that could extend these contracts for up to an additional 20 years. The remainder of our significant lease agreements do not provide for additional renewal terms.

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, 2020:

Asset Category	ROU Asset Carrying Value (1)		Lease Liability Carrying Value (2)		Weighted- Average Remaining Term	Weighted- Average Discount Rate (3)
Storage and pipeline facilities	$	128.0	$	128.7	15 years		4.3	%
Transportation equipment		33.5		35.6	3 years		3.5	%
Office and warehouse space		170.5		184.3	16 years		3.2	%
Total	$	332.0	$	348.6

(1)	ROU asset amounts are a component of “Other assets” on our Consolidated Balance Sheet.
(2)	At December 31, 2020, lease liabilities of $27.8 million and $320.8 million were included within “Other current liabilities” and “Other liabilities,” respectively.
(3)	The discount rate for each category of assets represents the weighted average 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, our ROU asset and lease liability carrying values increased $121.8 million and $136.6 million, respectively, since December 31, 2019 primarily due to the modification of an office space lease with an affiliate of EPCO in 2020.

In total, operating lease expense was $102.0 million, $106.6 million and $86.4 million for the years ended December 31, 2020, 2019 and 2018, respectively. The following table disaggregates our total operating lease expense for the years indicated:

	For the Year Ended December,
	2020		2019
Long-term operating leases:
Fixed lease expense:
Non-cash lease expense (amortization of ROU assets)	$	39.0	$	42.8
Related accretion expense on lease liability balances		13.0		9.0
Total fixed lease expense		52.0		51.8
Variable lease expense		0.2		6.2
Subtotal operating lease expense		52.2		58.0
Short-term operating leases		49.8		48.6
Total operating lease expense	$	102.0	$	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 $37.1 million and $48.1 million for the years ended December 31, 2020 and 2019, respectively.

We do not have any significant operating or direct financing leases where we are the lessor. Our operating lease income for the years ended December 31, 2020 and 2019 was $11.4 million and $14.4 million, respectively. 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:

•

Product purchase commitments – 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, 2020 applied to all future volume commitments. Actual future payment obligations may vary depending on prices at the time of delivery.

•

Service payment commitments – 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.

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, 2020, 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,
	2020		2019
Noncurrent portion of AROs (see Note 4)	$	137.6	$	126.9
Deferred revenues – non-current portion (see Note 9)		198.2		197.0
Liquidity Option liability		–		509.6
Lease liability – non-current portion		320.8		171.6
Derivative liabilities		17.2		7.3
Other		12.8		20.0
Total	$	686.6	$	1,032.4

Liquidity Option

Prior to its settlement on March 5, 2020, the Liquidity Option liability, at any measurement date, represented the fair value of estimated federal and state income taxes that we believe a market participant would assume due to ownership of OTA, including its deferred income tax liabilities. At December 31, 2019 and March 5, 2020, we estimated that our liability under the Liquidity Option Agreement, which was a component of “Other long-term liabilities” on our Consolidated Balance Sheet was $509.6 million and $511.9 million, respectively.

Our valuation estimates for the Liquidity Option liability at December 31, 2019 and March 5, 2020 incorporated several factors 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).

Changes in the fair value of the Liquidity Option liability were recognized in earnings as a component of other expense on our Statements of Consolidated Operations. We recognized $2.3 million of non-cash accretion expense for the period January 1, 2020 to March 5, 2020 attributable to the Liquidity Option liability. Results for the years ended December 31, 2019 and 2018 include $119.6 million and $56.1 million, respectively, of expense attributable to accretion and changes in management estimates regarding inputs to the valuation model. The higher level of expense recognized in 2019 is primarily due to a decrease in the discount factor used in determining the present value of the liability since December 31, 2018. The discount rate is based on a weighted-average cost of capital, which declined over the course of 2019 due to lower U.S. interest rates.

For information regarding settlement of the Liquidity Option, see Note 8.

Significant Risks and Uncertainties	12 Months Ended
Significant Risks and Uncertainties	Dec. 31, 2020
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, public health emergencies 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 connection with the COVID-19 pandemic in 2020, may 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 Information

12 Months Ended

Dec. 31, 2020

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,
	2020			2019			2018
Decrease (increase) in:
Accounts receivable – trade	$	300.2		$	(1,248.8	)	$	730.2
Accounts receivable – related parties		(0.8	)		0.9			(2.3	)
Inventories		(1,420.4	)		(558.0	)		121.4
Prepaid and other current assets		991.4			(69.6	)		214.4
Other assets		(79.6	)		(63.5	)		(9.7	)
Increase (decrease) in:
Accounts payable – trade		11.3			(43.9	)		18.3
Accounts payable – related parties		(12.8	)		67.8			51.4
Accrued product payables		482.7			1,447.8			(1,132.0	)
Accrued interest		23.9			36.1			37.6
Other current liabilities		(992.1	)		58.1			(70.9	)
Other liabilities		(71.3	)		(84.3	)		57.8
Net effect of changes in operating accounts	$	(767.5	)	$	(457.4	)	$	16.2

Cash payments for interest, net of $115.0, $143.8 and $147.9 capitalized in 2020, 2019 and 2018, respectively	$	1,201.3		$	1,080.3		$	1,017.9

Cash payments for federal and state income taxes	$	25.1		$	23.6		$	15.5

We incurred liabilities for construction in progress that had not been paid at December 31, 2020, 2019 and 2018 of $236.1 million, $432.0 million and $567.6 million, respectively. Such amounts are not included under the caption “Capital expenditures” on the Statements of Consolidated Cash Flows.

The following table presents our cash proceeds from asset sales for the years indicated:

	For the Year Ended December 31,
	2020		2019		2018
Sale of crude oil pipeline system	$	–	$	–	$	134.9
Other asset sales		12.8		20.6		26.3
Total	$	12.8	$	20.6	$	161.2

The following table presents net gains attributable to asset sales for the years indicated:

	For the Year Ended December 31,
	2020		2019		2018
Gain on sale of crude oil pipeline system	$	–	$	–	$	20.6
Net gains attributable to other asset sales		4.4		5.7		8.1
Total	$	4.4	$	5.7	$	28.7

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2020

Summary of Significant Accounting Policies [Abstract]

Allowance for Doubtful Accounts

The following table presents our allowance for doubtful accounts activity for the years indicated:

	For the Year Ended December 31,
	2020			2019			2018
Balance at beginning of period	$	12.4		$	11.5		$	12.1
Charged to costs and expenses		8.4			1.2			0.7
Charged to other accounts (1)		28.7			–			–
Deductions		(3.0	)		(0.3	)		(1.3	)
Balance at end of period	$	46.5		$	12.4		$	11.5

(1)	Amount presented for 2020 primarily relates to the reclassification of deferred revenue balances to allowance for doubtful accounts in connection with customer bankruptcies and contractual disputes.

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.

	December 31,
	2020		2019
Cash and cash equivalents	$	1,059.9	$	334.7
Restricted cash		98.2		75.3
Total cash, cash equivalents and restricted cash shown in the Statements of Consolidated Cash Flows	$	1,158.1	$	410.0

Consolidation Policy

Contingencies

Current Assets and Current Liabilities

Derivative Instruments

•	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.

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.

Environmental Costs

The following table presents the activity of our environmental reserves for the years indicated:

	For the Year Ended December 31,
	2020			2019			2018
Balance at beginning of period	$	7.2		$	6.9		$	11.6
Charged to costs and expenses		6.2			12.3			8.2
Acquisition-related additions and other		2.6			2.5			1.7
Deductions		(11.5	)		(14.5	)		(14.6	)
Balance at end of period	$	4.5		$	7.2		$	6.9

At December 31, 2020 and 2019, $3.8 million and $5.8 million, respectively, of our environmental reserves were classified as current liabilities.

Estimates

Fair Value Measurements

•

Impairment Testing

The following table summarizes our asset impairment charges by type as presented on our Statements of Consolidated Cash Flows for the years indicated:

	For the Year Ended December 31,
	2020		2019		2018
Impairment charges reflected in operating costs and expenses:
Property, plant and equipment (see Note 4)	$	589.8	$	51.0	$	46.8
Investment in unconsolidated affiliate (see Note 5)		–		76.4		–
Goodwill (see Note 6)		296.3		–		–
Other (1)		4.5		5.3		3.7
Total asset impairment charges in operating costs and expenses		890.6		132.7		50.5
Other property, plant and equipment impairment charges (2)		–		0.1		–
Total asset impairment charges	$	890.6	$	132.8	$	50.5

(1)	Primarily represents the write-down of surplus materials classified as current assets and intangible assets other than goodwill.
(2)	Amounts presented are reflected in general and administrative costs.

Asset impairment charges related to operations are a component of “Third party and other costs” within the “Operating costs and expenses” section of our Statements of Consolidated Operations.

The following information describes our accounting policies regarding impairment testing for major asset categories:

•

Inventories

Leases

•

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.

•

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

With regard to the planned major maintenance activities of our marine transportation assets and underground storage caverns, we continue to use the deferral method to account for such costs.

See Note 4 for additional information regarding our property, plant and equipment and AROs.

Revenue [Policy Text Block]

Revenues

See Note 9 regarding our revenue disclosures.

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2020

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,
	2020			2019			2018
Balance at beginning of period	$	12.4		$	11.5		$	12.1
Charged to costs and expenses		8.4			1.2			0.7
Charged to other accounts (1)		28.7			–			–
Deductions		(3.0	)		(0.3	)		(1.3	)
Balance at end of period	$	46.5		$	12.4		$	11.5

(1)	Amount presented for 2020 primarily relates to the reclassification of deferred revenue balances to allowance for doubtful accounts in connection with customer bankruptcies and contractual disputes.

Cash, Cash Equivalents and Restricted Cash

	December 31,
	2020		2019
Cash and cash equivalents	$	1,059.9	$	334.7
Restricted cash		98.2		75.3
Total cash, cash equivalents and restricted cash shown in the Statements of Consolidated Cash Flows	$	1,158.1	$	410.0

Environmental Reserves Activity

The following table presents the activity of our environmental reserves for the years indicated:

	For the Year Ended December 31,
	2020			2019			2018
Balance at beginning of period	$	7.2		$	6.9		$	11.6
Charged to costs and expenses		6.2			12.3			8.2
Acquisition-related additions and other		2.6			2.5			1.7
Deductions		(11.5	)		(14.5	)		(14.6	)
Balance at end of period	$	4.5		$	7.2		$	6.9

Asset Impairment Charges

The following table summarizes our asset impairment charges by type as presented on our Statements of Consolidated Cash Flows for the years indicated:

	For the Year Ended December 31,
	2020		2019		2018
Impairment charges reflected in operating costs and expenses:
Property, plant and equipment (see Note 4)	$	589.8	$	51.0	$	46.8
Investment in unconsolidated affiliate (see Note 5)		–		76.4		–
Goodwill (see Note 6)		296.3		–		–
Other (1)		4.5		5.3		3.7
Total asset impairment charges in operating costs and expenses		890.6		132.7		50.5
Other property, plant and equipment impairment charges (2)		–		0.1		–
Total asset impairment charges	$	890.6	$	132.8	$	50.5

(1)	Primarily represents the write-down of surplus materials classified as current assets and intangible assets other than goodwill.
(2)	Amounts presented are reflected in general and administrative costs.

Inventories (Tables)

12 Months Ended

Dec. 31, 2020

Inventories [Abstract]

Inventory Amounts by Product Type

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

	December 31,
	2020		2019
NGLs	$	1,888.1	$	1,094.9
Petrochemicals and refined products		642.6		311.5
Crude oil		758.1		674.2
Natural gas		14.7		10.8
Total	$	3,303.5	$	2,091.4

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,
	2020			2019			2018
Cost of sales (1)		$	16,723.2		$	22,065.8		$	26,789.8
Lower of cost or net realizable value adjustments recognized in cost of sales			60.2			22.7			11.5

(1)	Cost of sales is a component of “Operating costs and expenses,” as presented on our Statements of Consolidated Operations. Fluctuations in these amounts are primarily due to changes in energy commodity prices and sales volumes associated with our marketing activities.

Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2020

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			2020		2019
Plants, pipelines and facilities (1)		3-45	(5)	$	49,972.8	$	47,201.2
Underground and other storage facilities (2)		5-40	(6)		4,207.5		3,965.5
Transportation equipment (3)		3-10			204.9		198.9
Marine vessels (4)		15-30			932.7		905.9
Land					371.9		372.3
Construction in progress					1,807.7		2,641.2
Total					57,497.5		55,285.0
Less accumulated depreciation					15,584.7		13,681.6
Property, plant and equipment, net				$	41,912.8	$	41,603.4

(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,
	2020		2019		2018
Depreciation expense (1)	$	1,681.9	$	1,562.6	$	1,436.2
Capitalized interest (2)		115.0		143.8		147.9

(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,
	2020			2019			2018
ARO liability beginning balance	$	132.1		$	126.3		$	86.7
Liabilities incurred		4.6			5.0			24.4
Liabilities settled		(1.5	)		(2.3	)		(2.5	)
Revisions in estimated cash flows		6.1			(4.8	)		11.5
Accretion expense		8.2			7.9			6.2
ARO liability ending balance	$	149.5		$	132.1		$	126.3

The following table presents our forecast of ARO-related accretion expense for the years indicated:

2021				2022				2023				2024				2025
$	8.6			$	9.1			$	9.6			$	10.3			$	10.9

Impairments of Property, Plant and Equipment

The following table presents our non-cash asset impairment charges involving property, plant and equipment by business segment for the years indicated:

	For the Year Ended December 31,
	2020		2019		2018
NGL Pipelines & Services:
South Texas natural gas processing plants	$	86.9	$	15.6
Other		121.2		23.5	$	18.6
Crude Oil Pipelines & Services:
Cancellation of Midland-to-ECHO 4 project		42.2
Other		3.3		2.6		11.2
Natural Gas Pipelines & Services:
South Texas natural gas gathering pipelines		37.8
Other		5.5		4.8		13.9
Petrochemical & Refined Products Services:
Marine transportation business		252.1
Other		40.8		4.6		3.1
Total impairment charges for property, plant and equipment	$	589.8	$	51.1	$	46.8

Investments in Unconsolidated Affiliates (Tables)

12 Months Ended

Dec. 31, 2020

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,
	2020	2020		2019
NGL Pipelines & Services:
Venice Energy Service Company, L.L.C. (“VESCO”)	13.1%	$	23.4	$	23.2
K/D/S Promix, L.L.C. (“Promix”)	50%		23.0		25.7
Baton Rouge Fractionators LLC (“BRF”)	32.2%		13.8		15.6
Skelly-Belvieu Pipeline Company, L.L.C. (“Skelly-Belvieu”)	50%		31.6		33.1
Texas Express Pipeline LLC (“Texas Express”)	35%		342.8		358.1
Texas Express Gathering LLC (“TEG”)	45%		37.7		41.1
Front Range Pipeline LLC (“Front Range”)	33.3%		199.3		207.0
Crude Oil Pipelines & Services:
Seaway Crude Holdings LLC (“Seaway”)	50%		1,224.0		1,353.1
Eagle Ford Pipeline LLC (“Eagle Ford Crude Oil Pipeline”)	50%		376.8		386.5
Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Corpus Christi”)	50%		122.9		126.9
Natural Gas Pipelines & Services:
White River Hub, LLC (“White River Hub”)	50%		18.2		19.1
Old Ocean Pipeline, LLC (“Old Ocean”)	50%		13.2		8.2
Petrochemical & Refined Products Services:
Baton Rouge Propylene Concentrator LLC (“BRPC”)	30%		1.6		2.0
Transport 4, LLC (“Transport 4”)	25%		0.9		0.6
Total		$	2,429.2	$	2,600.2

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,
	2020			2019			2018
NGL Pipelines & Services	$	121.3		$	114.5		$	117.0
Crude Oil Pipelines & Services		301.2			449.2			365.4
Natural Gas Pipelines & Services		5.8			6.3			6.8
Petrochemical & Refined Products Services (1)		(2.2	)		(7.0	)		(9.2	)
Total	$	426.1		$	563.0		$	480.0

(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.

Intangible Assets and Goodwill (Tables)

12 Months Ended

Dec. 31, 2020

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, 2020							December 31, 2019
	Gross Value		Accumulated Amortization			Carrying Value		Gross Value		Accumulated Amortization			Carrying Value
NGL Pipelines & Services:
Customer relationship intangibles	$	447.8	$	(221.3	)	$	226.5	$	447.8	$	(206.3	)	$	241.5
Contract-based intangibles		162.6		(55.0	)		107.6		162.6		(43.9	)		118.7
Segment total		610.4		(276.3	)		334.1		610.4		(250.2	)		360.2
Crude Oil Pipelines & Services:
Customer relationship intangibles		2,195.0		(291.6	)		1,903.4		2,203.5		(243.5	)		1,960.0
Contract-based intangibles		283.1		(249.9	)		33.2		276.9		(235.0	)		41.9
Segment total		2,478.1		(541.5	)		1,936.6		2,480.4		(478.5	)		2,001.9
Natural Gas Pipelines & Services:
Customer relationship intangibles		1,350.3		(512.2	)		838.1		1,350.3		(481.6	)		868.7
Contract-based intangibles		470.7		(403.8	)		66.9		468.0		(395.5	)		72.5
Segment total		1,821.0		(916.0	)		905.0		1,818.3		(877.1	)		941.2
Petrochemical & Refined Products Services:
Customer relationship intangibles		181.4		(68.3	)		113.1		181.4		(57.5	)		123.9
Contract-based intangibles		44.9		(24.6	)		20.3		46.0		(24.2	)		21.8
Segment total		226.3		(92.9	)		133.4		227.4		(81.7	)		145.7
Total intangible assets	$	5,135.8	$	(1,826.7	)	$	3,309.1	$	5,136.5	$	(1,687.5	)	$	3,449.0

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,
	2020		2019		2018
NGL Pipelines & Services	$	25.2	$	31.9	$	34.7
Crude Oil Pipelines & Services		71.5		92.7		87.8
Natural Gas Pipelines & Services		38.8		41.4		39.1
Petrochemical & Refined Products Services		7.7		8.7		8.7
Total	$	143.2	$	174.7	$	170.3

Forecasted Amortization Expense

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

2021				2022				2023				2024				2025
$	144.5			$	161.3			$	169.0			$	165.1			$	163.5

Significant Acquired Intangible Assets

At December 31, 2020, the carrying value of our portfolio of customer relationship intangible assets was $3.08 billion, the principal components of which were as follows:

a	Weighted Average Remaining Amortization Period	December 31, 2020
a	Weighted Average Remaining Amortization Period	Gross Value		Accumulated Amortization		Carrying Value
Basin-specific customer relationships:
EFS Midstream (acquired 2015)	21.4 years	$	1,409.8	$	(188.1)	$	1,221.7
State Line and Fairplay (acquired 2010)	26.2 years		895.0		(224.0)		671.0
San Juan Gathering (acquired 2004)	18.8 years		331.3		(245.3)		86.0
General customer relationships:
Oiltanking (acquired 2014)	23.0 years		1,192.5		(162.6)		1,029.9

a	Weighted Average Remaining Amortization Period	December 31, 2020
a	Weighted Average Remaining Amortization Period	Gross Value		Accumulated Amortization		Carrying Value
Oiltanking customer contracts	3.0 years	$	293.3	$	(261.7)	$	31.6
Jonah natural gas gathering agreements	21.0 years		224.4		(175.8)		48.6
Delaware Basin natural gas processing contracts	6.0 years		82.6		(23.7)		58.9

Schedule of Goodwill

	NGL Pipelines & Services		Crude Oil Pipelines & Services		Natural Gas Pipelines & Services			Petrochemical & Refined Products Services		Consolidated Total
Balance at December 31, 2018	$	2,651.7	$	1,841.0	$	296.3		$	956.2	$	5,745.2

Balance at December 31, 2019	$	2,651.7	$	1,841.0	$	296.3		$	956.2	$	5,745.2
Impairment of goodwill		–		–		(296.3	)		–		(296.3	)
Balance at December 31, 2020	$	2,651.7	$	1,841.0	$	–		$	956.2	$	5,448.9

Debt Obligations (Tables)

12 Months Ended

Dec. 31, 2020

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,
	2020			2019
EPO senior debt obligations:
Commercial Paper Notes, variable-rates	$	–		$	482.0
Senior Notes Q, 5.25% fixed-rate, due January 2020		–			500.0
Senior Notes Y, 5.20% fixed-rate, due September 2020		–			1,000.0
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
September 2020 364-Day Revolving Credit Agreement, variable-rate, due September 2021		–			–
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			1,250.0
Senior Notes AAA, 2.80% fixed-rate, due January 2030		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			1,250.0
Senior Notes BBB, 3.70% fixed-rate, due January 2051		1,000.0			–
Senior Notes DDD, 3.20% fixed-rate, due February 2052		1,000.0			–
Senior Notes NN, 4.95% fixed-rate, due October 2054		400.0			400.0
Senior Notes CCC, 3.95% fixed rate, due January 2060		1,000.0			–
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		27,500.0			25,232.0
EPO Junior Subordinated Notes C, variable-rate, due June 2067 (1)		232.2			232.2
EPO Junior Subordinated Notes D, fixed/variable-rate, due August 2077 (2)		700.0			700.0
EPO Junior Subordinated Notes E, fixed/variable-rate, due August 2077 (3)		1,000.0			1,000.0
EPO Junior Subordinated Notes F, fixed/variable-rate, due February 2078 (4)		700.0			700.0
TEPPCO Junior Subordinated Notes, variable-rate, due June 2067 (1)		14.2			14.2
Total principal amount of senior and junior debt obligations		30,146.4			27,878.4
Other, non-principal amounts		(280.7	)		(253.3	)
Less current maturities of debt		(1,325.0	)		(1,981.9	)
Total long-term debt	$	28,540.7		$	25,643.2

(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, 2020:

	Range of Interest Rates Paid	Weighted-Average Interest Rate Paid
Commercial Paper Notes	1.78% to 2.08%	1.86%
EPO Junior Subordinated Notes C and TEPPCO Junior Subordinated Notes	3.00% to 4.68%	3.66%

Consolidated Debt Maturities

The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations at December 31, 2020 for the next five years, and in total thereafter:

				Scheduled Maturities of Debt
	Total			2021			2022			2023			2024			2025			Thereafter
Senior Notes		$	27,500.0		$	1,325.0		$	1,400.0		$	1,250.0		$	850.0		$	1,150.0		$	21,525.0
Junior Subordinated Notes			2,646.4			–			–			–			–			–			2,646.4
Total		$	30,146.4		$	1,325.0		$	1,400.0		$	1,250.0		$	850.0		$	1,150.0		$	24,171.4

- Definition

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

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
-URI http://asc.fasb.org/extlink&oid=120391452&loc=d3e13212-122682

Reference 2: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=119993939&loc=d3e28541-108399

Reference 3: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=109259400&loc=d3e21506-112644

Reference 4: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(e),(f))
-URI http://asc.fasb.org/extlink&oid=120395691&loc=d3e23780-122690

Reference 5: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 2
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+ Details

Capital Accounts (Tables)

12 Months Ended

Dec. 31, 2020

Capital Accounts [Abstract]

Summary of Changes in Outstanding Units

The following table summarizes changes in the number of our common units outstanding since December 31, 2017:

Common units outstanding at December 31, 2017	2,161,089,479
Common unit repurchases under Legacy Buyback Program	(1,236,800	)
Common units issued in connection with DRIP and EUPP	19,861,951
Common units issued in connection with the vesting of phantom unit awards, net	2,442,436
Common units issued in connection with employee compensation	1,443,586
Common units issued in connection with land acquisition	1,223,242
Other	45,135
Common units outstanding at December 31, 2018	2,184,869,029
Common unit repurchases under 2019 Buyback Program	(2,909,128	)
Common units issued in connection with DRIP and EUPP	2,897,990
Common units issued in connection with the vesting of phantom unit awards, net	2,720,603
Common units issued in connection with employee compensation	1,626,041
Other	21,595
Common units outstanding at December 31, 2019	2,189,226,130
Common units issued to Skyline North Americas, Inc. in connection with settlement of Liquidity Option in March 2020	54,807,352
Treasury units acquired in connection with settlement of the Liquidity Option in March 2020	(54,807,352	)
Common unit repurchases under 2019 Buyback Program	(8,978,317	)
Common units issued in connection with the vesting of phantom unit awards, net	3,162,095
Common units exchanged for preferred units in September 2020, with the common units received being immediately cancelled	(1,120,588	)
Other	19,638
Common units outstanding at December 31, 2020	2,182,308,958

The following table summarizes changes in the number of our preferred units outstanding during the year ended December 31, 2020:

Original issuance of preferred units on September 30, 2020:
Units sold to third party purchasers			35,000
Units sold to a related party			15,000
Total preferred units outstanding at September 30, 2020			50,000
Paid-in kind distribution to related party			138
Preferred units outstanding at December 31, 2020			50,138

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, 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
Other comprehensive income (loss) for period, before reclassifications		124.4			(127.5	)		(0.1	)		(3.2	)
Reclassification of losses (gains) to net income during period		(272.7	)		39.3			–			(233.4	)
Total other comprehensive income (loss) for period		(148.3	)		(88.2	)		(0.1	)		(236.6	)
Accumulated Other Comprehensive Income (Loss), December 31, 2020	$	(93.2	)	$	(74.3	)	$	2.3		$	(165.2	)

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	2020			2019
Interest rate derivatives	Interest expense	$	39.3		$	37.3
Commodity derivatives	Revenue		(282.6	)		(152.4	)
Commodity derivatives	Operating costs and expenses		9.9			10.7
Total		$	(233.4	)	$	(104.4	)

Noncontrolling Interests

	At December 31,
Consolidated Subsidiary	2020		2019
Breviloba LLC (“Breviloba”)(1)	$	480.4	$	492.9
Whitethorn Pipeline Company LLC (“Whitethorn”)(2)		193.0		198.9
Enterprise Navigator Ethylene Terminal LLC (“ENET”)(3)		142.2		124.3
Other (4)		257.7		247.4
Total noncontrolling interests in consolidated subsidiaries	$	1,073.3	$	1,063.5

(1)	Altus Midstream Processing LP acquired a noncontrolling 33% equity interest in Breviloba, which owns the Shin Oak NGL Pipeline, in July 2019 for $440.7 million in cash.
(2)	An affiliate of Western Gas Partners, LP acquired a noncontrolling 20% equity interest in Whitethorn, which owns the majority of our Midland-to-ECHO 1 pipeline, in June 2018 for $189.6 million in cash.
(3)	Navigator Ethylene Terminals LLC owns a noncontrolling 50% equity interest in ENET, which owns our ethylene export terminal located at Morgan’s Point on the Houston Ship Channel.
(4)	Primarily represents noncontrolling equity interests in NGL fractionation and pipeline businesses.

Declared Quarterly Cash Distribution Rates

	Quarterly Distribution Per Common Unit		Record Date	Payment Date
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
2020:
1st Quarter	$	0.4450	4/30/2020	5/12/2020
2nd Quarter	$	0.4450	7/31/2020	8/12/2020
3rd Quarter	$	0.4450	10/30/2020	11/12/2020
4th Quarter	$	0.4500	1/29/2021	2/11/2021

Revenues (Tables)

12 Months Ended

Dec. 31, 2020

Revenues [Abstract]

Revenues by Business Segment and Revenue Type

	For the Year Ended December 31,
	2020		2019		2018
NGL Pipelines & Services:
Sales of NGLs and related products	$	8,970.7	$	10,934.3	$	12,920.9
Segment midstream services:
Natural gas processing and fractionation		757.3		1,069.9		1,341.0
Transportation		1,036.8		1,054.3		1,007.0
Storage and terminals		412.4		412.2		380.0
Total segment midstream services		2,206.5		2,536.4		2,728.0
Total NGL Pipelines & Services		11,177.2		13,470.7		15,648.9
Crude Oil Pipelines & Services:
Sales of crude oil		5,410.8		9,007.8		10,001.2
Segment midstream services:
Transportation		804.9		801.8		676.5
Storage and terminals		473.3		477.7		364.9
Total segment midstream services		1,278.2		1,279.5		1,041.4
Total Crude Oil Pipelines & Services		6,689.0		10,287.3		11,042.6
Natural Gas Pipelines & Services:
Sales of natural gas		1,530.5		2,075.4		2,411.7
Segment midstream services:
Transportation		1,022.6		1,094.0		1,042.7
Total segment midstream services		1,022.6		1,094.0		1,042.7
Total Natural Gas Pipelines & Services		2,553.1		3,169.4		3,454.4
Petrochemical & Refined Products Services:
Sales of petrochemicals and refined products		5,942.6		4,985.2		5,535.4
Segment midstream services:
Fractionation and isomerization		187.7		166.6		188.3
Transportation, including marine logistics		482.9		539.4		481.8
Storage and terminals		167.2		170.6		182.8
Total segment midstream services		837.8		876.6		852.9
Total Petrochemical & Refined Products Services		6,780.4		5,861.8		6,388.3
Total consolidated revenues	$	27,199.7	$	32,789.2	$	36,534.2

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	2020		2019
Unbilled revenue (current amount)	Prepaid and other current assets	$	18.8	$	17.6
Total		$	18.8	$	17.6

		December 31,
Contract Liability	Location	2020		2019
Deferred revenue (current amount)	Other current liabilities	$	145.3	$	117.9
Deferred revenue (noncurrent)	Other long-term liabilities		198.2		197.0
Total		$	343.5	$	314.9

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 (2)		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 (2)		340.0			539.8
Amounts recorded during period transferred to other accounts (1)		(322.4	)		(384.8	)
Other changes		–			(4.9	)
Balance at December 31, 2019	$	17.6		$	314.9
Amount included in opening balance transferred to other accounts during period (1)		(17.6	)		(114.5	)
Amount recorded during period (2)		323.0			661.2
Amounts recorded during period transferred to other accounts (1)		(304.2	)		(496.7	)
Other changes		–			(21.4	)
Balance at December 31, 2020	$	18.8		$	343.5

(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.
(2)	Unbilled revenue represents revenue that has been recognized upon satisfaction of a performance obligation, but cannot be contractually invoiced (or billed) to the customer at the balance sheet date until a future period. Deferred revenue is recorded when payment is received from a customer prior to our satisfaction of the associated performance obligation.

Remaining Performance Obligations

Period	Fixed Consideration
One Year Ended December 31, 2021	$	3,906.4
One Year Ended December 31, 2022		3,492.3
One Year Ended December 31, 2023		3,110.2
One Year Ended December 31, 2024		2,937.3
One Year Ended December 31, 2025		2,636.5
Thereafter		12,912.5
Total	$	28,995.2

Business Segments (Tables)

12 Months Ended

Dec. 31, 2020

Business Segments [Abstract]

Measurement of Total Segment Gross Operating Margin

	For the Year Ended December 31,
	2020			2019			2018
Operating income	$	5,035.1		$	6,078.7		$	5,408.6
Adjustments to reconcile operating income to total segment gross operating margin (addition or subtraction indicated by sign):
Depreciation, amortization and accretion expense in operating costs and expenses		1,961.5			1,848.3			1,687.0
Asset impairment and related charges in operating costs and expenses		890.6			132.7			50.5
Net gains attributable to asset sales in operating costs and expenses		(4.4	)		(5.7	)		(28.7	)
General and administrative costs		219.6			211.7			208.3
Non-refundable payments received from shippers attributable to make-up rights (1)		119.3			47.0			21.5
Subsequent recognition of revenues attributable to make-up rights (2)		(33.6	)		(22.9	)		(56.2	)
Total segment gross operating margin	$	8,188.1		$	8,289.8		$	7,291.0

(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

	For the Year Ended December 31,
	2020		2019		2018
Gross operating margin by segment:
NGL Pipelines & Services	$	4,182.4	$	4,069.8	$	3,830.7
Crude Oil Pipelines & Services		1,997.3		2,087.8		1,511.3
Natural Gas Pipelines & Services		926.6		1,062.6		891.2
Petrochemical & Refined Products Services		1,081.8		1,069.6		1,057.8
Total segment gross operating margin	$	8,188.1	$	8,289.8	$	7,291.0

Information by business segment, together with reconciliations to amounts presented on, or included in, 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, 2020	$	11,170.6	$	6,668.8	$	2,543.2	$	6,780.4		$	–		$	27,163.0
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
Revenues from related parties:
Year ended December 31, 2020		6.6		20.2		9.9		–			–			36.7
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
Intersegment and intrasegment revenues:
Year ended December 31, 2020		29,010.3		24,531.3		460.1		5,379.4			(59,381.1	)		–
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	)		–
Total revenues:
Year ended December 31, 2020		40,187.5		31,220.3		3,013.2		12,159.8			(59,381.1	)		27,199.7
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
Equity in income (loss) of unconsolidated affiliates:
Year ended December 31, 2020		121.3		301.2		5.8		(2.2	)		–			426.1
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

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: (see Note 4)
At December 31, 2020	$	17,128.3	$	6,982.6	$	8,465.8	$	7,528.4	$	1,807.7	$	41,912.8
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
Investments in unconsolidated affiliates: (see Note 5)
At December 31, 2020		671.6		1,723.7		31.4		2.5		–		2,429.2
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
Intangible assets, net: (see Note 6)
At December 31, 2020		334.1		1,936.6		905.0		133.4		–		3,309.1
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
Goodwill: (see Note 6)
At December 31, 2020		2,651.7		1,841.0		–		956.2		–		5,448.9
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
Segment assets:
At December 31, 2020		20,785.7		12,483.9		9,402.2		8,620.5		1,807.7		53,100.0
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

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,
	2020			2019			2018
Consolidated revenues:
NGL Pipelines & Services	$	11,177.2		$	13,470.7		$	15,648.9
Crude Oil Pipelines & Services		6,689.0			10,287.3			11,042.6
Natural Gas Pipelines & Services		2,553.1			3,169.4			3,454.4
Petrochemical & Refined Products Services		6,780.4			5,861.8			6,388.3
Total consolidated revenues	$	27,199.7		$	32,789.2		$	36,534.2

Consolidated costs and expenses:
Operating costs and expenses:
Cost of sales	$	16,723.2		$	22,065.8		$	26,789.8
Other operating costs and expenses (1)		2,800.2			3,020.7			2,898.7
Depreciation, amortization and accretion		1,961.5			1,848.3			1,687.0
Impairment of goodwill		296.3			–			–
Impairment of assets other than goodwill		594.3			132.7			50.5
Net gains attributable to asset sales		(4.4	)		(5.7	)		(28.7	)
General and administrative costs		219.6			211.7			208.3
Total consolidated costs and expenses	$	22,590.7		$	27,273.5		$	31,605.6

(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.

NGL Pipelines & Services	$	1,410.8
Crude Oil Pipelines & Services		1,670.7
Natural Gas Pipelines & Services		31.2
Petrochemical & Refined Products Services		202.1
Total	$	3,314.8

Earnings Per Unit (Tables)

12 Months Ended

Dec. 31, 2020

Earnings Per Unit [Abstract]

Basic and Diluted Earnings Per Unit

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

	For the Year Ended December 31,
	2020			2019			2018
BASIC EARNINGS PER COMMON UNIT
Net income attributable to common unitholders	$	3,774.7		$	4,591.3		$	4,172.4
Earnings allocated to phantom unit awards (1)		(32.0	)		(27.7	)		(21.5	)
Net income allocated to common unitholders	$	3,742.7		$	4,563.6		$	4,150.9

Basic weighted-average number of common units outstanding		2,185.8			2,188.6			2,176.5

Basic earnings per common unit	$	1.71		$	2.09		$	1.91

DILUTED EARNINGS PER COMMON UNIT
Net income attributable to common unitholders	$	3,774.7		$	4,591.3		$	4,172.4
Net income attributable to preferred units		0.9			–			–
Net income attributable to limited partners	$	3,775.6		$	4,591.3		$	4,172.4

Diluted weighted-average number of units outstanding:
Distribution-bearing common units		2,185.8			2,188.6			2,176.5
Phantom units (2)		15.7			13.1			10.5
Preferred units (2)		0.7			–			–
Total		2,202.2			2,201.7			2,187.0

Diluted earnings per common unit	$	1.71		$	2.09		$	1.91

(1)	Phantom units are considered participating securities for purposes of computing basic earnings per unit. See Note 13 for information regarding our phantom units.
(2)	We use the “if-converted method” to determine the potential dilutive effect of the vesting of phantom units and the conversion of preferred units outstanding. See Note 8 for information regarding the preferred units issued during 2020.

Business Combinations (Tables)

12 Months Ended

Dec. 31, 2020

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	$	–

Equity-Based Awards (Tables)

12 Months Ended

Dec. 31, 2020

Equity-based Awards [Abstract]

Equity-based Award Expense

	For the Year Ended December 31,
	2020		2019		2018
Equity-classified awards:
Phantom unit awards	$	150.3	$	132.2	$	99.7
Profits interest awards		8.7		11.6		6.1
Liability-classified awards		0.1		0.1		0.3
Total	$	159.1	$	143.9	$	106.1

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 (1)
Phantom unit awards at December 31, 2017		9,289,501		$	27.65
Granted (2)		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 (3)		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
Granted (4)		7,405,245		$	25.71
Vested		(4,532,269	)	$	26.35
Forfeited		(178,218	)	$	26.73
Phantom unit awards at December 31, 2020		15,669,442		$	26.76

(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 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 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.
(4)	The aggregate grant date fair value of phantom unit awards issued during 2020 was $190.4 million based on a grant date market price of EPD common units ranging from $16.95 to $25.76 per unit. An estimated annual forfeiture rate of 2.4% was applied to these awards.

The following table presents supplemental information regarding phantom unit awards for the years indicated:

	For the Year Ended December 31,
	2020		2019		2018
Cash payments made in connection with DERs	$	27.1	$	22.1	$	17.7
Total intrinsic value of phantom unit awards that vested during period	$	114.8	$	111.1	$	90.7

The following table summarizes key elements of each Employee Partnership as of December 31, 2020:

Employee Partnership	Partnership Common Units Contributed by EPCO Holdings	Class A Capital Base (1)	Class A Preference Return	Expected Vesting/ Liquidation Date	Estimated Fair Value of Profits Interest Awards (2)	Unrecognized Compensation Cost (3)
PubCo II	2,834,198	$66.3 million	$0.3900	February 2023	$2.5 million	$2.3 million
PrivCo I	1,111,438	$26.0 million	$0.3900	February 2023	$0.9 million	$0.2 million
EPD IV	6,400,000	$172.9 million	$0.4325	December 2023	$26.7 million	$13.6 million
EPCO II	1,600,000	$43.2 million	$0.4325	December 2023	$6.6 million	$0.3 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 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. The fair value is as of the grant date or as of the plan modification date, as applicable.
(3)	Represents our expected share of the unrecognized compensation cost at December 31, 2020. 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 2.1 years, 2.1 years, 2.9 years and 2.9 years, respectively.

	Expected Life	Risk-Free	Expected	Expected Unit
Employee	of Award	Interest	Distribution	Price
Partnership	from Grant Date	Rate	Yield	Volatility
PubCo II	7.0 years	0.1% to 3.0%	5.9% to 7.0%	19% to 40%
PrivCo I	7.0 years	0.1% to 1.6%	6.1% to 6.7%	19% 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%

Hedging Activities and Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2020

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, 2020, 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	$75.0	4/2021	2.41%	Cash flow hedge
Future long-term debt offering	5 forward-starting swaps	$500.0	4/2021	2.13%	Cash flow hedge
Future long-term debt offering	2 forward-starting swaps (1)	$150.0	2/2022	1.72%	Cash flow hedge
Future long-term debt offering	1 forward starting swap (1)	$100.0	4/2021	1.46%	Cash flow hedge
Future long-term debt offering	2 forward starting swaps (1)	$150.0	2/2022	1.48%	Cash flow hedge
Future long-term debt offering	2 forward starting swaps (1)	$100.0	2/2022	0.95%	Cash flow hedge

(1)	These swaps were entered into during the first quarter of 2020.

The following table summarizes our portfolio of commodity derivative instruments outstanding at December 31, 2020 (volume measures as noted):

	Volume (1)		Accounting
Derivative Purpose	Current (2)	Long-Term (2)	Treatment
Derivatives designated as hedging instruments:
Natural gas processing:
Forecasted natural gas purchases for plant thermal reduction (Bcf)	6.0	n/a	Cash flow hedge
Forecasted sales of NGLs (MMBbls)	0.6	n/a	Cash flow hedge
Natural gas marketing:
Natural gas storage inventory management activities (Bcf)	4.0	n/a	Fair value hedge
NGL marketing:
Forecasted purchases of NGLs and related hydrocarbon products (MMBbls)	142.8	1.6	Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products (MMBbls)	172.1	4.5	Cash flow hedge
NGLs inventory management activities (MMBbls)	1.9	n/a	Fair value hedge
Refined products marketing:
Forecasted purchases of refined products (MMBbls)	41.2	n/a	Cash flow hedge
Forecasted sales of refined products (MMBbls)	51.1	3.3	Cash flow hedge
Refined products inventory management activities (MMBbls)	0.8	n/a	Fair value hedge
Crude oil marketing:
Forecasted purchases of crude oil (MMBbls)	32.9	n/a	Cash flow hedge
Forecasted sales of crude oil (MMBbls)	44.5	n/a	Cash flow hedge
Petrochemical marketing:
Forecasted purchases of petrochemical products (MMBbls)	0.4	n/a	Cash flow hedge
Forecasted sales of petrochemical products (MMBbls)	0.5	n/a	Cash flow hedge
Derivatives not designated as hedging instruments:
Natural gas risk management activities (Bcf) (3)	10.3	0.4	Mark-to-market
NGL risk management activities (MMBbls) (3)	26.5	7.9	Mark-to-market
Refined products risk management activities (MMBbls) (3)	6.9	n/a	Mark-to-market
Crude oil risk management activities (MMBbls) (3)	32.5	2.6	Mark-to-market

(1)	Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes.
(2)	The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is December 2022, December 2021 and October 2023, 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, 2020			December 31, 2019			December 31, 2020			December 31, 2019
	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	$	109.1	Current liabilities	$	6.7
Interest rate derivatives	Other assets		12.4	Other assets		–	Other liabilities		11.0	Other liabilities		6.8
Total interest rate derivatives			12.4			–			120.1			13.5
Commodity derivatives	Current assets		210.5	Current assets		116.5	Current liabilities		234.0	Current liabilities		107.1
Commodity derivatives	Other assets		0.4	Other assets		–	Other liabilities		6.1	Other liabilities		–
Total commodity derivatives			210.9			116.5			240.1			107.1
Total derivatives designated as hedging instruments		$	223.3		$	116.5		$	360.2		$	120.6

Derivatives not designated as hedging instruments
Commodity derivatives	Current assets		18.1	Current assets		10.7	Current liabilities		6.1	Current liabilities		8.6
Commodity derivatives	Other assets		0.2	Other assets		0.6	Other liabilities		0.1	Other liabilities		0.5
Total commodity derivatives			18.3			11.3			6.2			9.1
Total derivatives not designated as hedging instruments		$	18.3		$	11.3		$	6.2		$	9.1

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, 2020:
Interest rate derivatives		$	12.4		$	–		$	12.4		$	–		$	–		$	–		$	12.4
Commodity derivatives			229.2			–			229.2			(228.5	)		–			–			0.7
As of December 31, 2019:
Commodity derivatives		$	127.8			–		$	127.8		$	(115.3	)	$	(11.0	)	$	–		$	1.5

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, 2020:
Interest rate derivatives		$	120.1		$	–		$	120.1		$	–			$	–			$	120.1
Commodity derivatives			246.3			–			246.3			(228.5	)			(17.3	)			0.5
As of December 31, 2019:
Interest rate derivatives		$	13.5		$	–		$	13.5		$	–			$	–			$	13.5
Commodity derivatives			116.2			–			116.2			(115.3	)			–				0.9

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,
		2020			2019		2018
Interest rate derivatives	Interest expense	$	–		$	–	$	1.3
Commodity derivatives	Revenue		(88.0	)		2.2		9.9
Total		$	(88.0	)	$	2.2	$	11.2

Derivatives in Fair Value Hedging Relationships	Location	Gain (Loss) Recognized in Income on Hedged Item
		For the Year Ended December 31,
		2020		2019		2018
Interest rate derivatives	Interest expense	$	–	$	–	$	(1.4	)
Commodity derivatives	Revenue		168.1		6.9		(6.9	)
Total		$	168.1	$	6.9	$	(8.3	)

Derivative Instruments Effects on Statements of Comprehensive Income

Derivatives in Cash Flow Hedging Relationships	Change in Value Recognized in Other Comprehensive Income (Loss) On Derivative
	For the Year Ended December 31,
	2020				2019				2018
Interest rate derivatives		$	(127.5	)		$	81.4			$	22.2
Commodity derivatives – Revenue (1)			134.7				55.8				293.0
Commodity derivatives – Operating costs and expenses (1)			(10.3	)			(11.7	)			0.2
Total		$	(3.1	)		$	125.5			$	315.4

(1)	The fair value of these derivative instruments will be reclassified to their respective locations on the Statement of Consolidated Operations when the forecasted transactions affect earnings.

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,
		2020			2019			2018
Interest rate derivatives	Interest expense	$	(39.3	)	$	(37.3	)	$	(38.1	)
Commodity derivatives	Revenue		282.6			152.4			131.7
Commodity derivatives	Operating costs and expenses		(9.9	)		(10.7	)		(1.3	)
Total		$	233.4		$	104.4		$	92.3

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,
		2020			2019			2018
Interest rate derivatives	Interest expense	$	–		$	(94.9	)	$	–
Commodity derivatives	Revenue		166.0			102.2			(462.9	)
Commodity derivatives	Operating costs and expenses		(0.2	)		(12.4	)		8.2
Total		$	165.8		$	(5.1	)	$	(454.7	)

Unrealized mark-to-market gains (losses)

	For the Year Ended December 31,
	2020		2019			2018
Mark-to-market gains (losses) in gross operating margin:
NGL Pipelines & Services	$	48.4	$	(5.5	)	$	18.0
Crude Oil Pipelines & Services		20.1		80.6			(44.1	)
Natural Gas Pipelines & Services		6.3		(0.2	)		6.7
Petrochemical & Refined Products Services		4.5		(7.2	)		1.7
Total mark-to-market impact on gross operating margin		79.3		67.7			(17.7	)
Mark-to-market gains (losses) in interest expense		–		(94.9	)		(0.1	)
Total	$	79.3	$	(27.2	)	$	(17.8	)

Fair Value Measurements of Financial Assets and Liabilities Measured on a Recurring Basis

	At December 31, 2020 Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total
Financial assets:
Interest rate derivatives	$	–		$	12.4		$	–		$	12.4
Commodity derivatives:
Value before application of CME Rule 814		678.6			878.6			12.9			1,570.1
Impact of CME Rule 814 change		(678.6	)		(650.4	)		(11.9	)		(1,340.9	)
Total commodity derivatives		–			228.2			1.0			229.2
Total	$	–		$	240.6		$	1.0		$	241.6

Financial liabilities:
Interest rate derivatives	$	–		$	120.1		$	–		$	120.1
Commodity derivatives:
Value before application of CME Rule 814		1,065.6			1,047.4			25.9			2,138.9
Impact of CME Rule 814 change		(1,065.6	)		(807.3	)		(19.7	)		(1,892.6	)
Total commodity derivatives		–			240.1			6.2			246.3
Total	$	–		$	360.2		$	6.2		$	366.4

	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

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	2020			2019
Financial liability balance, net, January 1		$	(509.8	)	$	(395.9	)
Total gains (losses) included in:
Net income (1)	Revenue		(1.6	)		3.7
Net income	Other expense, net – Liquidity Option		(2.3	)		(119.6	)
Other comprehensive income (loss)	Commodity derivative instruments – changes in fair value of cash flow hedges		(23.7	)		(2.1	)
Settlements (1)	Revenue		3.2			(3.5	)
Transfer out of Level 3 – Liquidity Option (2)			511.9			–
Other transfers out of Level 3			17.1			7.6
Financial liability balance, net, December 31		$	(5.2	)	$	(509.8	)

(1)	There were $0.7 million and $0.2 million of unrealized gains included in these amounts for the years ended December 31, 2020 and 2019, respectively.
(2)	In March 2020, the Liquidity Option settled and was transferred out of Level 3. See Note 17 for information regarding the Liquidity Option.

Nonrecurring Fair Value Measurements

	Components of Carrying Value at December 31, 2020 by Level of Fair Value Measurement
	Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Carrying Values at December 31, 2020			Impairment Charges Recognized in 2020
Long-lived assets held and used: (1)
Marine transportation business		$	–		$	–		$	410.0		$	410.0		$	256.7
South Texas natural gas gathering and processing			–			–			21.3			21.3			125.7

(1)	Our fair value estimates for these assets were based on an income approach (i.e., a discounted cash flow approach).

Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2020

Related Party Transactions

The following table summarizes our related party transactions for the years indicated:

	For the Year Ended December 31,
	2020		2019		2018
Revenues – related parties:
Unconsolidated affiliates	$	36.7	$	67.3	$	107.7
Costs and expenses – related parties:
EPCO and its privately held affiliates	$	1,143.7	$	1,145.3	$	1,089.6
Unconsolidated affiliates		203.1		403.1		447.4
Total	$	1,346.8	$	1,548.4	$	1,537.0

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

	December 31,
	2020		2019
Accounts receivable - related parties:
EPCO and its privately held affiliates	$	1.9	$	–
Unconsolidated affiliates		3.7		2.5
Total	$	5.6	$	2.5

Accounts payable - related parties:
EPCO and its privately held affiliates	$	139.6	$	143.7
Unconsolidated affiliates		9.9		18.6
Total	$	149.5	$	162.3

At December 31, 2020, 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 Limited Partner Interests Held	Percentage of Limited Partner Interests Outstanding
701,993,298 common units		32.2	%
15,138 preferred units		30.2	%

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,
	2020		2019		2018
Operating costs and expenses	$	999.0	$	1,000.2	$	948.8
General and administrative expenses		128.9		127.6		124.2
Total costs and expenses	$	1,127.9	$	1,127.8	$	1,073.0

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2020

Income Taxes [Abstract]

Federal and State Income Tax Provision

The following table presents the components of our consolidated benefit from (provision for) income taxes for the years indicated:

	For the Year Ended December 31,
	2020			2019			2018
Deferred tax benefit attributable to OTA	$	155.3		$	–		$	–
Texas Margin Tax		(32.1	)		(44.2	)		(54.8	)
Other		1.1			(1.4	)		(5.5	)
Benefit from (provision for) income taxes	$	124.3		$	(45.6	)	$	(60.3	)

Our federal, state and foreign income tax benefit (provision) is summarized below:

	For the Year Ended December 31,
	2020			2019			2018
Current portion of income tax benefit (provision):
Federal	$	2.9		$	1.3		$	(5.3	)
State		(25.6	)		(25.7	)		(33.1	)
Foreign		(0.6	)		(1.2	)		(0.5	)
Total current portion		(23.3	)		(25.6	)		(38.9	)
Deferred portion of income tax benefit (provision):
Federal		142.0			(1.6	)		0.3
State		5.6			(18.5	)		(21.7	)
Foreign		–			0.1			–
Total deferred portion		147.6			(20.0	)		(21.4	)
Total benefit from (provision for) income taxes	$	124.3		$	(45.6	)	$	(60.3	)

Reconciliation of Provision for Income Taxes

A reconciliation of the benefit from (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,
	2020			2019			2018
Pre-Tax Net Book Income (“NBI”)	$	3,761.4		$	4,732.7		$	4,298.8

Texas Margin Tax (1)	$	(32.1	)	$	(44.2	)	$	(54.8	)
State income tax benefit (provision), net of federal benefit (2)		9.2			(0.5	)		(0.2	)
Federal income tax benefit (provision) computed by applying the federal statutory rate to NBI of corporate entities		80.1			(0.9	)		(2.1	)
Federal benefit attributable to settlement of Liquidity Option (2)		67.8			–			–
Other differences		(0.7	)		–			(3.2	)
Benefit from (provision for) income taxes	$	124.3		$	(45.6	)	$	(60.3	)

Effective income tax rate		3.3	%		(1.0	)%		(1.4	)%

(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)	The total benefit recognized in income tax expense on March 5, 2020 from settlement of the Liquidity Option was $72.2 million, which is comprised of $4.4 million of state income tax benefit and $67.8 million of federal income tax benefit.

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,
	2020		2019
Deferred tax liabilities:
Attributable to investment in OTA	$	356.6	$	–
Attributable to property, plant and equipment		106.4		100.2
Attributable to investments in other entities		4.1		3.3
Total deferred tax liabilities		467.1		103.5
Less deferred tax assets:
Net operating loss carryovers (1)		0.1		0.1
Temporary differences related to Texas Margin Tax		2.3		3.0
Total deferred tax assets		2.4		3.1
Total net deferred tax liabilities	$	464.7	$	100.4

(1)	These losses expire in various years between 2021 and 2037 and are subject to limitations on their utilization.

Commitments and Contingent Liabilities (Tables)

12 Months Ended

Dec. 31, 2020

Commitments and Contingencies [Abstract]

Summary of Contractual Obligations

The following table summarizes our various contractual obligations at December 31, 2020. A description of each type of contractual obligation follows:

	Payment or Settlement due by Period
Contractual Obligations	Total		2021		2022		2023		2024		2025		Thereafter
Scheduled maturities of debt obligations	$	30,146.4	$	1,325.0	$	1,400.0	$	1,250.0	$	850.0	$	1,150.0	$	24,171.4
Estimated cash interest payments	$	28,834.6	$	1,294.0	$	1,241.2	$	1,201.0	$	1,162.8	$	1,121.4	$	22,814.2
Operating lease obligations	$	460.5	$	33.7	$	36.1	$	33.2	$	29.9	$	28.8	$	298.8
Purchase obligations:
Product purchase commitments:
Estimated payment obligations:
Natural gas	$	155.0	$	84.6	$	70.4	$	–	$	–	$	–	$	–
NGLs	$	3,908.4	$	685.2	$	696.8	$	494.4	$	436.4	$	336.8	$	1,258.8
Crude oil	$	10,365.7	$	1,390.1	$	1,390.1	$	1,390.1	$	1,354.9	$	1,297.2	$	3,543.3
Petrochemicals and refined products	$	346.1	$	100.9	$	100.9	$	76.0	$	68.3	$	–	$	–
Other	$	25.5	$	5.8	$	5.9	$	6.0	$	5.1	$	2.7	$	–
Service payment commitments	$	278.8	$	62.0	$	59.7	$	42.3	$	16.1	$	12.9	$	85.8

Operating Leases

The following table presents information regarding operating leases where we are the lessee at December 31, 2020:

Asset Category	ROU Asset Carrying Value (1)		Lease Liability Carrying Value (2)		Weighted- Average Remaining Term	Weighted- Average Discount Rate (3)
Storage and pipeline facilities	$	128.0	$	128.7	15 years		4.3	%
Transportation equipment		33.5		35.6	3 years		3.5	%
Office and warehouse space		170.5		184.3	16 years		3.2	%
Total	$	332.0	$	348.6

(1)	ROU asset amounts are a component of “Other assets” on our Consolidated Balance Sheet.
(2)	At December 31, 2020, lease liabilities of $27.8 million and $320.8 million were included within “Other current liabilities” and “Other liabilities,” respectively.
(3)	The discount rate for each category of assets represents the weighted average 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

	For the Year Ended December,
	2020		2019
Long-term operating leases:
Fixed lease expense:
Non-cash lease expense (amortization of ROU assets)	$	39.0	$	42.8
Related accretion expense on lease liability balances		13.0		9.0
Total fixed lease expense		52.0		51.8
Variable lease expense		0.2		6.2
Subtotal operating lease expense		52.2		58.0
Short-term operating leases		49.8		48.6
Total operating lease expense	$	102.0	$	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,
	2020		2019
Noncurrent portion of AROs (see Note 4)	$	137.6	$	126.9
Deferred revenues – non-current portion (see Note 9)		198.2		197.0
Liquidity Option liability		–		509.6
Lease liability – non-current portion		320.8		171.6
Derivative liabilities		17.2		7.3
Other		12.8		20.0
Total	$	686.6	$	1,032.4

Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2020

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,
	2020			2019			2018
Decrease (increase) in:
Accounts receivable – trade	$	300.2		$	(1,248.8	)	$	730.2
Accounts receivable – related parties		(0.8	)		0.9			(2.3	)
Inventories		(1,420.4	)		(558.0	)		121.4
Prepaid and other current assets		991.4			(69.6	)		214.4
Other assets		(79.6	)		(63.5	)		(9.7	)
Increase (decrease) in:
Accounts payable – trade		11.3			(43.9	)		18.3
Accounts payable – related parties		(12.8	)		67.8			51.4
Accrued product payables		482.7			1,447.8			(1,132.0	)
Accrued interest		23.9			36.1			37.6
Other current liabilities		(992.1	)		58.1			(70.9	)
Other liabilities		(71.3	)		(84.3	)		57.8
Net effect of changes in operating accounts	$	(767.5	)	$	(457.4	)	$	16.2

Cash payments for interest, net of $115.0, $143.8 and $147.9 capitalized in 2020, 2019 and 2018, respectively	$	1,201.3		$	1,080.3		$	1,017.9

Cash payments for federal and state income taxes	$	25.1		$	23.6		$	15.5

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,
	2020		2019		2018
Sale of crude oil pipeline system	$	–	$	–	$	134.9
Other asset sales		12.8		20.6		26.3
Total	$	12.8	$	20.6	$	161.2

The following table presents net gains attributable to asset sales for the years indicated:

	For the Year Ended December 31,
	2020		2019		2018
Gain on sale of crude oil pipeline system	$	–	$	–	$	20.6
Net gains attributable to other asset sales		4.4		5.7		8.1
Total	$	4.4	$	5.7	$	28.7

- Definition

Tabular disclosure of information related to a disposal group. Includes, but is not limited to, a discontinued operation, disposal classified as held-for-sale or disposed of by means other than sale or disposal of an individually significant component.

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 360
-SubTopic 10
-Section 50
-Paragraph 3A
-URI http://asc.fasb.org/extlink&oid=109226691&loc=SL51724579-110230

Reference 2: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=109222650&loc=d3e1474-107760

Reference 3: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
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-Section 50
-Paragraph 5D
-URI http://asc.fasb.org/extlink&oid=109222650&loc=SL51721677-107760

Reference 4: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 45
-Paragraph 11
-URI http://asc.fasb.org/extlink&oid=109222160&loc=SL51721533-107759

Reference 5: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 3A
-URI http://asc.fasb.org/extlink&oid=109222650&loc=SL51721659-107760

Reference 6: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=109222650&loc=SL51721665-107760

Reference 7: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 360
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=109226691&loc=d3e2941-110230

Reference 8: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 5C
-URI http://asc.fasb.org/extlink&oid=109222650&loc=SL51721675-107760

Reference 9: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=109222650&loc=SL51721683-107760

Reference 10: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=109222650&loc=d3e1361-107760

Reference 11: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
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-URI http://asc.fasb.org/extlink&oid=109222650&loc=SL51721671-107760

Reference 12: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 5B
-URI http://asc.fasb.org/extlink&oid=109222650&loc=SL51721673-107760

Reference 13: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 4A
-URI http://asc.fasb.org/extlink&oid=109222650&loc=SL51721663-107760

+ Details

Partnership Organization and Operations (Details)	12 Months Ended
Partnership Organization and Operations (Details)	Dec. 31, 2020 Segment
Related Party Transaction [Line Items]
Number of reportable segments	4
EPCO and its privately held affiliates [Member] \| Common Units [Member]
Related Party Transaction [Line Items]
Percentage of total units outstanding	32.20%
EPCO and its privately held affiliates [Member] \| Preferred Units [Member]
Related Party Transaction [Line Items]
Percentage of total units outstanding	30.20%

Summary of Significant Accounting Policies (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Cash, Cash Equivalents and Restricted Cash:

Cash and cash equivalents

$ 1,059.9

$ 334.7

Restricted cash

98.2

75.3

Total cash, cash equivalents and restricted cash shown in the Statements of Consolidated Cash Flows

1,158.1

410.0

$ 410.1

$ 70.3

Allowance for Doubtful Accounts [Member]

Movement in valuation allowances and reserves [Roll Forward]

Balance at beginning of period

12.4

11.5

12.1

Charged to costs and expenses

8.4

1.2

0.7

Charged to other accounts

^[1]

28.7

0.0

Deductions

(3.0)

(0.3)

(1.3)

Balance at end of period

$ 46.5

$ 12.4

$ 11.5

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%

[1]	Amount presented for 2020 primarily relates to the reclassification of deferred revenue balances to allowance for doubtful accounts in connection with customer bankruptcies and contractual disputes.

Summary of Significant Accounting Policies, Part 2 (Details)	12 Months Ended
	Dec. 31, 2020
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 Accounting Policies, Part 3 (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

Environmental Costs [Abstract]

Environmental reserves - current portion

$ 3.8

$ 5.8

Asset Impairment Charges [Abstract]

Impairment of property, plant and equipment

589.8

51.1

$ 46.8

Impairment of goodwill

296.3

0.0

Impairment charges in operating costs and expenses

890.6

132.7

50.5

Total asset impairment charges

890.6

132.8

50.5

Lease Accounting Standard [Abstract]

Right-of-use assets

^[1]

332.0

Lease liabilities

^[2]

348.6

Environmental Reserves [Member]

Movement in valuation allowances and reserves [Roll Forward]

Balance at beginning of period

7.2

6.9

11.6

Charged to costs and expenses

6.2

12.3

8.2

Acquisition-related additions and other

2.6

2.5

1.7

Deductions

(11.5)

(14.5)

(14.6)

Balance at end of period

4.5

7.2

6.9

Operating costs and expenses [Member]

Asset Impairment Charges [Abstract]

Impairment of property, plant and equipment

589.8

51.0

46.8

Impairment of investment in unconsolidated affiliate

0.0

76.4

0.0

Impairment of goodwill

296.3

0.0

Other impairments

^[3]

4.5

5.3

3.7

Impairment charges in operating costs and expenses

890.6

132.7

50.5

General and administrative costs [Member]

Asset Impairment Charges [Abstract]

Impairment of property, plant and equipment

^[4]

$ 0.0

$ 0.1

0.0

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, 2020, lease liabilities of $27.8 million and $320.8 million were included within “Other current liabilities” and “Other liabilities,” respectively.
[3]	Primarily represents the write-down of surplus materials classified as current assets and intangible assets other than goodwill.
[4]	Amounts presented are reflected in general and administrative costs.

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

12 Months Ended

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

Inventory by Product Type [Abstract]

NGLs

$ 1,888.1

$ 1,094.9

Petrochemicals and refined products

642.6

311.5

Crude oil

758.1

674.2

Natural gas

14.7

10.8

Total

3,303.5

2,091.4

Summary of cost of sales and lower of cost or net realizable value adjustments [Abstract]

Cost of sales

^[1]

16,723.2

22,065.8

$ 26,789.8

Lower of cost or net realizable value adjustments recognized in cost of sales

$ 60.2

$ 22.7

$ 11.5

[1]	Cost of sales is a component of “Operating costs and expenses,” as presented on our Statements of Consolidated Operations. Fluctuations in these amounts are primarily due to changes in energy commodity prices and sales volumes associated with our marketing activities.

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

12 Months Ended

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

Property, plant and equipment and accumulated depreciation [Abstract]

Property, plant and equipment, gross

$ 57,497.5

$ 55,285.0

Less accumulated depreciation

15,584.7

13,681.6

Property, plant and equipment, net

41,912.8

41,603.4

$ 38,737.6

Summary of depreciation expense and capitalized interest [Abstract]

Depreciation expense

^[1]

1,681.9

1,562.6

1,436.2

Capitalized interest

^[2]

115.0

143.8

147.9

Asset Retirement Obligations [Roll Forward]

ARO liability beginning balance

132.1

126.3

86.7

Liabilities incurred

4.6

5.0

24.4

Liabilities settled

(1.5)

(2.3)

(2.5)

Revisions in estimated cash flows

6.1

(4.8)

11.5

Accretion expense

8.2

7.9

6.2

ARO liability ending balance

149.5

132.1

$ 126.3

Capitalized costs, asset retirement costs

69.7

69.6

Forecasted accretion expense [Abstract]

8.6

9.1

9.6

10.3

10.9

Plants, pipelines and facilities [Member]

Property, plant and equipment and accumulated depreciation [Abstract]

Property, plant and equipment, gross

^[3]

$ 49,972.8

47,201.2

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]

$ 4,207.5

3,965.5

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]

$ 204.9

198.9

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]

$ 932.7

905.9

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

$ 371.9

372.3

Construction in progress [Member]

Property, plant and equipment and accumulated depreciation [Abstract]

Property, plant and equipment, gross

$ 1,807.7

$ 2,641.2

Processing plants [Member] | Minimum [Member]

Property, plant and equipment and accumulated depreciation [Abstract]

Estimated useful life

20 years

Processing plants [Member] | Maximum [Member]

Property, plant and equipment and accumulated depreciation [Abstract]

Estimated useful life

35 years

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

Property, plant and equipment and accumulated depreciation [Abstract]

Estimated useful life

5 years

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

Property, plant and equipment and accumulated depreciation [Abstract]

Estimated useful life

45 years

Terminal facilities [Member] | Minimum [Member]

Property, plant and equipment and accumulated depreciation [Abstract]

Estimated useful life

10 years

Terminal facilities [Member] | Maximum [Member]

Property, plant and equipment and accumulated depreciation [Abstract]

Estimated useful life

35 years

Buildings [Member] | Minimum [Member]

Property, plant and equipment and accumulated depreciation [Abstract]

Estimated useful life

20 years

Buildings [Member] | Maximum [Member]

Property, plant and equipment and accumulated depreciation [Abstract]

Estimated useful life

40 years

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

Property, plant and equipment and accumulated depreciation [Abstract]

Estimated useful life

3 years

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

Property, plant and equipment and accumulated depreciation [Abstract]

Estimated useful life

20 years

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

Property, plant and equipment and accumulated depreciation [Abstract]

Estimated useful life

5 years

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

Property, plant and equipment and accumulated depreciation [Abstract]

Estimated useful life

35 years

Underground storage facilities [Member] | Minimum [Member]

Property, plant and equipment and accumulated depreciation [Abstract]

Estimated useful life

5 years

Underground storage facilities [Member] | Maximum [Member]

Property, plant and equipment and accumulated depreciation [Abstract]

Estimated useful life

35 years

Storage tanks [Member] | Minimum [Member]

Property, plant and equipment and accumulated depreciation [Abstract]

Estimated useful life

10 years

Storage tanks [Member] | Maximum [Member]

Property, plant and equipment and accumulated depreciation [Abstract]

Estimated useful life

40 years

Water wells [Member] | Minimum [Member]

Property, plant and equipment and accumulated depreciation [Abstract]

Estimated useful life

5 years

Water wells [Member] | Maximum [Member]

Property, plant and equipment and accumulated depreciation [Abstract]

Estimated useful life

35 years

[1]	Depreciation expense is a component of “Costs and expenses” as presented on our Statements of Consolidated Operations.
[2]	Capitalized interest is a component of “Interest expense” as presented on our Statements of Consolidated Operations.
[3]	Plants, pipelines and facilities include processing plants; NGL, natural gas, crude oil and petrochemical and refined products pipelines; terminal loading and unloading facilities; buildings; office furniture and equipment; laboratory and shop equipment and related assets.
[4]	In general, the estimated useful lives of major assets within this category are: processing plants, 20-35 years; pipelines and related equipment, 5-45 years; terminal facilities, 10-35 years; buildings, 20-40 years; office furniture and equipment, 3-20 years; and laboratory and shop equipment, 5-35 years.
[5]	Underground and other storage facilities include underground product storage caverns; above ground storage tanks; water wells and related assets.
[6]	In general, the estimated useful lives of assets within this category are: underground storage facilities, 5-35 years; storage tanks, 10-40 years; and water wells, 5-35 years.
[7]	Transportation equipment includes tractor-trailer tank trucks and other vehicles and similar assets used in our operations.
[8]	Marine vessels include tow boats, barges and related equipment used in our marine transportation business.

Property, Plant and Equipment, Impairments (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020 USD ($) Towboat Tankbarges	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)
Asset Impairment Charges [Abstract]
Impairment of property, plant and equipment	$ 589.8	$ 51.1	$ 46.8
Total asset impairment charges	890.6	132.8	50.5
Reclassification of construction in progress to other assets	311.7
Midland-to-Echo 4 Pipeline [Member] \| Crude Oil Pipelines & Services [Member]
Asset Impairment Charges [Abstract]
Impairment of property, plant and equipment	42.2
South Texas natural gas gathering and processing assets [Member]
Asset Impairment Charges [Abstract]
Impairment of property, plant and equipment	124.7
Impairment of intangible assets	1.0
Total asset impairment charges	125.7
Assets, fair value	21.3
South Texas natural gas gathering and processing assets [Member] \| NGL Pipelines & Services [Member]
Asset Impairment Charges [Abstract]
Impairment of property, plant and equipment	86.9	15.6
South Texas natural gas gathering and processing assets [Member] \| Natural Gas Pipelines & Services [Member]
Asset Impairment Charges [Abstract]
Impairment of property, plant and equipment	37.8
Marine transportation business [Member] \| Petrochemical & Refined Products Services [Member]
Asset Impairment Charges [Abstract]
Impairment of property, plant and equipment	252.1
Impairment of intangible assets	4.6
Total asset impairment charges	256.7
Assets, fair value	$ 410.0
Number of tow boats \| Towboat	65
Number of tank barges \| Tankbarges	160
Other [Member] \| NGL Pipelines & Services [Member]
Asset Impairment Charges [Abstract]
Impairment of property, plant and equipment	$ 121.2	23.5	18.6
Other [Member] \| Crude Oil Pipelines & Services [Member]
Asset Impairment Charges [Abstract]
Impairment of property, plant and equipment	3.3	2.6	11.2
Other [Member] \| Natural Gas Pipelines & Services [Member]
Asset Impairment Charges [Abstract]
Impairment of property, plant and equipment	5.5	4.8	13.9
Other [Member] \| Petrochemical & Refined Products Services [Member]
Asset Impairment Charges [Abstract]
Impairment of property, plant and equipment	$ 40.8	$ 4.6	$ 3.1

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

12 Months Ended

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

Schedule of Equity Method Investments [Line Items]

Investments in unconsolidated affiliates

$ 2,429.2

$ 2,600.2

$ 2,615.1

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

Equity in income (loss) of unconsolidated affiliates

426.1

563.0

480.0

NGL Pipelines & Services [Member]

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

Equity in income (loss) of unconsolidated affiliates

$ 121.3

114.5

117.0

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

$ 23.4

23.2

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

$ 23.0

25.7

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

Schedule of Equity Method Investments [Line Items]

Ownership interest

32.20%

Investments in unconsolidated affiliates

$ 13.8

15.6

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

$ 31.6

33.1

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

Schedule of Equity Method Investments [Line Items]

Ownership interest

35.00%

Investments in unconsolidated affiliates

$ 342.8

358.1

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

Schedule of Equity Method Investments [Line Items]

Ownership interest

45.00%

Investments in unconsolidated affiliates

$ 37.7

41.1

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

Schedule of Equity Method Investments [Line Items]

Ownership interest

33.30%

Investments in unconsolidated affiliates

$ 199.3

207.0

Crude Oil Pipelines & Services [Member]

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

Equity in income (loss) of unconsolidated affiliates

$ 301.2

449.2

365.4

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

$ 1,224.0

1,353.1

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

$ 376.8

386.5

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

$ 122.9

126.9

Natural Gas Pipelines & Services [Member]

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

Equity in income (loss) of unconsolidated affiliates

$ 5.8

6.3

6.8

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

$ 18.2

19.1

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

$ 13.2

8.2

Petrochemical & Refined Products Services [Member]

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

Equity in income (loss) of unconsolidated affiliates

^[1]

$ (2.2)

(7.0)

$ (9.2)

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

Schedule of Equity Method Investments [Line Items]

Ownership interest

50.00%

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

$ 1.6

2.0

Petrochemical & Refined Products Services [Member] | Transport 4, LLC [Member]

Schedule of Equity Method Investments [Line Items]

Ownership interest

25.00%

Investments in unconsolidated affiliates

$ 0.9

$ 0.6

[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.

Intangible Assets and Goodwill, Intangible Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Identifiable intangible assets [Abstract]
Gross Value	$ 5,135.8	$ 5,136.5
Accumulated Amortization	(1,826.7)	(1,687.5)
Carrying Value	3,309.1	3,449.0	$ 3,608.4
Amortization expense	143.2	174.7	170.3
Forecasted amortization expense [Abstract]
2021	144.5
2022	161.3
2023	169.0
2024	165.1
2025	163.5
Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Carrying Value	3,080.0
Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Carrying Value	228.0
NGL Pipelines & Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	610.4	610.4
Accumulated Amortization	(276.3)	(250.2)
Carrying Value	334.1	360.2
Amortization expense	25.2	31.9	34.7
NGL Pipelines & Services [Member] \| Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	447.8	447.8
Accumulated Amortization	(221.3)	(206.3)
Carrying Value	226.5	241.5
NGL Pipelines & Services [Member] \| Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	162.6	162.6
Accumulated Amortization	(55.0)	(43.9)
Carrying Value	107.6	118.7
Crude Oil Pipelines & Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	2,478.1	2,480.4
Accumulated Amortization	(541.5)	(478.5)
Carrying Value	1,936.6	2,001.9
Amortization expense	71.5	92.7	87.8
Crude Oil Pipelines & Services [Member] \| Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	2,195.0	2,203.5
Accumulated Amortization	(291.6)	(243.5)
Carrying Value	1,903.4	1,960.0
Crude Oil Pipelines & Services [Member] \| Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	283.1	276.9
Accumulated Amortization	(249.9)	(235.0)
Carrying Value	33.2	41.9
Natural Gas Pipelines & Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	1,821.0	1,818.3
Accumulated Amortization	(916.0)	(877.1)
Carrying Value	905.0	941.2
Amortization expense	38.8	41.4	39.1
Natural Gas Pipelines & Services [Member] \| Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	1,350.3	1,350.3
Accumulated Amortization	(512.2)	(481.6)
Carrying Value	838.1	868.7
Natural Gas Pipelines & Services [Member] \| Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	470.7	468.0
Accumulated Amortization	(403.8)	(395.5)
Carrying Value	66.9	72.5
Petrochemical & Refined Products Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	226.3	227.4
Accumulated Amortization	(92.9)	(81.7)
Carrying Value	133.4	145.7
Amortization expense	7.7	8.7	$ 8.7
Petrochemical & Refined Products Services [Member] \| Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	181.4	181.4
Accumulated Amortization	(68.3)	(57.5)
Carrying Value	113.1	123.9
Petrochemical & Refined Products Services [Member] \| Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	44.9	46.0
Accumulated Amortization	(24.6)	(24.2)
Carrying Value	$ 20.3	$ 21.8

Intangible Assets and Goodwill, Significant Intangible Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Identifiable intangible assets [Abstract]
Gross Value	$ 5,135.8	$ 5,136.5
Accumulated Amortization	(1,826.7)	(1,687.5)
Carrying Value	3,309.1	$ 3,449.0	$ 3,608.4
Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Carrying Value	3,080.0
Impairment of customer relationship intangible assets	5.6
Customer relationship intangibles [Member] \| EFS Midstream [Member]
Identifiable intangible assets [Abstract]
Gross Value	1,409.8
Accumulated Amortization	(188.1)
Carrying Value	$ 1,221.7
Weighted Average Remaining Amortization Period	21 years 4 months 24 days
Customer relationship intangibles [Member] \| State Line and Fairplay [Member]
Identifiable intangible assets [Abstract]
Gross Value	$ 895.0
Accumulated Amortization	(224.0)
Carrying Value	$ 671.0
Weighted Average Remaining Amortization Period	26 years 2 months 12 days
Customer relationship intangibles [Member] \| San Juan Gathering [Member]
Identifiable intangible assets [Abstract]
Gross Value	$ 331.3
Accumulated Amortization	(245.3)
Carrying Value	$ 86.0
Weighted Average Remaining Amortization Period	18 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	(162.6)
Carrying Value	$ 1,029.9
Weighted Average Remaining Amortization Period	23 years
Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Carrying Value	$ 228.0
Contract-based intangibles [Member] \| Oiltanking Partners L.P. [Member]
Identifiable intangible assets [Abstract]
Gross Value	293.3
Accumulated Amortization	(261.7)
Carrying Value	$ 31.6
Weighted Average Remaining Amortization Period	3 years
Contract-based intangibles [Member] \| Jonah Gas Gathering [Member]
Identifiable intangible assets [Abstract]
Gross Value	$ 224.4
Accumulated Amortization	(175.8)
Carrying Value	$ 48.6
Weighted Average Remaining Amortization Period	21 years
Contract-based intangibles [Member] \| Delaware Basin Gas Processing LLC [Member]
Identifiable intangible assets [Abstract]
Gross Value	$ 82.6
Accumulated Amortization	(23.7)
Carrying Value	$ 58.9
Weighted Average Remaining Amortization Period	6 years

Intangible Assets and Goodwill, Goodwill (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Changes in carrying amount of goodwill [Roll Forward]
Balance at beginning of period	$ 5,745.2	$ 5,745.2
Impairment of goodwill	(296.3)	0.0	$ 0.0
Balance at end of period	5,448.9	5,745.2	5,745.2
NGL Pipelines & Services [Member]
Changes in carrying amount of goodwill [Roll Forward]
Balance at beginning of period	2,651.7	2,651.7
Impairment of goodwill	0.0
Balance at end of period	2,651.7	2,651.7	2,651.7
Crude Oil Pipelines & Services [Member]
Changes in carrying amount of goodwill [Roll Forward]
Balance at beginning of period	1,841.0	1,841.0
Impairment of goodwill	0.0
Balance at end of period	1,841.0	1,841.0	1,841.0
Natural Gas Pipelines & Services [Member]
Changes in carrying amount of goodwill [Roll Forward]
Balance at beginning of period	296.3	296.3
Impairment of goodwill	(296.3)
Balance at end of period	0.0	296.3	296.3
Petrochemical & Refined Products Services [Member]
Changes in carrying amount of goodwill [Roll Forward]
Balance at beginning of period	956.2	956.2
Impairment of goodwill	0.0
Balance at end of period	$ 956.2	$ 956.2	$ 956.2

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

1 Months Ended

12 Months Ended

Mar. 31, 2021

Feb. 28, 2021

Aug. 31, 2020

Jan. 31, 2020

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

Debt Instrument [Line Items]

Principal outstanding

$ 30,146.4

$ 27,878.4

Other, non-principal amounts

(280.7)

(253.3)

Less current maturities of debt

(1,325.0)

(1,981.9)

Total long-term debt

28,540.7

25,643.2

Debt Obligations Terms:

Repayment of debt obligations

4,406.6

56,716.5

$ 77,957.1

Letters of credit outstanding for facilities and motor fuel tax obligations

200.7

Senior Debt Obligations [Member]

Debt Instrument [Line Items]

Principal outstanding

27,500.0

25,232.0

Senior Debt Obligations [Member] | Commercial Paper Notes [Member]

Debt Instrument [Line Items]

Principal outstanding

0.0

482.0

Debt Obligations Terms:

Maximum borrowing capacity

$ 3,000.0

Information regarding variable interest rates paid:

Weighted-average interest rate paid

1.86%

Senior Debt Obligations [Member] | Commercial Paper Notes [Member] | Minimum [Member]

Information regarding variable interest rates paid:

Variable interest rates paid

1.78%

Senior Debt Obligations [Member] | Commercial Paper Notes [Member] | Maximum [Member]

Information regarding variable interest rates paid:

Variable interest rates paid

2.08%

Senior Debt Obligations [Member] | EPO Senior Notes Q, due January 2020 [Member]

Debt Instrument [Line Items]

Principal outstanding

$ 0.0

500.0

Debt Obligations Terms:

Interest rate, stated percentage

5.25%

Repayment of debt obligations

$ 500.0

Senior Debt Obligations [Member] | EPO Senior Notes Y, due September 2020 [Member]

Debt Instrument [Line Items]

Principal outstanding

$ 0.0

1,000.0

Debt Obligations Terms:

Interest rate, stated percentage

5.20%

Repayment of debt obligations

$ 1,000.0

Senior Debt Obligations [Member] | EPO Senior Notes TT, due February 2021 [Member]

Debt Instrument [Line Items]

Principal outstanding

$ 750.0

750.0

Debt Obligations Terms:

Interest rate, stated percentage

2.80%

Senior Debt Obligations [Member] | EPO Senior Notes TT, due February 2021 [Member] | Subsequent Event [Member]

Debt Obligations Terms:

Repayment of debt obligations

$ 750.0

Senior Debt Obligations [Member] | EPO Senior Notes RR, due April 2021 [Member]

Debt Instrument [Line Items]

Principal outstanding

$ 575.0

575.0

Debt Obligations Terms:

Interest rate, stated percentage

2.85%

Senior Debt Obligations [Member] | EPO Senior Notes RR, due April 2021 [Member] | Forecast [Member]

Debt Obligations Terms:

Repayment of debt obligations

$ 575.0

Senior Debt Obligations [Member] | September 2020 EPO 364-Day Revolving Credit Agreement, due September 2021 [Member]

Debt Instrument [Line Items]

Principal outstanding

$ 0.0

0.0

Debt Obligations Terms:

Maximum borrowing capacity

1,500.0

Maximum bank commitments increase

200.0

Total maximum borrowing capacity

$ 1,700.0

Information regarding variable interest rates paid:

Credit facility interest rate description

Senior Debt Obligations [Member] | EPO Senior Notes VV, due February 2022 [Member]

Debt Instrument [Line Items]

Principal outstanding

$ 750.0

750.0

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

$ 650.0

650.0

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

$ 1,250.0

1,250.0

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

$ 850.0

850.0

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

0.0

Debt Obligations Terms:

Maximum borrowing capacity

3,500.0

Maximum bank commitments increase

500.0

Total maximum borrowing capacity

$ 4,000.0

Information regarding variable interest rates paid:

Credit facility interest rate description

Senior Debt Obligations [Member] | EPO Senior Notes MM, due February 2025 [Member]

Debt Instrument [Line Items]

Principal outstanding

$ 1,150.0

1,150.0

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

$ 875.0

875.0

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

$ 575.0

575.0

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

$ 1,000.0

1,000.0

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

1,250.0

Debt Obligations Terms:

Interest rate, stated percentage

3.125%

Senior Debt Obligations [Member] | EPO Senior Notes AAA, due January 2030 [Member]

Debt Instrument [Line Items]

Principal outstanding

$ 1,250.0

0.0

Debt Obligations Terms:

Interest rate, stated percentage

2.80%

Aggregate debt principal issued

$ 250.0

$ 1,000.0

Debt issued as percent of principal amount

107.211%

99.921%

Senior Debt Obligations [Member] | EPO Senior Notes D, due March 2033 [Member]

Debt Instrument [Line Items]

Principal outstanding

$ 500.0

500.0

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

$ 350.0

350.0

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

$ 250.0

250.0

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

$ 600.0

600.0

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

$ 600.0

600.0

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

$ 750.0

750.0

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

$ 600.0

600.0

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

$ 750.0

750.0

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

$ 1,100.0

1,100.0

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

$ 1,400.0

1,400.0

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

$ 1,150.0

1,150.0

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

$ 975.0

975.0

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

$ 1,250.0

1,250.0

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

$ 1,250.0

1,250.0

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

1,250.0

Debt Obligations Terms:

Interest rate, stated percentage

4.20%

Senior Debt Obligations [Member] | EPO Senior Notes BBB, due January 2051 [Member]

Debt Instrument [Line Items]

Principal outstanding

$ 1,000.0

0.0

Debt Obligations Terms:

Interest rate, stated percentage

3.70%

Aggregate debt principal issued

$ 1,000.0

Debt issued as percent of principal amount

99.413%

Senior Debt Obligations [Member] | EPO Senior Notes DDD, due February 2052 [Member]

Debt Instrument [Line Items]

Principal outstanding

$ 1,000.0

0.0

Debt Obligations Terms:

Interest rate, stated percentage

3.20%

Aggregate debt principal issued

$ 1,000.0

Debt issued as percent of principal amount

99.233%

Senior Debt Obligations [Member] | EPO Senior Notes NN, due October 2054 [Member]

Debt Instrument [Line Items]

Principal outstanding

$ 400.0

400.0

Debt Obligations Terms:

Interest rate, stated percentage

4.95%

Senior Debt Obligations [Member] | EPO Senior Notes CCC, due January 2060 [Member]

Debt Instrument [Line Items]

Principal outstanding

$ 1,000.0

0.0

Debt Obligations Terms:

Interest rate, stated percentage

3.95%

Aggregate debt principal issued

$ 1,000.0

Debt issued as percent of principal amount

99.36%

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

700.0

Junior Debt Obligations [Member] | EPO Junior Subordinated Notes C, due June 2067 [Member]

Debt Instrument [Line Items]

Principal outstanding

^[1]

$ 232.2

232.2

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

3.66%

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

3.00%

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

4.68%

Junior Debt Obligations [Member] | EPO Junior Subordinated Notes D, due August 2077 [Member]

Debt Instrument [Line Items]

Principal outstanding

^[2]

$ 700.0

700.0

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]

$ 1,000.0

1,000.0

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]

$ 700.0

700.0

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

3.66%

Junior Debt Obligations [Member] | TEPPCO Junior Subordinated Notes, due June 2067 [Member] | Minimum [Member]

Information regarding variable interest rates paid:

Variable interest rates paid

3.00%

Junior Debt Obligations [Member] | TEPPCO Junior Subordinated Notes, due June 2067 [Member] | Maximum [Member]

Information regarding variable interest rates paid:

Variable interest rates paid

4.68%

Senior Notes [Member]

Debt Instrument [Line Items]

Principal outstanding

$ 27,500.0

Debt Obligations Terms:

Aggregate debt principal issued

$ 3,000.0

$ 4,250.0

$ 2,500.0

$ 5,000.0

[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 Maturities (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Scheduled Maturities of Debt [Abstract]
2021	$ 1,325.0
2022	1,400.0
2023	1,250.0
2024	850.0
2025	1,150.0
Thereafter	24,171.4
Total	30,146.4	$ 27,878.4
Senior Notes [Member]
Scheduled Maturities of Debt [Abstract]
2021	1,325.0
2022	1,400.0
2023	1,250.0
2024	850.0
2025	1,150.0
Thereafter	21,525.0
Total	27,500.0
Junior Subordinated Notes [Member]
Scheduled Maturities of Debt [Abstract]
2021	0.0
2022	0.0
2023	0.0
2024	0.0
2025	0.0
Thereafter	2,646.4
Total	$ 2,646.4

Capital Accounts, Summary of Changes in Outstanding Units (Details) - Common Units [Member] - shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Summary of changes in outstanding units [Roll Forward]
Number of common units outstanding, beginning balance (in units)	2,189,226,130	2,184,869,029	2,161,089,479
Common units issued to Skyline North Americas, Inc. in connection with settlement of Liquidity Option in March 2020 (in units)	54,807,352
Treasury units acquired in connection with settlement of Liquidity Option in March 2020 (in units)	(54,807,352)
Common unit repurchases under buyback program (in units)	(8,978,317)	(2,909,128)	(1,236,800)
Common units issued in connection with the vesting of phantom unit awards, net (in units)	3,162,095	2,720,603	2,442,436
Common units exchanged for preferred units in September 2020, with the common units received being immediately cancelled (in units)	(1,120,588)
Common units issued in connection with DRIP and EUPP (in units)		2,897,990	19,861,951
Common units issued in connection with employee compensation (in units)		1,626,041	1,443,586
Common units issued in connection with land acquisition (in units)			1,223,242
Other (in units)	19,638	21,595	45,135
Number of common units outstanding, ending balance (in units)	2,182,308,958	2,189,226,130	2,184,869,029

Capital Accounts, Issuances of Equity (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2020 USD ($) Contract shares	Dec. 31, 2019 USD ($) shares	Dec. 31, 2018 USD ($) shares	Mar. 05, 2020 $ / shares	Dec. 31, 2014
Net Cash Proceeds from Sale of Common Units [Abstract]
Net cash proceeds from the issuance of common units	$ 0.0	$ 82.2	$ 538.4
Common units issued in connection with employee compensation		45.6	39.1
Liquidity Option Agreement [Abstract]
Limited partner interest of Oiltanking acquired					65.90%
Percentage of capital stock we agreed to purchase under liquidity option agreement	100.00%
Liquidity Option exercise period	90 days
Common units issued to Skyline North Americas, Inc. in connection with settlement of Liquidity Option	$ 1,297.3
Common units acquired in connection with buyback program	186.3	81.1	30.8
Capital expenditures	$ 3,287.9	$ 4,531.7	4,223.2
Land [Member]
Liquidity Option Agreement [Abstract]
Property, plant and equipment, additions			85.2
Capital expenditures			$ 55.2
Common units issued in connection with land acquisition (in units) \| shares			1,223,242
Phantom Unit Awards [Member]
Liquidity Option Agreement [Abstract]
Common units issued in connection with the vesting of phantom unit awards, net (in units) \| shares	3,162,095	2,720,603	2,442,436
Enterprise Products Partners L.P. [Member]
Liquidity Option Agreement [Abstract]
Closing price (in dollars per unit) \| $ / shares				$ 23.67
2019 Buyback Program [Member]
Liquidity Option Agreement [Abstract]
Total of common units repurchased under a buyback program (in units) \| shares	8,978,317	2,909,128
Common units acquired in connection with buyback program	$ 186.3	$ 81.1
Amount authorized under 2019 Buyback Program	2,000.0
Remaining available capacity under the 2019 Buyback Program	1,730.0
Legacy Buyback Program [Member]
Liquidity Option Agreement [Abstract]
Maximum common units authorized for repurchase under a buyback program (in units) \| shares			4,000,000
Total of common units repurchased under a buyback program (in units) \| shares			1,236,800
Common units acquired in connection with buyback program			$ 30.8
Long-Term Incentive Plan (2008) [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Common units issued in connection with employee compensation (in units) \| shares		1,626,041	1,443,586
Universal Shelf Registration [Member] \| Senior Debt Obligations [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Debt issued under universal shelf registration	4,250.0
At-the-Market Registration [Member]
Registration Statements and Equity Offerings [Line Items]
Maximum common units authorized for issuance	2,540.0
Net Cash Proceeds from Sale of Common Units [Abstract]
Remaining units available for issuance	2,540.0
Skyline Registration Rights Agreement [Member]
Registration Statements and Equity Offerings [Line Items]
Maximum common units authorized for issuance	$ 500.0
Liquidity Option Agreement [Abstract]
Number of registration statements following exercise of Liquidity Option \| Contract	5
Distribution Reinvestment Plan [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Remaining units available for issuance (in units) \| shares	50,615,246
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		$ 29.0	$ 213.0
Employee Unit Purchase Plan [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Employer contribution to EUPP	$ 2.4	$ 0.9
Remaining units available for issuance (in units) \| shares	3,318,607
Distribution Reinvestment and Employee Unit Purchase Plans [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Number of common units issued (in units) \| shares		2,897,990	19,861,951
Number of common units purchased on the open market and delivered to participants (in units) \| shares	6,982,963	2,801,196
Net cash proceeds from the issuance of common units		$ 82.2	$ 538.4

Capital Accounts, Redeemable Preferred Limited Partner Interests (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	3 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Temporary Equity [Line Items]
Treasury units		$ 1,297.3	$ 1,297.3	$ 0.0
Series A cumulative convertible preferred units (in dollars per unit)		$ 1,000	$ 1,000
Series A cumulative convertible preferred units issued (in units)	35,000
Series A cumulative convertible preferred units outstanding (in units)	50,000	50,138	50,138
Cash proceeds from the issuance of preferred units	$ 32.5		$ 31.5	$ 0.0	$ 0.0
Common units exchanged for preferred units, with common units received being immediately cancelled	17.5		17.5
Total offering price for redeemable noncontrolling interests	$ 50.0
Offering expenses			1.0
Total distributions paid to convertible preferred unitholders			0.5
Cash distributions paid to convertible preferred unitholders			$ 0.3
Preferred unit distribution rate			7.25%
Redemption price per preferred unit after September 30, 2025 at unitholder election (in dollars per unit)			$ 1,000
Redemption price per preferred unit from September 30, 2020 through September 29, 2022 (in dollars per unit)			1,100
Redemption price per preferred unit from September 30, 2022 through September 29, 2024 (in dollars per unit)			1,070
Redemption price per preferred unit from September 30, 2024 through September 29, 2025 (in dollars per unit)			1,030
Redemption price per preferred unit from September 30, 2025 through September 29, 2026 (in dollars per unit)			1,010
Redemption price per preferred unit on or after September 30, 2026 (in dollars per unit)			1,000
Redemption price per preferred unit if Change of Control event occurs (in dollars per unit)			$ 1,010
Percentage applied to the common unit market price in calculating the number of common units to be acquired upon the conversion of series A preferred units to common units			92.50%
Percentage of preferred units that may be converted into common units at unitholder option			50.00%
EPCO and its privately held affiliates [Member]
Temporary Equity [Line Items]
Series A cumulative convertible preferred units issued (in units)	15,000
Series A cumulative convertible preferred units, paid-in kind distribution (in units)		138
Cash proceeds from the issuance of preferred units	$ 15.0
Preferred Units [Member]
Temporary Equity [Line Items]
Treasury units outstanding (preferred units) (in units)	855,915
Common Units [Member]
Temporary Equity [Line Items]
Common units exchanged for preferred units in September 2020, with the common units received being immediately cancelled (in units)			1,120,588

Capital Accounts, Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Accumulated Other Comprehensive Income (Loss) [Abstract]
Accumulated Other Comprehensive Income (Loss), Beginning Balance	$ 71.4	$ 50.9
Other comprehensive income (loss) for period, before reclassifications	(3.2)	124.9
Reclassification of losses (gains) to net income during period	(233.4)	(104.4)
Total other comprehensive income (loss) for period	(236.6)	20.5	$ 222.6
Accumulated Other Comprehensive Income (Loss), Ending balance	(165.2)	71.4	50.9
Interest expense	1,287.4	1,243.0	1,096.7
Revenue	(27,199.7)	(32,789.2)	(36,534.2)
Operating costs and expenses	22,371.1	27,061.8	31,397.3
Total	(3,885.7)	(4,687.1)	(4,238.5)
Cash Flow Hedges [Member] \| Commodity Derivatives [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Accumulated Other Comprehensive Income (Loss), Beginning Balance	55.1	152.7
Other comprehensive income (loss) for period, before reclassifications	124.4	44.1
Reclassification of losses (gains) to net income during period	(272.7)	(141.7)
Total other comprehensive income (loss) for period	(148.3)	(97.6)
Accumulated Other Comprehensive Income (Loss), Ending balance	(93.2)	55.1	152.7
Cash Flow Hedges [Member] \| Interest Rate Derivatives [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Accumulated Other Comprehensive Income (Loss), Beginning Balance	13.9	(104.8)
Other comprehensive income (loss) for period, before reclassifications	(127.5)	81.4
Reclassification of losses (gains) to net income during period	39.3	37.3
Total other comprehensive income (loss) for period	(88.2)	118.7
Accumulated Other Comprehensive Income (Loss), Ending balance	(74.3)	13.9	(104.8)
Other [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Accumulated Other Comprehensive Income (Loss), Beginning Balance	2.4	3.0
Other comprehensive income (loss) for period, before reclassifications	(0.1)	(0.6)
Reclassification of losses (gains) to net income during period	0.0	0.0
Total other comprehensive income (loss) for period	(0.1)	(0.6)
Accumulated Other Comprehensive Income (Loss), Ending balance	2.3	2.4	$ 3.0
Reclassification out of Accumulated Other Comprehensive Income (Loss) [Member] \| Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Total	(233.4)	(104.4)
Reclassification out of Accumulated Other Comprehensive Income (Loss) [Member] \| Cash Flow Hedges [Member] \| Commodity Derivatives [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Revenue	(282.6)	(152.4)
Operating costs and expenses	9.9	10.7
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	$ 39.3	$ 37.3

Capital Accounts, Noncontrolling Interests (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

Noncontrolling Interest

Noncontrolling interests

$ 1,073.3

$ 1,063.5

Net income attributable to noncontrolling interests

110.1

95.8

$ 66.1

Breviloba LLC [Member]

Noncontrolling Interest

Noncontrolling Interest, Increase from Sale of Parent Equity Interest

440.7

Noncontrolling interests

^[1]

480.4

492.9

Whitehorn Pipeline Company LLC [Member]

Noncontrolling Interest

Noncontrolling Interest, Increase from Sale of Parent Equity Interest

$ 189.6

Noncontrolling interests

^[2]

193.0

198.9

Enterprise Navigator Ethylene Terminal LLC [Member]

Noncontrolling Interest

Noncontrolling interests

^[3]

142.2

124.3

Other [Member]

Noncontrolling Interest

Noncontrolling interests

^[4]

$ 257.7

$ 247.4

Altus Midstream Processing LP [Member] | Breviloba LLC [Member]

Noncontrolling Interest

Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners

33.00%

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%

[1]	Altus Midstream Processing LP acquired a noncontrolling 33% equity interest in Breviloba, which owns the Shin Oak NGL Pipeline, in July 2019 for $440.7 million in cash.
[2]	An affiliate of Western Gas Partners, LP acquired a noncontrolling 20% equity interest in Whitethorn, which owns the majority of our Midland-to-ECHO 1 pipeline, in June 2018 for $189.6 million in cash.
[3]	Navigator Ethylene Terminals LLC owns a noncontrolling 50% equity interest in ENET, which owns our ethylene export terminal located at Morgan’s Point on the Houston Ship Channel.
[4]	Primarily represents noncontrolling equity interests in NGL fractionation and pipeline businesses.

Capital Accounts, Distributions (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended
	Feb. 28, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Distributions to Partners [Abstract]
Number of days after quarter end to distribute available cash		45 days
Cash payments made in connection with distribution equivalent rights		$ 27.1	$ 22.1	$ 17.7
Subsequent Event [Member]
Distributions to Partners [Abstract]
Cash distributions paid	$ 988.8
Cash payments made in connection with distribution equivalent rights	$ 7.1
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 08, 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. 08, 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. 08, 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. 08, 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] \| First Quarter 2020 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)		$ 0.4450
Record Date		Apr. 30, 2020
Payment Date		May 12, 2020
Cash Distribution [Member] \| Second Quarter 2020 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)		$ 0.4450
Record Date		Jul. 31, 2020
Payment Date		Aug. 12, 2020
Cash Distribution [Member] \| Third Quarter 2020 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)		$ 0.4450
Record Date		Oct. 30, 2020
Payment Date		Nov. 12, 2020
Cash Distribution [Member] \| Fourth Quarter 2020 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)		$ 0.4500
Record Date		Jan. 29, 2021
Payment Date		Feb. 11, 2021

Revenues, Revenues by Business Segment and Revenue Type (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Revenue [Abstract]
Revenues	$ 27,199.7	$ 32,789.2	$ 36,534.2
NGL Pipelines & Services [Member]
Revenue [Abstract]
Revenues	11,177.2	13,470.7	15,648.9
NGL Pipelines & Services [Member] \| Sales of NGLs and Related Products [Member]
Revenue [Abstract]
Revenues	8,970.7	10,934.3	12,920.9
NGL Pipelines & Services [Member] \| Midstream Services [Member]
Revenue [Abstract]
Revenues	2,206.5	2,536.4	2,728.0
NGL Pipelines & Services [Member] \| Midstream Services: Natural Gas Processing and Fractionation [Member]
Revenue [Abstract]
Revenues	757.3	1,069.9	1,341.0
NGL Pipelines & Services [Member] \| Midstream Services: Transportation [Member]
Revenue [Abstract]
Revenues	1,036.8	1,054.3	1,007.0
NGL Pipelines & Services [Member] \| Midstream Services: Storage and Terminals [Member]
Revenue [Abstract]
Revenues	412.4	412.2	380.0
Crude Oil Pipelines & Services [Member]
Revenue [Abstract]
Revenues	6,689.0	10,287.3	11,042.6
Crude Oil Pipelines & Services [Member] \| Sales of Crude Oil [Member]
Revenue [Abstract]
Revenues	5,410.8	9,007.8	10,001.2
Crude Oil Pipelines & Services [Member] \| Midstream Services [Member]
Revenue [Abstract]
Revenues	1,278.2	1,279.5	1,041.4
Crude Oil Pipelines & Services [Member] \| Midstream Services: Transportation [Member]
Revenue [Abstract]
Revenues	804.9	801.8	676.5
Crude Oil Pipelines & Services [Member] \| Midstream Services: Storage and Terminals [Member]
Revenue [Abstract]
Revenues	473.3	477.7	364.9
Natural Gas Pipelines & Services [Member]
Revenue [Abstract]
Revenues	2,553.1	3,169.4	3,454.4
Natural Gas Pipelines & Services [Member] \| Sales of Natural Gas [Member]
Revenue [Abstract]
Revenues	1,530.5	2,075.4	2,411.7
Natural Gas Pipelines & Services [Member] \| Midstream Services [Member]
Revenue [Abstract]
Revenues	1,022.6	1,094.0	1,042.7
Natural Gas Pipelines & Services [Member] \| Midstream Services: Transportation [Member]
Revenue [Abstract]
Revenues	1,022.6	1,094.0	1,042.7
Petrochemical & Refined Products Services [Member]
Revenue [Abstract]
Revenues	6,780.4	5,861.8	6,388.3
Petrochemical & Refined Products Services [Member] \| Sales of Petrochemicals and Refined Products [Member]
Revenue [Abstract]
Revenues	5,942.6	4,985.2	5,535.4
Petrochemical & Refined Products Services [Member] \| Midstream Services [Member]
Revenue [Abstract]
Revenues	837.8	876.6	852.9
Petrochemical & Refined Products Services [Member] \| Midstream Services: Fractionation and Isomerization [Member]
Revenue [Abstract]
Revenues	187.7	166.6	188.3
Petrochemical & Refined Products Services [Member] \| Midstream Services: Transportation [Member]
Revenue [Abstract]
Revenues	482.9	539.4	481.8
Petrochemical & Refined Products Services [Member] \| Midstream Services: Storage and Terminals [Member]
Revenue [Abstract]
Revenues	$ 167.2	$ 170.6	$ 182.8

Revenues, Unbilled Revenue and Deferred Revenue (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Contracts with Customers, Assets and Liabilities [Abstract]
Unbilled revenue	$ 18.8	$ 17.6	$ 13.3	$ 0.0
Deferred revenue	343.5	314.9	$ 291.2	$ 224.7
Other Current Assets [Member]
Contracts with Customers, Assets and Liabilities [Abstract]
Unbilled revenue (current amount)	18.8	17.6
Other Current Liabilities [Member]
Contracts with Customers, Assets and Liabilities [Abstract]
Deferred revenue (current amount)	145.3	117.9
Other Liabilities [Member]
Contracts with Customers, Assets and Liabilities [Abstract]
Deferred revenue (noncurrent)	$ 198.2	$ 197.0

Revenues, Significant Changes in Unbilled Revenue (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

Significant Changes in Unbilled Revenue

Balance at beginning of period

$ 17.6

$ 13.3

$ 0.0

Unbilled revenue included in opening balance transferred to other accounts during period

^[1]

(17.6)

(13.3)

0.0

Unbilled revenue recorded during period

^[2]

323.0

340.0

321.7

Unbilled revenue recorded during period transferred to other accounts

^[1]

(304.2)

(322.4)

(310.6)

Unbilled revenue recorded in connection with business combination

2.2

Other changes

0.0

Balance at end of period

$ 18.8

$ 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.
[2]	Unbilled revenue represents revenue that has been recognized upon satisfaction of a performance obligation, but cannot be contractually invoiced (or billed) to the customer at the balance sheet date until a future period. Deferred revenue is recorded when payment is received from a customer prior to our satisfaction of the associated performance obligation.

Revenues, Significant Changes in Deferred Revenue (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

Significant Changes in Deferred Revenue

Balance at beginning of period

$ 314.9

$ 291.2

$ 224.7

Deferred revenue included in opening balance transferred to other accounts during period

^[1]

(114.5)

(126.4)

(90.8)

Deferred revenue recorded during period

^[2]

661.2

539.8

432.5

Deferred revenue recorded during period transferred to other accounts

^[1]

(496.7)

(384.8)

(274.8)

Deferred revenue recorded in connection with business combination

0.0

Other changes

(21.4)

(4.9)

(0.4)

Balance at end of period

$ 343.5

$ 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.
[2]	Unbilled revenue represents revenue that has been recognized upon satisfaction of a performance obligation, but cannot be contractually invoiced (or billed) to the customer at the balance sheet date until a future period. Deferred revenue is recorded when payment is received from a customer prior to our satisfaction of the associated performance obligation.

Revenues, Remaining Performance Obligations (Details) $ in Millions	Dec. 31, 2020 USD ($)
Remaining Performance Obligation to be Recognized in the Future [Abstract]
Remaining performance obligation	$ 28,995.2
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	$ 3,906.4
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	$ 3,492.3
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	$ 3,110.2
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	$ 2,937.3
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	$ 2,636.5
Expected timing of satisfaction, period	1 year
Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Remaining Performance Obligation to be Recognized in the Future [Abstract]
Remaining performance obligation	$ 12,912.5
Expected timing of satisfaction, period

Business Segments (Details)	12 Months Ended
Business Segments (Details)	Dec. 31, 2020 Segment
Segment Reporting Information [Line Items]
Number of reportable segments	4

Business Segments, Gross Operating Margin (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

Business Segments [Abstract]

Operating income

$ 5,035.1

$ 6,078.7

$ 5,408.6

Adjustments to reconcile operating income to total segment gross operating margin (addition or subtraction indicated by sign):

Depreciation, amortization and accretion expense in operating costs and expenses

1,961.5

1,848.3

1,687.0

Asset impairment and related charges in operating costs and expenses

890.6

132.7

50.5

Net gains attributable to asset sales in operating costs and expenses

(4.4)

(5.7)

(28.7)

General and administrative costs

219.6

211.7

208.3

Non-refundable payments received from shippers attributable to make-up rights

^[1]

119.3

47.0

21.5

Subsequent recognition of revenues attributable to make-up rights

^[2]

(33.6)

(22.9)

(56.2)

Total segment gross operating margin

$ 8,188.1

$ 8,289.8

$ 7,291.0

[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 Reporting Information (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

Information by business segment [Abstract]

Gross operating margin

$ 8,188.1

$ 8,289.8

$ 7,291.0

Revenues from third parties

27,163.0

32,721.9

36,426.5

Revenues from related parties

36.7

67.3

107.7

Intersegment and intrasegment revenues

0.0

Total revenues

27,199.7

32,789.2

36,534.2

Equity in income (loss) of unconsolidated affiliates

426.1

563.0

480.0

Property, plant and equipment, net

41,912.8

41,603.4

38,737.6

Investments in unconsolidated affiliates

2,429.2

2,600.2

2,615.1

Intangible assets, net

3,309.1

3,449.0

3,608.4

Goodwill

5,448.9

5,745.2

Segment assets

53,100.0

53,397.8

50,706.3

NGL Pipelines and Services [Member]

Information by business segment [Abstract]

Total revenues

11,177.2

13,470.7

15,648.9

Equity in income (loss) of unconsolidated affiliates

121.3

114.5

117.0

Intangible assets, net

334.1

360.2

Goodwill

2,651.7

Crude Oil Pipelines & Services [Member]

Information by business segment [Abstract]

Total revenues

6,689.0

10,287.3

11,042.6

Equity in income (loss) of unconsolidated affiliates

301.2

449.2

365.4

Intangible assets, net

1,936.6

2,001.9

Goodwill

1,841.0

Natural Gas Pipelines & Services [Member]

Information by business segment [Abstract]

Total revenues

2,553.1

3,169.4

3,454.4

Equity in income (loss) of unconsolidated affiliates

5.8

6.3

6.8

Intangible assets, net

905.0

941.2

Goodwill

0.0

296.3

Petrochemical & Refined Products Services [Member]

Information by business segment [Abstract]

Total revenues

6,780.4

5,861.8

6,388.3

Equity in income (loss) of unconsolidated affiliates

^[1]

(2.2)

(7.0)

(9.2)

Intangible assets, net

133.4

145.7

Goodwill

956.2

Reportable Business Segments [Member] | NGL Pipelines and Services [Member]

Information by business segment [Abstract]

Gross operating margin

4,182.4

4,069.8

3,830.7

Revenues from third parties

11,170.6

13,460.8

15,630.5

Revenues from related parties

6.6

9.9

18.4

Intersegment and intrasegment revenues

29,010.3

20,840.4

26,453.6

Total revenues

40,187.5

34,311.1

42,102.5

Equity in income (loss) of unconsolidated affiliates

121.3

114.5

117.0

Property, plant and equipment, net

17,128.3

16,652.1

14,845.4

Investments in unconsolidated affiliates

671.6

703.8

662.0

Intangible assets, net

334.1

360.2

380.1

Goodwill

2,651.7

Segment assets

20,785.7

20,367.8

18,539.2

Reportable Business Segments [Member] | Crude Oil Pipelines & Services [Member]

Information by business segment [Abstract]

Gross operating margin

1,997.3

2,087.8

1,511.3

Revenues from third parties

6,668.8

10,244.6

10,968.2

Revenues from related parties

20.2

42.7

74.4

Intersegment and intrasegment revenues

24,531.3

34,613.0

35,490.4

Total revenues

31,220.3

44,900.3

46,533.0

Equity in income (loss) of unconsolidated affiliates

301.2

449.2

365.4

Property, plant and equipment, net

6,982.6

6,324.4

5,847.7

Investments in unconsolidated affiliates

1,723.7

1,866.5

1,867.5

Intangible assets, net

1,936.6

2,001.9

2,094.6

Goodwill

1,841.0

Segment assets

12,483.9

12,033.8

11,650.8

Reportable Business Segments [Member] | Natural Gas Pipelines & Services [Member]

Information by business segment [Abstract]

Gross operating margin

926.6

1,062.6

891.2

Revenues from third parties

2,543.2

3,154.7

3,439.5

Revenues from related parties

9.9

14.7

14.9

Intersegment and intrasegment revenues

460.1

624.7

721.9

Total revenues

3,013.2

3,794.1

4,176.3

Equity in income (loss) of unconsolidated affiliates

5.8

6.3

6.8

Property, plant and equipment, net

8,465.8

8,432.5

8,303.8

Investments in unconsolidated affiliates

31.4

27.3

22.8

Intangible assets, net

905.0

941.2

979.3

Goodwill

0.0

296.3

Segment assets

9,402.2

9,697.3

9,602.2

Reportable Business Segments [Member] | Petrochemical & Refined Products Services [Member]

Information by business segment [Abstract]

Gross operating margin

1,081.8

1,069.6

1,057.8

Revenues from third parties

6,780.4

5,861.8

6,388.3

Revenues from related parties

0.0

Intersegment and intrasegment revenues

5,379.4

2,481.3

2,917.5

Total revenues

12,159.8

8,343.1

9,305.8

Equity in income (loss) of unconsolidated affiliates

(2.2)

(7.0)

(9.2)

Property, plant and equipment, net

7,528.4

7,553.2

6,213.9

Investments in unconsolidated affiliates

2.5

2.6

62.8

Intangible assets, net

133.4

145.7

154.4

Goodwill

956.2

Segment assets

8,620.5

8,657.7

7,387.3

Eliminations [Member]

Information by business segment [Abstract]

Revenues from third parties

0.0

Revenues from related parties

0.0

Intersegment and intrasegment revenues

(59,381.1)

(58,559.4)

(65,583.4)

Total revenues

(59,381.1)

(58,559.4)

(65,583.4)

Equity in income (loss) of unconsolidated affiliates

0.0

Adjustments [Member]

Information by business segment [Abstract]

Property, plant and equipment, net

1,807.7

2,641.2

3,526.8

Investments in unconsolidated affiliates

0.0

Intangible assets, net

0.0

Goodwill

0.0

Segment assets

$ 1,807.7

$ 2,641.2

$ 3,526.8

[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.

Business Segments, Consolidated Revenues and Expenses (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

Consolidated Revenues [Abstract]

Total consolidated revenues

$ 27,199.7

$ 32,789.2

$ 36,534.2

Operating costs and expenses:

Cost of sales

^[1]

16,723.2

22,065.8

26,789.8

Other operating costs and expenses

^[2]

2,800.2

3,020.7

2,898.7

Depreciation, amortization and accretion

1,961.5

1,848.3

1,687.0

Impairment of goodwill

296.3

0.0

Impairment of assets other than goodwill

594.3

132.7

50.5

Net gains attributable to asset sales

(4.4)

(5.7)

(28.7)

General and administrative costs

219.6

211.7

208.3

Total costs and expenses

22,590.7

27,273.5

31,605.6

Vitol Holding B.V. [Member]

Consolidated Revenues [Abstract]

Total consolidated revenues

$ 3,314.8

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

Consolidated Revenues [Abstract]

Percent of revenues

10.10%

NGL Pipelines and Services [Member]

Consolidated Revenues [Abstract]

Total consolidated revenues

11,177.2

$ 13,470.7

15,648.9

Operating costs and expenses:

Impairment of goodwill

0.0

NGL Pipelines and Services [Member] | Vitol Holding B.V. [Member]

Consolidated Revenues [Abstract]

Total consolidated revenues

1,410.8

Crude Oil Pipelines & Services [Member]

Consolidated Revenues [Abstract]

Total consolidated revenues

6,689.0

10,287.3

11,042.6

Operating costs and expenses:

Impairment of goodwill

0.0

Crude Oil Pipelines & Services [Member] | Vitol Holding B.V. [Member]

Consolidated Revenues [Abstract]

Total consolidated revenues

1,670.7

Natural Gas Pipelines & Services [Member]

Consolidated Revenues [Abstract]

Total consolidated revenues

2,553.1

3,169.4

3,454.4

Operating costs and expenses:

Impairment of goodwill

296.3

Natural Gas Pipelines & Services [Member] | Vitol Holding B.V. [Member]

Consolidated Revenues [Abstract]

Total consolidated revenues

31.2

Petrochemical and Refined Products Services [Member]

Consolidated Revenues [Abstract]

Total consolidated revenues

6,780.4

5,861.8

$ 6,388.3

Operating costs and expenses:

Impairment of goodwill

$ 0.0

Petrochemical and Refined Products Services [Member] | Vitol Holding B.V. [Member]

Consolidated Revenues [Abstract]

Total consolidated revenues

$ 202.1

[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.
[2]	Represents the cost of operating our plants, pipelines and other fixed assets excluding: depreciation, amortization and accretion charges; asset impairment and related charges; and net losses (or gains) attributable to asset sales.

Earnings Per Unit (Details) - USD ($)
$ / shares in Units, shares in Millions, $ in Millions

12 Months Ended

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

BASIC EARNINGS PER COMMON UNIT

Net income attributable to common unitholders

$ 3,774.7

$ 4,591.3

$ 4,172.4

Earnings allocated to phantom unit awards

^[1]

(32.0)

(27.7)

(21.5)

Net income allocated to common unitholders

$ 3,742.7

$ 4,563.6

$ 4,150.9

Basic weighted-average number of common units outstanding (in units)

2,185.8

2,188.6

2,176.5

Basic earnings per common unit (in dollars per unit)

$ 1.71

$ 2.09

$ 1.91

DILUTED EARNINGS PER COMMON UNIT

Net income attributable to common unitholders

$ 3,774.7

$ 4,591.3

$ 4,172.4

Net income attributable to preferred units

0.9

0.0

Net income attributable to limited partners

$ 3,775.6

$ 4,591.3

$ 4,172.4

Diluted weighted-average number of units outstanding:

Distribution-bearing common units (in units)

2,185.8

2,188.6

2,176.5

Phantom units (in units)

^[2]

15.7

13.1

10.5

Preferred units (in units)

^[2]

0.7

0.0

Total (in units)

2,202.2

2,201.7

2,187.0

Diluted earnings per common unit (in dollars per unit)

$ 1.71

$ 2.09

$ 1.91

[1]	Phantom units are considered participating securities for purposes of computing basic earnings per unit. See Note 13 for information regarding our phantom units.
[2]	We use the “if-converted method” to determine the potential dilutive effect of the vesting of phantom units and the conversion of preferred units outstanding. See Note 8 for information regarding the preferred units issued during 2020.

Business Combinations (Details) - USD ($) $ in Millions	12 Months Ended
Business Combinations (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Mar. 29, 2018
Business Combination
Investments in unconsolidated affiliates	$ 2,429.2	$ 2,600.2	$ 2,615.1
Gain on step acquisition of Delaware Processing	0.0	0.0	39.4
Cash used for business combinations, net of cash received	$ 0.0	$ 0.0	150.6
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				$ 107.0
Gain on step acquisition of Delaware Processing			39.4
Cash used for business combinations, net of cash received			$ 151.0

Business Combinations, Purchase Price Allocation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2020	Dec. 31, 2019	Mar. 29, 2018
Liabilities assumed in business combination:
Goodwill	$ 5,745.2	$ 5,448.9	$ 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				200.0
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				0.0
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

Equity-Based Awards (Details) - USD ($) $ in Millions	12 Months Ended
Equity-Based Awards (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Equity-based compensation expense [Abstract]
Total compensation expense	$ 159.1	$ 143.9	$ 106.1
Phantom Unit Awards [Member]
Equity-based compensation expense [Abstract]
Total compensation expense	150.3	132.2	99.7
Profits Interest Awards [Member]
Equity-based compensation expense [Abstract]
Total compensation expense	8.7	11.6	6.1
Liability-classified awards [Member]
Equity-based compensation expense [Abstract]
Total compensation expense	$ 0.1	$ 0.1	$ 0.3
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)	55,000,000
Remaining number of common units available to be issued as awards (in units)	16,229,995

Equity-Based Awards, Phantom Unit Awards (Details) - USD ($)
$ / shares in Units, $ in Millions

12 Months Ended

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

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

Cash payments made in connection with DERs

$ 27.1

$ 22.1

$ 17.7

Phantom Unit Awards [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Vesting rate of phantom unit awards

25.00%

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

Beginning of period (in units)

12,974,684

10,333,277

9,289,501

Granted (in units)

7,405,245

^[1]

6,854,920

^[2]

5,006,181

^[3]

Vested (in units)

(4,532,269)

(3,895,049)

(3,479,958)

Forfeited (in units)

(178,218)

(318,464)

(482,447)

End of period (in units)

15,669,442

12,974,684

10,333,277

Common units issued in connection with the vesting of phantom unit awards, net (in units)

3,162,095

2,720,603

2,442,436

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

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

^[4]

$ 27.21

$ 26.97

$ 27.65

Granted weighted-average grant date fair value per unit (in dollars per unit)

^[4]

25.71

^[1]

27.75

^[2]

26.82

^[3]

Vested weighted-average grant date fair value per unit (in dollars per unit)

^[4]

26.35

27.53

28.57

Forfeited weighted-average grant date fair value per unit (in dollars per unit)

^[4]

26.73

27.21

26.88

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

^[4]

$ 26.76

$ 27.21

$ 26.97

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

Aggregate grant date fair value

$ 190.4

$ 190.2

$ 134.3

Estimated forfeiture rate

2.40%

3.00%

3.20%

Cash payments made in connection with DERs

$ 27.1

$ 22.1

$ 17.7

Total intrinsic value of phantom unit awards that vested during period

114.8

$ 111.1

$ 90.7

Unrecognized Compensation Expense [Abstract]

Unrecognized compensation cost

$ 156.7

Recognition period for total unrecognized compensation cost

2 years

Phantom Unit Awards [Member] | Minimum [Member]

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

Grant date market price of common units (in dollars per unit)

$ 16.95

$ 26.32

$ 25.40

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)

$ 25.76

$ 29.29

$ 29.22

Phantom Unit Awards [Member] | Enterprise [Member]

Unrecognized Compensation Expense [Abstract]

Unrecognized compensation cost

$ 129.6

[1]	The aggregate grant date fair value of phantom unit awards issued during 2020 was $190.4 million based on a grant date market price of EPD common units ranging from $16.95 to $25.76 per unit. An estimated annual forfeiture rate of 2.4% was applied to these awards.
[2]	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.
[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]	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 Interest Awards (Details)
$ / shares in Units, $ in Millions

12 Months Ended

Dec. 31, 2020

USD ($)

$ / shares

EPD PubCo II [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Exercise price (in dollars per unit) | $ / shares

$ 25.41

Incremental cost due to plan modification

$ 1.2

Vesting period

30 days

Partnership common units contributed by EPCO Holdings (in units) | shares

2,834,198

Class A capital base

$ 66.3

^[1]

Class A preference return | $ / shares

$ 0.3900

Estimated fair value of profits interest awards

$ 2.5

^[2]

Unrecognized Compensation Expense [Abstract]

Unrecognized compensation cost

$ 2.3

^[3]

Recognition period for total unrecognized compensation cost

2 years 1 month 6 days

Estimated Grant Date Fair Value Assumptions [Abstract]

Expected life of award from grant date

7 years

EPD PubCo II [Member] | Minimum [Member]

Estimated Grant Date Fair Value Assumptions [Abstract]

Risk-free interest rate

0.10%

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]

Exercise price (in dollars per unit) | $ / shares

$ 25.41

Incremental cost due to plan modification

$ 0.5

Vesting period

30 days

Partnership common units contributed by EPCO Holdings (in units) | shares

1,111,438

Class A capital base

$ 26.0

^[1]

Class A preference return | $ / shares

$ 0.3900

Estimated fair value of profits interest awards

$ 0.9

^[2]

Unrecognized Compensation Expense [Abstract]

Unrecognized compensation cost

$ 0.2

^[3]

Recognition period for total unrecognized compensation cost

2 years 1 month 6 days

Estimated Grant Date Fair Value Assumptions [Abstract]

Expected life of award from grant date

7 years

EPD PrivCo I [Member] | Minimum [Member]

Estimated Grant Date Fair Value Assumptions [Abstract]

Risk-free interest rate

0.10%

Expected distribution yield

6.10%

Expected unit price volatility

19.00%

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

Partnership common units contributed by EPCO Holdings (in units) | shares

6,400,000

Class A capital base

$ 172.9

^[1]

Class A preference return | $ / shares

$ 0.4325

Estimated fair value of profits interest awards

$ 26.7

^[2]

Unrecognized Compensation Expense [Abstract]

Unrecognized compensation cost

$ 13.6

^[3]

Recognition period for total unrecognized compensation cost

2 years 10 months 24 days

Estimated Grant Date Fair Value Assumptions [Abstract]

Expected life of award from grant date

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

Partnership common units contributed by EPCO Holdings (in units) | shares

1,600,000

Class A capital base

$ 43.2

^[1]

Class A preference return | $ / shares

$ 0.4325

Estimated fair value of profits interest awards

$ 6.6

^[2]

Unrecognized Compensation Expense [Abstract]

Unrecognized compensation cost

$ 0.3

^[3]

Recognition period for total unrecognized compensation cost

2 years 10 months 24 days

Estimated Grant Date Fair Value Assumptions [Abstract]

Expected life of award from grant date

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 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. The fair value is as of the grant date or as of the plan modification date, as applicable.
[3]	Represents our expected share of the unrecognized compensation cost at December 31, 2020. 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 2.1 years, 2.1 years, 2.9 years and 2.9 years, respectively.

Hedging Activities and Fair Value Measurements (Details)
bbl in Millions, $ in Millions, ft³ in Billions

12 Months Ended

Dec. 31, 2020

USD ($)

Contract

bbl

ft³

Dec. 31, 2019

USD ($)

Dec. 31, 2018

USD ($)

Derivative [Line Items]

Payments for the settlement of interest rate derivative instruments | $

$ (33.3)

$ 0.0

$ 22.1

Gain on the sale of swaption | $

23.1

29.4

Carrying amount of hedged asset | $

144.0

$ 31.7

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

Derivative [Line Items]

Notional Amount | $

$ 1,080.0

Weighted-Average Rate Locked

1.83%

Life of associated future debt

30 years

Notional amount of settled derivative instruments | $

$ 575.0

275.0

Payments for the settlement of interest rate derivative instruments | $

$ (33.3)

$ 22.1

Forward Starting Swaps - May 2019 [Member] | Derivatives in cash flow hedging relationships [Member]

Derivative [Line Items]

Number of Derivatives Outstanding | Contract

Notional Amount | $

$ 75.0

Weighted-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

Notional Amount | $

$ 1,000.0

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

Derivative [Line Items]

Number of Derivatives Outstanding | Contract

Notional Amount | $

$ 500.0

Weighted-Average Rate Locked

2.13%

Forward Starting Swaps - January 2020 [Member] | Derivatives in cash flow hedging relationships [Member]

Derivative [Line Items]

Number of Derivatives Outstanding | Contract

^[1]

Notional Amount | $

$ 150.0

Weighted-Average Rate Locked

1.72%

Forward Starting Swaps - February 2020 (A) [Member] | Derivatives in cash flow hedging relationships [Member]

Derivative [Line Items]

Number of Derivatives Outstanding | Contract

^[1]

Notional Amount | $

$ 100.0

Weighted-Average Rate Locked

1.46%

Forward Starting Swaps - February 2020 (B) [Member] | Derivatives in cash flow hedging relationships [Member]

Derivative [Line Items]

Number of Derivatives Outstanding | Contract

^[1]

Notional Amount | $

$ 150.0

Weighted-Average Rate Locked

1.48%

Forward Starting Swaps - March 2020 [Member] | Derivatives in cash flow hedging relationships [Member]

Derivative [Line Items]

Number of Derivatives Outstanding | Contract

^[1]

Notional Amount | $

$ 100.0

Weighted-Average Rate Locked

0.95%

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] | Current [Member]

Derivative [Line Items]

Volume | ft³

^[2],[3]

6.0

Designated as Hedging Instrument [Member] | Natural gas processing: Forecasted sales of NGLs [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member]

Derivative [Line Items]

Volume

^[2],[3]

0.6

Designated as Hedging Instrument [Member] | Natural gas marketing: Natural gas storage inventory management activities [Member] | Derivatives in fair value hedging relationships [Member] | Current [Member]

Derivative [Line Items]

Volume | ft³

^[2],[3]

4.0

Designated as Hedging Instrument [Member] | NGL marketing: Forecasted purchases of NGLs and related hydrocarbon products [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member]

Derivative [Line Items]

Volume

^[2],[3]

142.8

Derivative [Line Items]

Volume

^[2],[3]

1.6

Designated as Hedging Instrument [Member] | NGL marketing: Forecasted sales of NGLs and related hydrocarbon products [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member]

Derivative [Line Items]

Volume

^[2],[3]

172.1

Derivative [Line Items]

Volume

^[2],[3]

4.5

Designated as Hedging Instrument [Member] | NGL marketing: NGLs inventory management activities [Member] | Derivatives in fair value hedging relationships [Member] | Current [Member]

Derivative [Line Items]

Volume

^[2],[3]

1.9

Designated as Hedging Instrument [Member] | Refined products marketing: Forecasted purchases of refined products [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member]

Derivative [Line Items]

Volume

^[2],[3]

41.2

Designated as Hedging Instrument [Member] | Refined products marketing: Forecasted sales of refined products [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member]

Derivative [Line Items]

Volume

^[2],[3]

51.1

Designated as Hedging Instrument [Member] | Refined products marketing: Forecasted sales of refined products [Member] | Derivatives in cash flow hedging relationships [Member] | Long-term [Member]

Derivative [Line Items]

Volume

^[2],[3]

3.3

Designated as Hedging Instrument [Member] | Refined products marketing: Refined products inventory management activities [Member] | Derivatives in fair value hedging relationships [Member] | Current [Member]

Derivative [Line Items]

Volume

^[2],[3]

0.8

Designated as Hedging Instrument [Member] | Crude oil marketing: Forecasted purchases of crude oil [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member]

Derivative [Line Items]

Volume

^[2],[3]

32.9

Designated as Hedging Instrument [Member] | Crude oil marketing: Forecasted sales of crude oil [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member]

Derivative [Line Items]

Volume

^[2],[3]

44.5

Designated as Hedging Instrument [Member] | Petrochemical marketing: Forecasted purchases of petrochemical products [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member]

Derivative [Line Items]

Volume

^[2],[3]

0.4

Designated as Hedging Instrument [Member] | Petrochemical marketing: Forecasted sales of petrochemical products [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member]

Derivative [Line Items]

Volume

^[2],[3]

0.5

Not Designated as Hedging Instrument [Member] | Natural gas risk management activities [Member] | Derivatives in mark-to-market relationships [Member] | Current [Member]

Derivative [Line Items]

Volume | ft³

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

10.3

Not Designated as Hedging Instrument [Member] | Natural gas risk management activities [Member] | Derivatives in mark-to-market relationships [Member] | Long-term [Member]

Derivative [Line Items]

Volume | ft³

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

0.4

Not Designated as Hedging Instrument [Member] | NGL risk management activities [Member] | Derivatives in mark-to-market relationships [Member] | Current [Member]

Derivative [Line Items]

Volume

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

26.5

Not Designated as Hedging Instrument [Member] | NGL risk management activities [Member] | Derivatives in mark-to-market relationships [Member] | Long-term [Member]

Derivative [Line Items]

Volume

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

7.9

Not Designated as Hedging Instrument [Member] | Refined products risk management activities [Member] | Derivatives in mark-to-market relationships [Member] | Current [Member]

Derivative [Line Items]

Volume

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

6.9

Not Designated as Hedging Instrument [Member] | Crude oil risk management activities [Member] | Derivatives in mark-to-market relationships [Member] | Current [Member]

Derivative [Line Items]

Volume

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

32.5

Not Designated as Hedging Instrument [Member] | Crude oil risk management activities [Member] | Derivatives in mark-to-market relationships [Member] | Long-term [Member]

Derivative [Line Items]

Volume

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

2.6

[1]	These swaps were entered into during the first quarter of 2020.
[2]	The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is December 2022, December 2021 and October 2023, respectively.
[3]	Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes.
[4]	Reflects the use of derivative instruments to manage risks associated with transportation, processing and storage assets.

Hedging Activities and Fair Value Measurements, Derivative Fair Value Amounts (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Interest rate derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	$ 12.4
Liability Derivatives	120.1	$ 13.5
Commodity derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	229.2	127.8
Liability Derivatives	246.3	116.2
Derivatives designated as hedging instruments [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	223.3	116.5
Liability Derivatives	360.2	120.6
Derivatives designated as hedging instruments [Member] \| Interest rate derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	12.4	0.0
Liability Derivatives	120.1	13.5
Derivatives designated as hedging instruments [Member] \| Interest rate derivatives [Member] \| Current assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	0.0	0.0
Derivatives designated as hedging instruments [Member] \| Interest rate derivatives [Member] \| Other assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	12.4	0.0
Derivatives designated as hedging instruments [Member] \| Interest rate derivatives [Member] \| Current liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	109.1	6.7
Derivatives designated as hedging instruments [Member] \| Interest rate derivatives [Member] \| Other liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	11.0	6.8
Derivatives designated as hedging instruments [Member] \| Commodity derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	210.9	116.5
Liability Derivatives	240.1	107.1
Derivatives designated as hedging instruments [Member] \| Commodity derivatives [Member] \| Current assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	210.5	116.5
Derivatives designated as hedging instruments [Member] \| Commodity derivatives [Member] \| Other assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	0.4	0.0
Derivatives designated as hedging instruments [Member] \| Commodity derivatives [Member] \| Current liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	234.0	107.1
Derivatives designated as hedging instruments [Member] \| Commodity derivatives [Member] \| Other liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	6.1	0.0
Derivatives not designated as hedging instruments [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	18.3	11.3
Liability Derivatives	6.2	9.1
Derivatives not designated as hedging instruments [Member] \| Commodity derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	18.3	11.3
Liability Derivatives	6.2	9.1
Derivatives not designated as hedging instruments [Member] \| Commodity derivatives [Member] \| Current assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	18.1	10.7
Derivatives not designated as hedging instruments [Member] \| Commodity derivatives [Member] \| Other assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	0.2	0.6
Derivatives not designated as hedging instruments [Member] \| Commodity derivatives [Member] \| Current liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	6.1	8.6
Derivatives not designated as hedging instruments [Member] \| Commodity derivatives [Member] \| Other liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	$ 0.1	$ 0.5

Hedging Activities and Fair Value Measurements, Asset Balance Sheet Offsetting (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Interest rate derivatives [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	$ 12.4
Gross Amounts Offset in the Balance Sheet	0.0
Amounts of Assets Presented in the Balance Sheet	12.4
Financial Instruments	0.0
Cash Collateral Paid	0.0
Cash Collateral Received	0.0
Amounts That Would Have Been Presented On Net Basis	12.4
Commodity Derivatives [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	229.2	$ 127.8
Gross Amounts Offset in the Balance Sheet	0.0	0.0
Amounts of Assets Presented in the Balance Sheet	229.2	127.8
Financial Instruments	(228.5)	(115.3)
Cash Collateral Paid	0.0	(11.0)
Cash Collateral Received	0.0	0.0
Amounts That Would Have Been Presented On Net Basis	$ 0.7	$ 1.5

Hedging Activities and Fair Value Measurements, Liability Balance Sheet Offsetting (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Interest rate derivatives [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	$ 120.1	$ 13.5
Gross Amounts Offset in the Balance Sheet	0.0	0.0
Amounts of Liabilities Presented in the Balance Sheet	120.1	13.5
Financial Instruments	0.0	0.0
Cash Collateral Paid	0.0	0.0
Amounts That Would Have Been Presented On Net Basis	120.1	13.5
Commodity Derivatives [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	246.3	116.2
Gross Amounts Offset in the Balance Sheet	0.0	0.0
Amounts of Liabilities Presented in the Balance Sheet	246.3	116.2
Financial Instruments	(228.5)	(115.3)
Cash Collateral Paid	(17.3)	0.0
Amounts That Would Have Been Presented On Net Basis	$ 0.5	$ 0.9

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, 2020

Dec. 31, 2019

Dec. 31, 2018

Derivative Instruments, Gain (Loss) [Line Items]

Unrealized gains (losses)

$ 79.3

$ 67.7

$ (17.7)

Mark-to-market loss in interest expense

0.0

(94.9)

(0.1)

Total mark-to-market gains (losses)

79.3

(27.2)

(17.8)

NGL Pipelines & Services [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Unrealized gains (losses)

48.4

(5.5)

18.0

Crude Oil Pipelines & Services [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Unrealized gains (losses)

20.1

80.6

(44.1)

Natural Gas Pipelines & Services [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Unrealized gains (losses)

6.3

(0.2)

6.7

Petrochemical & Refined Products Services [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Unrealized gains (losses)

4.5

(7.2)

1.7

Derivatives in fair value hedging relationships [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Gain (Loss) Recognized in Income on Derivative

(88.0)

2.2

11.2

Gain (Loss) Recognized in Income on Hedged Item

168.1

6.9

(8.3)

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

0.0

1.3

Gain (Loss) Recognized in Income on Hedged Item

0.0

(1.4)

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

(88.0)

2.2

9.9

Gain (Loss) Recognized in Income on Hedged Item

168.1

6.9

(6.9)

Derivatives in cash flow hedging relationships [Member]

Derivative Instruments, Gain (Loss) [Line Items]

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

(3.1)

125.5

315.4

Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income

233.4

104.4

92.3

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

(127.5)

81.4

22.2

Accumulated other comprehensive loss related to interest rate derivative instruments expected to be reclassified to earnings in interest expense over the next twelve months

(41.2)

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

(39.3)

(37.3)

(38.1)

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

(35.6)

Accumulated other comprehensive income (loss) related to commodity derivative instruments expected to be reclassified to revenue over the next twelve months

(36.0)

Accumulated other comprehensive income (loss) related to commodity derivative instruments expected to be reclassified to operating costs and expenses over the next twelve months

0.4

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]

134.7

55.8

293.0

Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income

282.6

152.4

131.7

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

Derivative Instruments, Gain (Loss) [Line Items]

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

^[1]

(10.3)

(11.7)

0.2

Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income

(9.9)

(10.7)

(1.3)

Derivatives not designated as hedging instruments [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Gain (Loss) Recognized in Income on Derivative

165.8

(5.1)

(454.7)

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

Derivative Instruments, Gain (Loss) [Line Items]

Gain (Loss) Recognized in Income on Derivative

0.0

(94.9)

0.0

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

Derivative Instruments, Gain (Loss) [Line Items]

Realized gains (losses)

92.1

Unrealized gains (losses)

73.7

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

166.0

102.2

(462.9)

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

Derivative Instruments, Gain (Loss) [Line Items]

Gain (Loss) Recognized in Income on Derivative

$ (0.2)

$ (12.4)

$ 8.2

[1]	The fair value of these derivative instruments will be reclassified to their respective locations on the Statement of Consolidated Operations when the forecasted transactions affect earnings.

Hedging Activities and Fair Value Measurements, Recurring Fair Value Measurements (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

Mar. 05, 2020

Financial liabilities [Abstract]

Liquidity Option

$ 0.0

$ 509.6

$ 511.9

Total gains (losses) included in:

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

79.3

(27.2)

$ (17.8)

Fair Value, Measurements, Recurring [Member]

Financial assets [Abstract]

Interest rate derivatives

12.4

Value before application of CME Rule 814

1,570.1

397.2

Impact of CME Rule 814

(1,340.9)

(269.4)

Total commodity derivatives

229.2

127.8

Total

241.6

127.8

Financial liabilities [Abstract]

Liquidity Option

509.6

Interest rate derivatives

120.1

13.5

Commodity derivatives:

Value before application of CME Rule 814

2,138.9

362.0

Impact of CME Rule 814

(1,892.6)

(245.8)

Total commodity derivatives

246.3

116.2

Total

366.4

639.3

Net value before application of CME Rule 814 to commodity hedging portfolio

(568.8)

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

Financial assets [Abstract]

Interest rate derivatives

0.0

Value before application of CME Rule 814

678.6

53.4

Impact of CME Rule 814

(678.6)

(47.0)

Total commodity derivatives

0.0

6.4

Total

0.0

6.4

Financial liabilities [Abstract]

Liquidity Option

0.0

Interest rate derivatives

0.0

Commodity derivatives:

Value before application of CME Rule 814

1,065.6

88.1

Impact of CME Rule 814

(1,065.6)

(81.9)

Total commodity derivatives

0.0

6.2

Total

0.0

6.2

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

Financial assets [Abstract]

Interest rate derivatives

12.4

Value before application of CME Rule 814

878.6

343.7

Impact of CME Rule 814

(650.4)

(222.4)

Total commodity derivatives

228.2

121.3

Total

240.6

121.3

Financial liabilities [Abstract]

Liquidity Option

0.0

Interest rate derivatives

120.1

13.5

Commodity derivatives:

Value before application of CME Rule 814

1,047.4

273.6

Impact of CME Rule 814

(807.3)

(163.9)

Total commodity derivatives

240.1

109.7

Total

360.2

123.2

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

Financial assets [Abstract]

Interest rate derivatives

0.0

Value before application of CME Rule 814

12.9

0.1

Impact of CME Rule 814

(11.9)

0.0

Total commodity derivatives

1.0

0.1

Total

1.0

0.1

Financial liabilities [Abstract]

Liquidity Option

509.6

Interest rate derivatives

0.0

Commodity derivatives:

Value before application of CME Rule 814

25.9

0.3

Impact of CME Rule 814

(19.7)

0.0

Total commodity derivatives

6.2

0.3

Total

6.2

509.9

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

Financial liability balance, net, beginning of period

(509.8)

(395.9)

Total gains (losses) included in:

Transfer out of Level 3 - Liquidity Option

^[1]

511.9

0.0

Other transfers out of Level 3

17.1

7.6

Financial liability balance, net, end of period

(5.2)

(509.8)

$ (395.9)

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

0.7

0.2

Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Other Comprehensive Income (Loss) [Member]

Total gains (losses) included in:

Other comprehensive income (loss)

(23.7)

(2.1)

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

Total gains (losses) included in:

Net income

^[2]

(1.6)

3.7

Settlements

^[2]

3.2

(3.5)

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

Total gains (losses) included in:

Net income

$ (2.3)

$ (119.6)

[1]	In March 2020, the Liquidity Option settled and was transferred out of Level 3. See Note 17 for information regarding the Liquidity Option.
[2]	There were $0.7 million and $0.2 million of unrealized gains included in these amounts for the years ended December 31, 2020 and 2019, respectively.

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

12 Months Ended

Dec. 31, 2020

USD ($)

South Texas natural gas gathering and processing assets [Member]

Assets, Fair Value Disclosure [Abstract]

Assets, fair value

$ 21.3

Asset Impairment Charges [Abstract]

Impairment of long-lived assets held and used

125.7

Marine transportation business [Member]

Asset Impairment Charges [Abstract]

Impairment of long-lived assets held and used

$ 256.7

Marine transportation business [Member] | Measurement input, discount rate [Member]

Asset Impairment Charges [Abstract]

Long-lived asset, measurement input

0.093

Marine transportation business [Member] | Measurement input, growth rate [Member]

Asset Impairment Charges [Abstract]

Long-lived asset, measurement input

0.021

Petrochemical and Refined Products Services [Member] | Marine transportation business [Member]

Assets, Fair Value Disclosure [Abstract]

Assets, fair value

$ 410.0

Fair Value, Measurements, Nonrecurring [Member] | South Texas natural gas gathering and processing assets [Member]

Assets, Fair Value Disclosure [Abstract]

Assets, fair value

21.3

^[1]

Fair Value, Measurements, Nonrecurring [Member] | Marine transportation business [Member]

Assets, Fair Value Disclosure [Abstract]

Assets, fair value

410.0

^[1]

Fair Value, Measurements, Nonrecurring [Member] | Level 1 [Member] | South Texas natural gas gathering and processing assets [Member]

Assets, Fair Value Disclosure [Abstract]

Assets, fair value

0.0

^[1]

Fair Value, Measurements, Nonrecurring [Member] | Level 1 [Member] | Marine transportation business [Member]

Assets, Fair Value Disclosure [Abstract]

Assets, fair value

0.0

^[1]

Fair Value, Measurements, Nonrecurring [Member] | Level 2 [Member] | South Texas natural gas gathering and processing assets [Member]

Assets, Fair Value Disclosure [Abstract]

Assets, fair value

0.0

^[1]

Fair Value, Measurements, Nonrecurring [Member] | Level 2 [Member] | Marine transportation business [Member]

Assets, Fair Value Disclosure [Abstract]

Assets, fair value

0.0

^[1]

Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | South Texas natural gas gathering and processing assets [Member]

Assets, Fair Value Disclosure [Abstract]

Assets, fair value

21.3

^[1]

Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Marine transportation business [Member]

Assets, Fair Value Disclosure [Abstract]

Assets, fair value

$ 410.0

^[1]

[1]	Our fair value estimates for these assets were based on an income approach (i.e., a discounted cash flow approach).

Hedging Activities and Fair Value Measurements, Other Fair Value Measurements (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Carrying Value [Member]
Financial Liabilities: [Abstract]
Fixed-rate debt obligations	$ 29,900	$ 27,150
Level 2 [Member] \| Fair Value [Member]
Financial Liabilities: [Abstract]
Fixed-rate debt obligations	$ 35,000	$ 30,370

Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Revenues - related parties:
Total revenue - related parties	$ 36.7	$ 67.3	$ 107.7
Costs and expenses - related parties:
Operating costs and expenses	1,210.6	1,412.0	1,406.1
General and administrative expenses	136.2	136.4	130.9
Total costs and expenses - related parties	1,346.8	1,548.4	1,537.0
Accounts receivable - related parties:
Total accounts receivable - related parties	5.6	2.5
Accounts payable - related parties:
Total accounts payable - related parties	149.5	162.3
EPCO and its privately held affiliates [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	1,143.7	1,145.3	1,089.6
Accounts receivable - related parties:
Total accounts receivable - related parties	1.9	0.0
Accounts payable - related parties:
Total accounts payable - related parties	139.6	143.7
Distributions:
Total cash distributions	1,210.0	1,190.0	1,160.0
EPCO and its privately held affiliates [Member] \| Distribution Reinvestment Plan [Member]
Relationship with Affiliates [Abstract]
Gross proceeds from the sale of common units		29.0	213.0
EPCO and its privately held affiliates [Member] \| Administrative Services Agreement [Member]
Costs and expenses - related parties:
Operating costs and expenses	999.0	1,000.2	948.8
General and administrative expenses	128.9	127.6	124.2
Total costs and expenses - related parties	1,127.9	1,127.8	1,073.0
EPCO and its privately held affiliates [Member] \| Related Party Operating Leases [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	$ 13.0	14.9	13.9
EPCO and its privately held affiliates [Member] \| Common Units [Member]
Relationship with Affiliates [Abstract]
Number of Units (in units)	701,993,298
Percentage of total units outstanding	32.20%
Enterprise common units pledged as security (in units)	92,976,464
EPCO and its privately held affiliates [Member] \| Preferred Units [Member]
Relationship with Affiliates [Abstract]
Number of Units (in units)	15,138
Percentage of total units outstanding	30.20%
Unconsolidated affiliates [Member]
Revenues - related parties:
Total revenue - related parties	$ 36.7	67.3	107.7
Costs and expenses - related parties:
Total costs and expenses - related parties	203.1	403.1	447.4
Accounts receivable - related parties:
Total accounts receivable - related parties	3.7	2.5
Accounts payable - related parties:
Total accounts payable - related parties	9.9	18.6
Unconsolidated affiliates [Member] \| Seaway Crude Holdings LLC [Member]
Revenues - related parties:
Total revenue - related parties	20.2	42.7	74.4
Costs and expenses - related parties:
Total costs and expenses - related parties	71.5	194.5	163.2
Unconsolidated affiliates [Member] \| Venice Energy Service Company, L.L.C. [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	51.3	89.2	157.9
Unconsolidated affiliates [Member] \| K/D/S Promix, L.L.C. [Member]
Revenues - related parties:
Total revenue - related parties	6.0	9.1	9.5
Costs and expenses - related parties:
Total costs and expenses - related parties	23.5	34.8	31.9
Unconsolidated affiliates [Member] \| Texas Express Pipeline LLC [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	29.1	33.5	57.6
Unconsolidated affiliates [Member] \| Eagle Ford Pipeline LLC [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	20.9	36.0	18.5
Unconsolidated affiliates [Member] \| Management/Operator Fees [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	$ (10.1)	$ (9.9)	$ (11.6)

Income Taxes (Details) - USD ($)
$ / shares in Units, $ in Millions

10 Months Ended

12 Months Ended

Mar. 05, 2020

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

Components of Benefit From (Provision For) Income Taxes:

Maximum percent of qualifying income for publicly traded partnerships to be treated as corporations

90.00%

Texas Margin Tax

^[1]

$ (32.1)

$ (44.2)

$ (54.8)

Other

1.1

(1.4)

(5.5)

Benefit from (provision for) income taxes

124.3

(45.6)

(60.3)

Liquidity Option liability

$ 511.9

$ 0.0

509.6

Series A cumulative convertible preferred units (in dollars per unit)

$ 1,000

OTA Holdings, Inc. [Member]

Components of Benefit From (Provision For) Income Taxes:

Benefit from (provision for) income taxes

$ 72.2

$ 83.1

$ 155.3

$ 0.0

[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.

- Definition

Amount of current income tax expense (benefit) and deferred income tax expense (benefit) pertaining to continuing operations.

+ References + Details

Income Taxes, Benefit From (Provision For) Income Taxes (Details) - USD ($) $ in Millions		10 Months Ended	12 Months Ended
	Mar. 05, 2020	Dec. 31, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Current portion of income tax benefit (provision):
Federal			$ 2.9	$ 1.3	$ (5.3)
State			(25.6)	(25.7)	(33.1)
Foreign			(0.6)	(1.2)	(0.5)
Total current portion			(23.3)	(25.6)	(38.9)
Deferred portion of income tax benefit (provision):
Federal			142.0	(1.6)	0.3
State			5.6	(18.5)	(21.7)
Foreign			0.0	0.1	0.0
Total deferred portion			147.6	(20.0)	(21.4)
Total benefit from (provision for) income taxes			124.3	(45.6)	(60.3)
OTA Holdings, Inc. [Member]
Deferred portion of income tax benefit (provision):
Federal	$ 67.8
State	4.4
Total benefit from (provision for) income taxes	$ 72.2	$ 83.1	$ 155.3	$ 0.0	$ 0.0

Income Taxes, Reconciliation of the Benefit From (Provision For) Income Taxes (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

Reconciliation of the benefit from (provision for) income taxes [Abstract]

Pre-Tax Net Book Income ("NBI")

$ 3,761.4

$ 4,732.7

$ 4,298.8

Texas Margin Tax

^[1]

(32.1)

(44.2)

(54.8)

State income tax benefit (provision), net of federal benefit

^[2]

9.2

(0.5)

(0.2)

Federal income tax benefit (provision) computed by applying the federal statutory rate to NBI of corporate entities

80.1

(0.9)

(2.1)

Federal benefit attributable to settlement of Liquidity Option

^[2]

67.8

0.0

Other differences

(0.7)

0.0

(3.2)

Total benefit from (provision for) income taxes

$ 124.3

$ (45.6)

$ (60.3)

Effective income tax rate

3.30%

(1.00%)

(1.40%)

[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]	The total benefit recognized in income tax expense on March 5, 2020 from settlement of the Liquidity Option was $72.2 million, which is comprised of $4.4 million of state income tax benefit and $67.8 million of federal income tax benefit.

- Definition

Amount of income (loss) from continuing operations, including income (loss) from equity method investments, before deduction of income tax expense (benefit), and income (loss) attributable to noncontrolling interest.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-Subparagraph (c)
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8933-108599

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 30
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8906-108599

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-Subparagraph (f)
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8933-108599

Reference 4: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 940
-SubTopic 20
-Section 25
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=68072869&loc=d3e41242-110953

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 22
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8736-108599

Reference 6: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section S99
-Paragraph 2
-Subparagraph (SX 210.5-03(10))
-URI http://asc.fasb.org/extlink&oid=120395209&loc=SL114868664-224227

Reference 7: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 944
-SubTopic 220
-Section S99
-Paragraph 1
-Subparagraph (SX 210.7-04(8))
-URI http://asc.fasb.org/extlink&oid=120400993&loc=SL114874131-224263

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 235
-Section S99
-Paragraph 1
-Subparagraph (SX 210.9-05(b)(2))
-URI http://asc.fasb.org/extlink&oid=120399901&loc=d3e537907-122884

Reference 9: http://www.xbrl.org/2003/role/exampleRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 31
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8924-108599

Reference 10: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 220
-Section S99
-Paragraph 1
-Subparagraph (SX 210.9-04(15))
-URI http://asc.fasb.org/extlink&oid=120399700&loc=SL114874048-224260

+ Details

- Definition

Amount of current income tax expense (benefit) and deferred income tax expense (benefit) pertaining to continuing operations.

+ References + Details

Income Taxes, Deferred Tax Liabilities and Assets (Details) - USD ($)
$ in Millions

Dec. 31, 2020

Mar. 05, 2020

Dec. 31, 2019

Deferred tax liabilities:

Attributable to investment in OTA

$ 356.6

$ 439.7

$ 0.0

Attributable to property, plant and equipment

106.4

100.2

Attributable to investments in other entities

4.1

3.3

Total deferred tax liabilities

467.1

103.5

Less: deferred tax assets:

Net operating loss carryovers

^[1]

0.1

Temporary differences related to Texas Margin Tax

2.3

3.0

Total deferred tax assets

2.4

3.1

Total net deferred tax liabilities

$ 464.7

$ 100.4

[1]	These losses expire in various years between 2021 and 2037 and are subject to limitations on their utilization.

Commitments and Contingent Liabilities (Details) bbl in Millions, $ in Millions, BTU in Trillions	Dec. 31, 2020 USD ($) BTU bbl	Mar. 05, 2020 USD ($)	Dec. 31, 2019 USD ($)
Redelivery commitments:
Redelivery commitments of natural gas \| BTU	9.9
Redelivery commitments of crude oil \| bbl	19.4
Redelivery commitments of NGL and petrochemical products \| bbl	31.1
Operating lease obligations:
Renewal option years for certain leases	20 years
Liabilities, Other than Long-term Debt, Noncurrent [Abstract]
Noncurrent portion of AROs	$ 137.6		$ 126.9
Deferred revenues - non-current portion	198.2		197.0
Liquidity Option liability	0.0	$ 511.9	509.6
Lease liability - non-current portion	320.8		171.6
Derivative liabilities	17.2		7.3
Other	12.8		20.0
Total	686.6		1,032.4
Junior Subordinated Note [Member]
Debt Instrument [Line Items]
Debt obligations	$ 2,650.0
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	$ 6.1		$ 0.2

Commitments and Contingent Liabilities, Contractual Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Scheduled maturities of debt obligations [Abstract]
2021	$ 1,325.0
2022	1,400.0
2023	1,250.0
2024	850.0
2025	1,150.0
Thereafter	24,171.4
Total	30,146.4	$ 27,878.4
Estimated cash interest payments [Abstract]
2021	1,294.0
2022	1,241.2
2023	1,201.0
2024	1,162.8
2025	1,121.4
Thereafter	22,814.2
Total	28,834.6
Operating lease obligations [Abstract]
2021	33.7
2022	36.1
2023	33.2
2024	29.9
2025	28.8
Thereafter	298.8
Total	460.5
Natural Gas [Member]
Estimated payment obligations:
2021	84.6
2022	70.4
2023	0.0
2024	0.0
2025	0.0
Thereafter	0.0
Total	155.0
NGLs [Member]
Estimated payment obligations:
2021	685.2
2022	696.8
2023	494.4
2024	436.4
2025	336.8
Thereafter	1,258.8
Total	3,908.4
Crude Oil [Member]
Estimated payment obligations:
2021	1,390.1
2022	1,390.1
2023	1,390.1
2024	1,354.9
2025	1,297.2
Thereafter	3,543.3
Total	10,365.7
Petrochemicals And Refined Products [Member]
Estimated payment obligations:
2021	100.9
2022	100.9
2023	76.0
2024	68.3
2025	0.0
Thereafter	0.0
Total	346.1
Estimated Payment Obligations Other [Member]
Estimated payment obligations:
2021	5.8
2022	5.9
2023	6.0
2024	5.1
2025	2.7
Thereafter	0.0
Total	25.5
Service Payment Commitments [Member]
Estimated payment obligations:
2021	62.0
2022	59.7
2023	42.3
2024	16.1
2025	12.9
Thereafter	85.8
Total	278.8
EFS Midstream Contract with Producers [Member]
Contractual obligation [Line Items]
Contractual obligation	270.0
Capital expenditures to date	$ 151.0
Contract term	10 years

Commitments and Contingent Liabilities, Operating Leases (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2020

Dec. 31, 2019

Operating Leases [Abstract]

ROU asset carrying value

^[1]

$ 332.0

Lease liability carrying value

^[2]

348.6

Lease liability, current

$ 27.8

Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]

us-gaap:OtherLiabilitiesCurrent

Lease liability, noncurrent

$ 320.8

$ 171.6

Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]

us-gaap:OtherLiabilitiesNoncurrent

Increase in ROU asset during the period

$ 121.8

Increase in lease liability during the period

136.6

Storage and Pipeline Facilities [Member]

Operating Leases [Abstract]

ROU asset carrying value

^[1]

128.0

Lease liability carrying value

^[2]

$ 128.7

Weighted-average remaining term

15 years

Weighted-average discount rate

^[3]

4.30%

Transportation Equipment [Member]

Operating Leases [Abstract]

ROU asset carrying value

^[1]

$ 33.5

Lease liability carrying value

^[2]

$ 35.6

Weighted-average remaining term

3 years

Weighted-average discount rate

^[3]

3.50%

Office and Warehouse Space [Member]

Operating Leases [Abstract]

ROU asset carrying value

^[1]

$ 170.5

Lease liability carrying value

^[2]

$ 184.3

Weighted-average remaining term

16 years

Weighted-average discount rate

^[3]

3.20%

[1]	ROU asset amounts are a component of “Other assets” on our Consolidated Balance Sheet.
[2]	At December 31, 2020, lease liabilities of $27.8 million and $320.8 million were included within “Other current liabilities” and “Other liabilities,” respectively.
[3]	The discount rate for each category of assets represents the weighted average 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 Contingent Liabilities, Consolidated Lease Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Consolidated Lease Expense [Abstract]
Non-cash lease expense (amortization of ROU assets)	$ 39.0	$ 42.8	$ 0.0
Related accretion expense on lease liability balances	13.0	9.0
Total fixed lease expense	52.0	51.8
Variable lease expense	0.2	6.2
Subtotal operating lease expense	52.2	58.0
Short-term operating leases	49.8	48.6
Total operating lease expense	102.0	106.6	$ 86.4
Cash payments for operating lease liabilities	37.1	48.1
Operating lease income	$ 11.4	$ 14.4

Commitments and Contingent Liabilities, Liquidity Option Agreement (Details) $ in Millions	2 Months Ended	12 Months Ended
	Mar. 05, 2020 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)
Liquidity Option Agreement [Abstract]
Change in fair value of Liquidity Option Agreement	$ 2.3	$ 2.3	$ 119.6	$ 56.1
Level 3 [Member] \| Liquidity Option Agreement [Member]
Liquidity Option Agreement [Abstract]
Derivative Liability	$ 511.9		$ 509.6
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%		0.70%
Fair value inputs, OTA ownership interest in Enterprise common units	2.30%		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		30 years
Fair value inputs, Estimated growth rates in Enterprise earnings before interest, taxes, depreciation and amortization	2.20%		2.20%
Fair value inputs, OTA ownership interest in Enterprise common units	2.50%		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		0.228
Level 3 [Member] \| Liquidity Option Agreement [Member] \| Measurement input, discount rate [Member]
Liquidity Option Agreement [Abstract]
Derivative Liability, Measurement Input	0.057		0.057

Significant Risks and Uncertainties (Details) $ in Millions	12 Months Ended
Significant Risks and Uncertainties (Details) $ in Millions	Dec. 31, 2020 USD ($)
Insurance Matters [Abstract]
Insurance deductible per incident	$ 30
Minimum business interruption period	60 days
Named windstorm insurance coverage	$ 200