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Total operating costs and expenses

36,534.2

^[1]

29,241.5

^[2]

23,022.3

^[2]

Operating costs and expenses:

Third parties

29,991.2

24,444.7

18,539.5

Related parties

1,406.1

1,112.8

1,104.0

31,397.3

25,557.5

19,643.5

General and administrative costs:

Third parties

77.4

59.6

47.0

Related parties

130.9

121.5

113.1

Total general and administrative costs

208.3

181.1

160.1

31,605.6

25,738.6

19,803.6

480.0

426.0

362.0

5,408.6

3,928.9

3,580.7

Change in fair market value of Liquidity Option Agreement

(1,096.7)

(984.6)

(982.6)

(56.1)

(64.3)

(24.5)

Gain on step acquisition of unconsolidated affiliate

39.4

0.0

3.6

1.3

2.8

(1,109.8)

(1,047.6)

(1,004.3)

4,298.8

2,881.3

2,576.4

(60.3)

(25.7)

(23.4)

Net income attributable to noncontrolling interests

4,238.5

2,855.6

2,553.0

(66.1)

(56.3)

(39.9)

Basic earnings per unit (in dollars per unit)

$ 4,172.4

$ 2,799.3

$ 2,513.1

Earnings per unit:

$ 1.91

$ 1.30

$ 1.20

Diluted earnings per unit (in dollars per unit)

$ 1.91

$ 1.30

$ 1.20

[1]	Revenues are accounted for under ASC 606 upon implementation at January 1, 2018.
[2]	Revenues are accounted for under ASC 605 for historical periods prior to January 1, 2018.

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
Net income	$ 4,238.5	$ 2,855.6	$ 2,553.0
Commodity derivative instruments:
Changes in fair value of cash flow hedges	293.2	(38.5)	(193.8)
Reclassification of losses (gains) to net income	(130.4)	112.2	53.4
Interest rate derivative instruments:
Changes in fair value of cash flow hedges	22.2	(5.7)	42.3
Reclassification of losses to net income	38.1	40.4	37.4
Total cash flow hedges	223.1	108.4	(60.7)
Other	(0.5)	(0.1)	(0.1)
Total other comprehensive income (loss)	222.6	108.3	(60.8)
Comprehensive income	4,461.1	2,963.9	2,492.2
Comprehensive income attributable to noncontrolling interests	(66.1)	(56.3)	(39.9)
Comprehensive income attributable to limited partners	$ 4,395.0	$ 2,907.6	$ 2,452.3

STATEMENTS OF CONSOLIDATED CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating activities:
Net income	$ 4,238.5	$ 2,855.6	$ 2,553.0
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion	1,791.6	1,644.0	1,552.0
Asset impairment and related charges	50.5	49.8	53.5
Equity in income of unconsolidated affiliates	(480.0)	(426.0)	(362.0)
Distributions received on earnings from unconsolidated affiliates	479.4	433.7	380.5
Net gains attributable to asset sales	(28.7)	(10.7)	(2.5)
Deferred income tax expense	21.4	6.1	6.6
Change in fair market value of derivative instruments	17.8	22.8	45.0
Change in fair market value of Liquidity Option Agreement	56.1	64.3	24.5
Gain on step acquisition of unconsolidated affiliate	(39.4)	0.0	0.0
Net effect of changes in operating accounts	16.2	32.2	(180.9)
Other operating activities	2.9	(5.5)	(2.9)
Net cash flows provided by operating activities	6,126.3	4,666.3	4,066.8
Investing activities:
Capital expenditures	(4,223.2)	(3,101.8)	(2,984.1)
Cash used for business combinations, net of cash received	(150.6)	(198.7)	(1,000.0)
Investments in unconsolidated affiliates	(113.6)	(50.5)	(138.8)
Distributions received for return of capital from unconsolidated affiliates	50.0	49.3	71.0
Proceeds from asset sales	161.2	40.1	46.5
Other investing activities	(5.4)	(24.5)	(0.4)
Cash used in investing activities	(4,281.6)	(3,286.1)	(4,005.8)
Financing activities:
Borrowings under debt agreements	79,588.7	69,315.3	62,813.9
Repayments of debt	(77,957.1)	(68,459.6)	(61,672.6)
Debt issuance costs	(49.1)	(24.1)	(10.6)
Monetization of interest rate derivative instruments	22.1	30.6	6.1
Cash distributions paid to limited partners	(3,726.9)	(3,569.9)	(3,300.5)
Cash payments made in connection with distribution equivalent rights	(17.7)	(15.1)	(11.7)
Cash distributions paid to noncontrolling interests	(81.6)	(49.2)	(47.4)
Cash contributions from noncontrolling interests	238.1	0.4	20.4
Net cash proceeds from the issuance of common units	538.4	1,073.4	2,542.8
Common units acquired in connection with buyback program	(30.8)	0.0	0.0
Other financing activities	(29.0)	(29.3)	(18.7)
Cash provided by (used in) financing activities	(1,504.9)	(1,727.5)	321.7
Net change in cash and cash equivalents, including restricted cash	339.8	(347.3)	382.7
Cash and cash equivalents, including restricted cash, at beginning of period	70.3	417.6	34.9
Cash and cash equivalents, including restricted cash, at end of period	$ 410.1	$ 70.3	$ 417.6

STATEMENTS OF CONSOLIDATED EQUITY - USD ($) $ in Millions	Total	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interests [Member]	Limited Partners [Member]
Balance at Dec. 31, 2015	$ 20,501.1	$ (219.2)	$ 206.0	$ 20,514.3
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	2,553.0	0.0	39.9	2,513.1
Cash distributions paid to limited partners	(3,300.5)	0.0	0.0	(3,300.5)
Cash payments made in connection with distribution equivalent rights	(11.7)	0.0	0.0	(11.7)
Cash distributions paid to noncontrolling interests	(47.4)	0.0	(47.4)	0.0
Cash contributions from noncontrolling interests	20.4	0.0	20.4	0.0
Net cash proceeds from the issuance of common units	2,542.8	0.0	0.0	2,542.8
Amortization of fair value of equity-based awards	90.2	0.0	0.0	90.2
Cash flow hedges	(60.7)	(60.7)	0.0	0.0
Other	(21.2)	(0.1)	0.1	(21.2)
Balance at Dec. 31, 2016	22,266.0	(280.0)	219.0	22,327.0
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	2,855.6	0.0	56.3	2,799.3
Cash distributions paid to limited partners	(3,569.9)	0.0	0.0	(3,569.9)
Cash payments made in connection with distribution equivalent rights	(15.1)	0.0	0.0	(15.1)
Cash distributions paid to noncontrolling interests	(49.2)	0.0	(49.2)	0.0
Cash contributions from noncontrolling interests	0.4	0.0	0.4	0.0
Net cash proceeds from the issuance of common units	1,073.4	0.0	0.0	1,073.4
Common units issued in connection with employee compensation	33.7	0.0	0.0	33.7
Amortization of fair value of equity-based awards	99.0	0.0	0.0	99.0
Cash flow hedges	108.4	108.4	0.0	0.0
Other	(29.9)	(0.1)	(1.3)	(28.5)
Balance at Dec. 31, 2017	22,772.4	(171.7)	225.2	22,718.9
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	4,238.5	0.0	66.1	4,172.4
Cash distributions paid to limited partners	(3,726.9)	0.0	0.0	(3,726.9)
Cash payments made in connection with distribution equivalent rights	(17.7)	0.0	0.0	(17.7)
Cash distributions paid to noncontrolling interests	(81.6)	0.0	(81.6)	0.0
Cash contributions from noncontrolling interests	238.1	0.0	238.1	0.0
Net cash proceeds from the issuance of common units	538.4	0.0	0.0	538.4
Common units issued in connection with employee compensation	39.1	0.0	0.0	39.1
Common units issued in connection with land acquisition	30.0	0.0	0.0	30.0
Common units acquired in connection with buyback program	(30.8)	0.0	0.0	(30.8)
Amortization of fair value of equity-based awards	104.7	0.0	0.0	104.7
Cash flow hedges	223.1	223.1	0.0	0.0
Other	(35.1)	(0.5)	(9.1)	(25.5)
Balance at Dec. 31, 2018	$ 24,292.2	$ 50.9	$ 438.7	$ 23,802.6

Partnership Operations, Organization and Basis of Presentation	12 Months Ended
	Dec. 31, 2018
Partnership Operations, Organization and Basis of Presentation [Abstract]
Partnership Operations, Organization and Basis of Presentation	With the exception of per unit amounts, or as noted within the context of each disclosure, the dollar amounts presented in the tabular data within these disclosures are stated in millions of dollars. KEY REFERENCES USED IN THESE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Unless the context requires otherwise, references to “we,” “us,” “our,” “Enterprise” or “Enterprise Products Partners” are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries. References to “EPO” mean Enterprise Products Operating LLC, which is a wholly owned subsidiary of Enterprise, and its consolidated subsidiaries, through which Enterprise Products Partners L.P. conducts its business. Enterprise is managed by its general partner, Enterprise Products Holdings LLC (“Enterprise GP”), which is a wholly owned subsidiary of Dan Duncan LLC, a privately held Texas limited liability company. The membership interests of Dan Duncan LLC are owned by a voting trust, the current trustees (“DD LLC Trustees”) of which are: (i) Randa Duncan Williams, who is also a director and Chairman of the Board of Directors (the “Board”) of Enterprise GP; (ii) Richard H. Bachmann, who is also a director and Vice Chairman of the Board of Enterprise GP; and (iii) Dr. Ralph S. Cunningham, who is also an advisory director of Enterprise GP. Ms. Duncan Williams and Mr. Bachmann also currently serve as managers of Dan Duncan LLC along with W. Randall Fowler, who is also a director and the President and Chief Financial Officer of Enterprise GP. References to “EPCO” mean Enterprise Products Company, a privately held Texas corporation, and its privately held affiliates. A majority of the outstanding voting capital stock of EPCO is owned by a voting trust, the current trustees (“EPCO Trustees”) of which are: (i) Ms. Duncan Williams, who serves as Chairman of EPCO; (ii) Dr. Cunningham, who serves as Vice Chairman of EPCO; and (iii) Mr. Bachmann, who serves as the President and Chief Executive Officer of EPCO. Ms. Duncan Williams and Mr. Bachmann also currently serve as directors of EPCO along with Mr. Fowler, who is also the Executive Vice President and Chief Financial Officer of EPCO. EPCO, together with its privately held affiliates, owned approximately 31.9% of our limited partner interests at December 31, 2018. Note 1. Partnership Organization and Operations We are a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.” We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO and are a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, petrochemicals and refined products. Our integrated midstream energy asset network links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the United States (“U.S.”), Canada and the Gulf of Mexico with domestic consumers and international markets. Our midstream energy operations currently include: natural gas gathering, treating, processing, transportation and storage; NGL transportation, fractionation, storage, and export and import terminals (including those used to export liquefied petroleum gases, or “LPG,” and ethane); crude oil gathering, transportation, storage, and export and import terminals; petrochemical and refined products transportation, storage, export and import terminals, and related services; and a marine transportation business that operates primarily on the U.S. inland and Intracoastal Waterway systems. Our assets currently include approximately 49,200 miles of pipelines; 260 million barrels (“MMBbls”) of storage capacity for NGLs, crude oil, petrochemicals and refined products; and 14 billion cubic feet (“Bcf”) of natural gas storage capacity. All statistical data (e.g., pipeline mileage, processing capacity and similar operating metrics) in these notes to consolidated financial statements are unaudited. We conduct substantially all of our business through EPO and are owned 100% by our limited partners from an economic perspective. Enterprise GP manages our partnership and owns a non-economic general partner interest in us. We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates under the collective common control of the DD LLC Trustees and the EPCO Trustees. Like many publicly traded partnerships, we have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement (the “ASA”) or by other service providers. See Note 15 for information regarding related party matters. Our operations are reported under four business segments: (i) NGL Pipelines & Services, (ii) Crude Oil Pipelines & Services, (iii) Natural Gas Pipelines & Services and (iv) Petrochemical & Refined Products Services. See Note 10 for additional information regarding our business segments.

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2018

Summary of Significant Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Note 2. Summary of Significant Accounting Policies

Allowance for Doubtful Accounts

Our allowance for doubtful accounts is determined based on specific identification and estimates of future uncollectible accounts, including those related to natural gas imbalances. Our procedure for estimating the allowance for doubtful accounts is based on: (i) historical experience with customers, (ii) the perceived financial stability of customers based on our research and (iii) the levels of credit we grant to customers. In addition, we may increase the allowance for doubtful accounts in response to the specific identification of customers involved in bankruptcy proceedings and similar financial difficulties. On a routine basis, we review estimates associated with the allowance for doubtful accounts to ensure that we have recorded sufficient reserves to cover potential losses. The following table presents our allowance for doubtful accounts activity for the years indicated:

	For the Year Ended December 31,
	2018			2017			2016
Balance at beginning of period	$	12.1		$	11.3		$	12.1
Charged to costs and expenses		0.7			2.7			2.3
Deductions		(1.3	)		(1.9	)		(3.1	)
Balance at end of period	$	11.5		$	12.1		$	11.3

See “Credit Risk” in Note 18 for additional information.

Cash, Cash Equivalents and Restricted Cash

Cash and cash equivalents represent unrestricted cash on hand and highly liquid investments with original maturities of less than three months from the date of purchase. Restricted cash represents amounts held in segregated bank accounts by our clearing brokers as margin in support of our commodity derivative instruments portfolio and related physical purchases and sales of natural gas, NGLs, crude oil and refined products. Additional cash may be restricted to maintain our commodity derivative instruments portfolio as prices fluctuate or margin requirements change. 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,
	2018		2017
Cash and cash equivalents	$	344.8	$	5.1
Restricted cash		65.3		65.2
Total cash, cash equivalents and restricted cash shown in the Statements of Consolidated Cash Flows	$	410.1	$	70.3

The balance of restricted cash at December 31, 2018 consisted of initial margin requirements of $69.6 million partially offset by positive variation margin of $4.3 million. The initial margin requirements will be returned to us as the related derivative instruments are settled. See Note 14 for information regarding our derivative instruments and hedging activities.

Consolidation Policy

Our consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest, after the elimination of all intercompany accounts and transactions. We also consolidate other entities and ventures in which we possess a controlling financial interest as well as partnership interests where we are the sole general partner of the partnership. We evaluate our financial interests in business enterprises to determine if they represent variable interest entities where we are the primary beneficiary. If such criteria are met, we consolidate the financial statements of such businesses with those of our own. Third party or affiliate ownership interests in our controlled subsidiaries are presented as noncontrolling interests. See Note 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 similarly forecasted transactions are probable of occurring in the future.

We are required to recognize derivative instruments at fair value as either assets or liabilities on our Consolidated Balance Sheets unless such instruments meet certain normal purchase/normal sale criteria. While all derivatives are required to be reported at fair value on the balance sheet, changes in fair value of derivative instruments are reported in different ways, depending on the nature and effectiveness of the hedging activities to which they relate. After meeting specified conditions, a qualified derivative may be designated as a total or partial hedge of:

§	Changes in the fair value of a recognized asset or liability, or an unrecognized firm commitment – In a fair value hedge, gains and losses for both the derivative instrument and the hedged item are recognized in income during the period of change.

§	Variable cash flows of a forecasted transaction – In a cash flow hedge, the 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. Conversely, ineffectiveness represents the change in the fair value of the derivative instrument that does not exactly offset the change in the fair value of the hedged item. Any ineffectiveness associated with a fair value hedge is recognized in earnings immediately. Ineffectiveness can be caused by, among other things, changes in the timing of forecasted transactions or a mismatch of terms between the derivative instrument and the hedged item.

A contract designated as a cash flow hedge of an anticipated transaction that is not probable of occurring is immediately recognized in earnings.

Certain of our derivative instruments do not qualify for hedge accounting treatment; therefore, these instruments are accounted for using mark-to-market accounting.

For certain physical forward commodity derivative contracts, we apply the normal purchase/normal sale exception, whereby changes in the mark-to-market values of such contracts are not recognized in income. As a result, the revenues and expenses associated with such physical transactions are recognized during the period when volumes are physically delivered or received. Physical forward commodity contracts subject to this exception are evaluated for the probability of future delivery and are periodically back-tested once the forecasted period has passed to determine whether similar forward contracts are probable of physical delivery in the future. See Note 14 for additional information regarding our derivative instruments.

Environmental Costs

Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals. Expenditures to mitigate or prevent future environmental contamination are capitalized. Ongoing environmental compliance costs are charged to expense as incurred. In accruing for environmental remediation liabilities, costs of future expenditures for environmental remediation are not discounted to their present value, unless the amount and timing of the expenditures are fixed or reliably determinable. At December 31, 2018, 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,
	2018			2017			2016
Balance at beginning of period	$	11.6		$	11.9		$	13.0
Charged to costs and expenses		8.2			12.1			7.0
Acquisition-related additions and other		1.7			1.7			0.5
Deductions		(14.6	)		(14.1	)		(8.6	)
Balance at end of period	$	6.9		$	11.6		$	11.9

At December 31, 2018 and 2017, $3.2 million and $5.6 million, respectively, of our environmental reserves were classified as current liabilities.

Estimates

Preparing our consolidated financial statements in conformity with U.S. generally accepted accounting principles (“GAAP”) requires us to make estimates that affect amounts presented in the financial statements. Our most significant estimates relate to (i) the useful lives and depreciation/amortization methods used for fixed and identifiable intangible assets; (ii) measurement of fair value and projections used in impairment testing of fixed and intangible assets (including goodwill); (iii) contingencies; and (iv) revenue and expense accruals.

Actual results could differ materially from our estimates. On an ongoing basis, we review our estimates based on currently available information. Any changes in the facts and circumstances underlying our estimates may require us to update such estimates, which could have a material impact on our consolidated financial statements.

Fair Value Measurements

Our fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk, in the principal market of the asset or liability at a specified measurement date. Recognized valuation techniques employ inputs such as contractual prices, quoted market prices or rates, operating costs, discount factors and business growth rates. These inputs may be either readily observable, corroborated by market data or generally unobservable. In developing our estimates of fair value, we endeavor to utilize the best information available and apply market-based data to the highest extent possible. Accordingly, we utilize valuation techniques (such as the market approach) that maximize the use of observable inputs and minimize the use of unobservable inputs.

A three-tier hierarchy has been established that classifies fair value amounts recognized in the financial statements based on the observability of inputs used to estimate such fair values. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). At each balance sheet reporting date, we categorize our financial assets and liabilities using this hierarchy.

The characteristics of fair value amounts classified within each level of the hierarchy are described as follows:

Level 1 fair values are based on quoted prices, which are available in active markets for identical assets or liabilities as of the measurement date. Active markets are defined as those in which transactions for identical assets or liabilities occur with sufficient frequency so as to provide pricing information on an ongoing basis (e.g., the New York Mercantile Exchange (“NYMEX”)). Our Level 1 fair values consist of financial assets and liabilities such as exchange-traded commodity derivative instruments.

Level 2 fair values are based on pricing inputs other than quoted prices in active markets (as reflected in Level 1 fair values) and are either directly or indirectly observable as of the measurement date. Level 2 fair values include instruments that are valued using financial models or other appropriate valuation methodologies. Such financial models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, the time value of money, volatility factors, current market and contractual prices for the underlying instruments and other relevant economic measures. Substantially all of these assumptions (i) are observable in the marketplace throughout the full term of the instrument; (ii) can be derived from observable data; or (iii) are validated by inputs other than quoted prices (e.g., interest rate and yield curves at commonly quoted intervals). Our Level 2 fair values primarily consist of commodity derivative instruments such as forwards, swaps and other instruments transacted on an exchange or over-the-counter and interest rate derivative instruments. The fair values of these derivative instruments are based on observable price quotes for similar products and locations. The fair value of our interest rate derivatives are determined using financial models that incorporate the implied forward LIBOR yield curve for the same period as the future interest rate swap settlements.

Level 3 fair values are based on unobservable inputs. Unobservable inputs are used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. Unobservable inputs reflect management’s ideas about the assumptions that market participants would use in pricing an asset or liability (including assumptions about risk). Unobservable inputs are based on the best information available to us in the circumstances, which might include our internally developed data. Level 3 inputs are typically used in connection with internally developed valuation methodologies where we make our best estimate of an instrument’s fair value. With regards to commodity derivatives, our Level 3 fair values primarily consist of the following commodity derivative instruments which are used to hedge our various inventories and transportation capacities: (i) NGL-based contracts with terms greater than one year; (ii) crude, natural gas and refined products-based contracts with terms greater than 36 months; (iii) over-the-counter options; and (iv) exchange traded options with terms greater than one year. In addition, we often rely on price quotes from reputable brokers who publish price quotes on certain products and compare these prices to other reputable brokers for the same products in the same markets whenever possible. These prices, when combined with data from our commodity derivative instruments, are used in our models to determine the fair value of such instruments.

Transfers within the fair value hierarchy routinely occur for certain term contracts as prices and other inputs used for the valuation of future delivery periods become more observable with the passage of time. Other transfers are made periodically in response to changing market conditions that affect liquidity, price observability and other inputs used in determining valuations. We deem any such transfers to have occurred at the end of the quarter in which they transpired. There were no transfers between Level 1 and 2 during the years ended December 31, 2018 and 2017.

We have a risk management policy that covers our Level 3 commodity derivatives. Governance and oversight of risk management activities for these commodities are provided by our Chief Executive Officer with guidance and support from a risk management committee (“RMC”) that meets quarterly (or on a more frequent basis, if needed). Members of executive management attend the RMC meetings, which are chaired by the head of our commodities risk control group. This group is responsible for preparing and distributing daily reports and risk analysis to members of the RMC and other appropriate members of management. These reports include mark-to-market valuations with the one-day and month-to-date changes in fair values. This group also develops and validates the forward commodity price curves used to estimate the fair values of our Level 3 commodity derivatives. These forward curves incorporate published indexes, market quotes and other observable inputs to the extent available.

Impairment Testing for Goodwill

Our goodwill amounts are assessed for impairment on a routine annual basis or when impairment indicators are present. If such indicators occur (e.g., the loss of a significant customer or technological obsolescence of assets), the estimated fair value of the reporting unit to which the goodwill is assigned is determined and compared to its carrying value. If the fair value of the reporting unit is less than its carrying value including associated goodwill amounts, a non-cash impairment charge to earnings is recorded to reduce the carrying value of the goodwill to its implied fair value.

Our reporting unit estimated fair values are based on assumptions regarding the future economic prospects of the businesses that comprise each reporting unit. Such assumptions include: (i) discrete financial forecasts for the assets classified within the reporting unit, which, in turn, rely on management’s estimates of operating margins, throughput volumes and similar factors; (ii) long-term growth rates for cash flows beyond the discrete forecast period; and (iii) appropriate discount rates. We believe the assumptions we use in estimating reporting unit fair values are consistent with those that would be employed by market participants in their fair value estimation process. Based on our most recent goodwill impairment test at December 31, 2018, each reporting unit’s fair value was substantially in excess of its carrying value (i.e., by at least 10%).

See Note 6 for additional information regarding goodwill.

Impairment Testing for Long-Lived Assets

Long-lived assets (including intangible assets with finite useful lives and property, plant and equipment) are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Long-lived assets with carrying values that are not expected to be recovered through future cash flows are written-down to their estimated fair values. The carrying value of a long-lived asset is deemed not recoverable if it exceeds the sum of undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the asset’s carrying value exceeds the sum of its undiscounted cash flows, a non-cash asset impairment charge equal to the excess of the asset’s carrying value over its estimated fair value is recorded. Fair value is defined as the price that would be received to sell an asset or be paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. We measure fair value using market price indicators or, in the absence of such data, appropriate valuation techniques. See Note 14 for information regarding non-cash impairment charges related to long-lived assets.

Impairment Testing for Unconsolidated Affiliates

We evaluate our equity method investments for impairment to determine whether there are events or changes in circumstances that indicate there is a loss in value of the investment attributable to an other than temporary decline. Examples of such events or changes in circumstances include continuing operating losses of the entity and/or long-term negative changes in the entity’s industry. In the event we determine that the loss in value of an investment is an other than temporary decline, we record a non-cash impairment charge to equity earnings to adjust the carrying value of the investment to its estimated fair value. There were not any non-cash impairment charges related to our equity method investments during the years ended December 31, 2018, 2017 and 2016. See Note 5 for information regarding our equity method investments.

Inventories

Inventories primarily consist of NGLs, petrochemicals, refined products, crude oil and natural gas volumes that are valued at the lower of cost or net realizable value. We capitalize, as a cost of inventory, shipping and handling charges (e.g., pipeline transportation and storage fees) and other related costs associated with purchased volumes. As volumes are sold and delivered out of inventory, the cost of these volumes (including freight-in charges that have been capitalized as part of inventory cost) are charged to operating costs and expenses. Shipping and handling fees associated with products we sell and deliver to customers are charged to operating costs and expenses as incurred. See Note 3 for additional information regarding our inventories.

Property, Plant and Equipment

Property, plant and equipment is recorded at cost. Expenditures for additions, improvements and other enhancements to property, plant and equipment are capitalized, and minor replacements, maintenance, and repairs that do not extend asset life or add value are charged to expense as incurred. When property, plant and equipment assets are retired or otherwise disposed of, the related cost and accumulated depreciation is removed from the accounts and any resulting gain or loss is included in results of operations for the respective period.

We capitalize interest costs incurred on funds used to construct property, plant and equipment while the asset is in its construction phase. The capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset’s estimated useful life as a component of depreciation expense. When capitalized interest is recorded, it reduces interest expense from what it would be otherwise.

In general, depreciation is the systematic and rational allocation of an asset’s cost, less its residual value (if any), to the periods it benefits. The majority of our property, plant and equipment is depreciated using the straight-line method, which results in depreciation expense being incurred evenly over the life of an asset. Our estimate of depreciation expense incorporates management assumptions regarding the useful economic lives and residual values of our assets. With respect to midstream energy assets such as natural gas gathering systems that are reliant upon a specific natural resource basin for throughput volumes, the anticipated useful economic life of such assets may be limited by the estimated life of the associated natural resource basin from which the assets derive benefit. Our forecast of the remaining life for the applicable resource basins is based on several factors, including information published by the U.S. Energy Information Administration. Where appropriate, we use other depreciation methods (generally accelerated) for tax purposes.

Leasehold improvements are recorded as a component of property, plant and equipment. The cost of leasehold improvements is charged to earnings using the straight-line method over the shorter of (i) the remaining lease term or (ii) the estimated useful lives of the improvements. We consider renewal terms that are deemed reasonably assured when estimating remaining lease terms.

Our assumptions regarding the useful economic lives and residual values of our assets may change in response to new facts and circumstances, which would prospectively impact our depreciation expense amounts. Examples of such circumstances include, but are not limited to: (i) changes in laws and regulations that limit the estimated economic life of an asset; (ii) changes in technology that render an asset obsolete; (iii) changes in expected salvage values or (iv) significant changes in the forecast life of the applicable resource basins, if any.

Certain of our plant operations entail periodic planned outages for major maintenance activities. These planned shutdowns typically result in significant expenditures, which are principally comprised of amounts paid to third parties for materials, contract services and related items. We use the expense-as-incurred method for our planned major maintenance activities for plant operations; however, the cost of annual planned major maintenance projects for such plants are deferred and recognized on a straight-line basis over the remaining portion of the fiscal year in which the maintenance occurred. With regard to the planned major maintenance activities on our marine transportation assets and underground storage caverns, we use the deferral method to account for such costs. Under this method, major maintenance costs are capitalized and amortized over the period until the next major overhaul or cavern integrity project.

Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of tangible long-lived assets that result from their acquisition, construction, development and/or normal operation. When an ARO is incurred, we record a liability for the ARO and capitalize an equal amount as an increase in the carrying value of the related long-lived asset. ARO amounts are measured at their estimated fair value using expected present value techniques. Over time, the ARO liability is accreted to its present value (through accretion expense) and the capitalized amount is depreciated over the remaining useful life of the related long-lived asset. We will incur a gain or loss to the extent that our ARO liabilities are not settled at their recorded amounts.

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

Recent Accounting Developments

Adoption of New Revenue Recognition Policies on January 1, 2018

For periods through December 31, 2017, we accounted for our revenue streams using Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 605, Revenue Recognition. Under ASC 605, we recognized revenue when all of the following criteria were met: (i) persuasive evidence of an exchange arrangement existed between us and the counterparty (e.g., published tariffs), (ii) delivery of products or the rendering of services had occurred, (iii) the price of the products or the fee for services was fixed or determinable and (iv) collectibility of the amount owed by the counterparty was reasonably assured.

We adopted ASC 606, Revenue from Contracts with Customers, on January 1, 2018 using a modified retrospective approach that applied the new revenue recognition standard to existing contracts at the implementation date and any future revenue contracts. As such, our consolidated revenues and related financial information for periods prior to January 1, 2018 were not adjusted and continue to be reported in accordance with ASC 605. We did not record a cumulative effect adjustment upon initially applying ASC 606 since there was no impact on partners’ equity upon adoption; however, the extent of our revenue-related disclosures has increased under the new standard.

Due to the large number of individual contracts that were in effect at the implementation date of ASC 606, we evaluated our contracts using a portfolio approach based on the types of products sold or services rendered within our business segments. There are no material differences in the amount or timing of revenues recognized under ASC 606 when compared to ASC 605.

The core principle of ASC 606 is that a company should recognize revenue in a manner that fairly depicts the transfer of goods or services to customers in amounts that reflect the consideration the company expects to receive for those goods or services. We apply this core principle by following five key steps outlined in ASC 606: (i) identify the contract; (ii) identify the performance obligations in the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and (v) recognize revenue when (or as) the performance obligation is satisfied. Each of these steps involves management judgment and an analysis of the contract’s material terms and conditions.

Substantially all of our revenues are accounted for under ASC 606; however, to a limited extent, some revenues are accounted for under other guidance such as ASC 840, Leases, ASC 845, Nonmonetary Transactions, or ASC 815, Derivatives and Hedging Activities.

Under ASC 606, we recognize revenue when or as we satisfy our performance obligation to the customer. In situations where we have recognized revenue, but have a conditional right to consideration (based on something other than the passage of time) from the customer, we recognize unbilled revenue (a contract asset) on our consolidated balance sheet. Unbilled revenue is reclassified to accounts receivable when we have an unconditional right of payment from the customer. Payments received from customers in advance of the period in which we satisfy a performance obligation are recorded as deferred revenue (a contract liability) on our consolidated balance sheet.

Our revenue streams are derived from the sale of products and providing midstream services. Revenues from the sale of products are recognized at a point in time, which represents the transfer of control (and the satisfaction of our performance obligation under the contract) to the customer. From that point forward, the customer is able to direct the use of, and obtain substantially all the benefits from, its use of the products. With respect to midstream services (e.g., interruptible transportation), we satisfy our performance obligations over time and recognize revenues when the services are provided and the customer receives the benefits based on an output measure of volumes redelivered. We believe this measure is a faithful depiction of the transfer of control for midstream services since there is (i) an insignificant period of time between the receipt of customers’ volumes and their subsequent redelivery, and (ii) it is not possible to individually track and differentiate customers’ inventories as they traverse our facilities. For stand-ready performance obligations (e.g., a storage capacity reservation contract), we recognize revenues over time on a straight-line basis as time elapses over the term of the contract. We believe that these approaches accurately depict the transfer of benefits to the customer.

Customers are invoiced for products purchased or services rendered when we have an unconditional right to consideration under the associated contract. The consideration we are entitled to invoice may be either fixed, variable or a combination of both. Examples of fixed consideration would be fixed payments from customers under take-or-pay arrangements, storage capacity reservation agreements and firm transportation contracts. Variable consideration represents payments from customers that are based on factors that fluctuate (or vary) based on volumes, prices or both. Examples of variable consideration include interruptible transportation agreements, market-indexed product sales contracts and the value of NGLs we retain under natural gas processing agreements. The terms of our billings are typical of the industry for the products we sell.

Under certain midstream service agreements, customers are required to provide a minimum volume over an agreed-upon period with a provision that allows the customer to make-up any volume shortfalls over an agreed-upon period (referred to as “make-up rights”). Revenue pursuant to such agreements is initially deferred and subsequently recognized when either the make-up rights are exercised, the likelihood of the customer exercising the rights becomes remote, or we are otherwise released from the performance obligation.

Customers may contribute funds to us to help offset the construction costs related to pipeline construction activities and production well tie-ins. Under ASC 605, these amounts were accounted for as contributions in aid of construction costs (“CIACs”) and netted against property, plant and equipment. Under ASC 606, these receipts are recognized as additional service revenues over the term of the associated midstream services provided to the customer.

As a practical expedient, 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 new revenue disclosures.

Lease accounting standard

In February 2016, the FASB issued ASC 842, Leases, which requires substantially all leases to 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.

The new standard introduces two lessee accounting models, which result in a lease being classified as either a “finance” or “operating” lease on the basis of whether the lessee effectively obtains control of the underlying asset during the lease term. A lease would be classified as a finance lease if it meets one of five classification criteria, four of which are generally consistent with 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 lease liability (as a component of interest expense). Operating leases will result in the recognition of a single lease expense amount that is recorded on a straight-line basis (or another systematic basis, as appropriate).

ASC 842 will result in changes to the way our operating leases are recorded, presented and disclosed in our consolidated financial statements. Upon adoption of ASC 842 on January 1, 2019, we recognized a ROU asset and a corresponding lease liability based on the present value of then existing operating lease obligations. In addition, there are several key accounting policy elections that we made upon adoption of ASC 842 including:

We will 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 will not reassess whether any expired or existing contracts are or contain leases or the lease classification for any existing or expired leases.

§	The impact of adopting ASC 842 will be prospective beginning January 1, 2019. We will not recast prior periods presented in our consolidated financial statements to reflect the new lease accounting guidance.

Based on current information, we expect to recognize at adoption of ASC 842 an estimated $250 million in ROU assets and $250 million in lease liabilities on our consolidated balance sheet at January 1, 2019 based on discounted amounts. These amounts would represent less than 1% of our total consolidated assets and liabilities, respectively.

Fair value measurements

In August 2018, the FASB issued ASU 2018-13, Fair Value Measurements (Topic 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurement, which amends certain disclosure requirements related to fair value measurements. The amendments will require incremental disclosures regarding uncertainties surrounding fair value measurements, including discussions of any interrelationships between significant unobservable inputs used to estimate Level 3 fair value measurements, and changes in unrealized gains and losses. The amendments in this ASU are effective January 1, 2020, which is when we expect to apply the new requirements. We are currently reviewing the effect of this ASU on our consolidated financial statements.

Credit losses

In June 2016, the FASB issued ASU 2016-13, “Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” This ASU modifies the impairment model to utilize an expected loss methodology in place of the currently used incurred loss methodology. These changes are expected to result in the more timely recognition of losses. The amendments in this ASU are effective January 1, 2020, which is when we expect to apply the new requirements to how the allowance for doubtful accounts is determined. We are currently reviewing the effect of this ASU on our consolidated financial statements.

Inventories

12 Months Ended

Dec. 31, 2018

Inventories [Abstract]

Inventories

Note 3. Inventories

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

	December 31,
	2018		2017
NGLs	$	647.7	$	917.4
Petrochemicals and refined products		264.7		161.5
Crude oil		593.4		516.3
Natural gas		16.3		14.6
Total	$	1,522.1	$	1,609.8

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,
	2018		2017		2016
Cost of sales (1)	$	26,789.8	$	21,487.0	$	15,710.9
Lower of cost or net realizable value adjustments within cost of sales		11.5		9.1		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, 2018

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	2018		2017
Plants, pipelines and facilities (1)	3-45 (5)	$	42,371.0	$	37,132.2
Underground and other storage facilities (2)	5-40 (6)		3,624.2		3,460.9
Transportation equipment (3)	3-10		187.1		177.1
Marine vessels (4)	15-30		828.6		803.8
Land			359.5		273.1
Construction in progress			3,526.8		4,698.1
Total			50,897.2		46,545.2
Less accumulated depreciation			12,159.6		10,924.8
Property, plant and equipment, net		$	38,737.6	$	35,620.4

(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. We placed a number of growth projects into service since December 31, 2017 including a propane dehydrogenation facility at our Mont Belvieu complex, the first two processing trains at our Orla natural gas processing facility, and a ninth NGL fractionator in Chambers County, Texas at our Mont Belvieu NGL fractionation complex. (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.

In March 2018, we acquired the remaining 50% member interest of our Delaware Processing joint venture, which resulted in the consolidation of $200 million of property, plant and equipment. See Note 12 for information regarding this recent 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 Enterprise common units.

In October 2018, we sold our Red River System and associated crude oil linefill for $134.9 million and recorded a gain of $20.6 million. The Red River System gathers and transports crude oil from North Texas and southern Oklahoma for delivery to local refineries and pipeline interconnects for further transportation to the Cushing hub and Gulf Coast.

The following table summarizes our depreciation expense and capitalized interest amounts for the years indicated:

	For the Year Ended December 31,
	2018		2017		2016
Depreciation expense (1)	$	1,436.2	$	1,296.1	$	1,215.7
Capitalized interest (2)		147.9		192.1		168.2
(1)Depreciation expense is a component of “Costs and expenses” as presented on our Statements of Consolidated Operations. (2)Capitalized interest is a component of “Interest expense” as presented on our Statements of Consolidated Operations.

Asset Retirement Obligations

We record AROs in connection with legal requirements to perform specified retirement activities under contractual arrangements and/or governmental regulations. Our contractual AROs primarily result from right-of-way agreements associated with our pipeline operations and real estate leases associated with our plant sites. In addition, we record AROs in connection with governmental regulations associated with the abandonment or retirement of above-ground brine storage pits and certain marine vessels. We also record AROs in connection with regulatory requirements associated with the renovation or demolition of certain assets containing hazardous substances such as asbestos. We typically fund our AROs using cash flow from operations.

Property, plant and equipment at December 31, 2018 and 2017 includes $72.5 million and $39.9 million, respectively, of asset retirement costs capitalized as an increase in the associated long-lived asset.

The following table presents information regarding our AROs for the years indicated:

	For the Year Ended December 31,
	2018			2017			2016
ARO liability beginning balance	$	86.7		$	85.4		$	58.5
Liabilities incurred		24.4			4.7			4.2
Liabilities settled		(2.5	)		(2.2	)		(5.7	)
Revisions in estimated cash flows		11.5			(6.7	)		24.6
Accretion expense		6.2			5.5			3.8
ARO liability ending balance	$	126.3		$	86.7		$	85.4

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

2019				2020				2021				2022				2023
$	8.1			$	8.6			$	9.0			$	9.6			$	10.3

Investments in Unconsolidated Affiliates

12 Months Ended

Dec. 31, 2018

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,
	2018	2018		2017
NGL Pipelines & Services:
Venice Energy Service Company, L.L.C. (“VESCO”)	13.1%	$	24.1	$	25.7
K/D/S Promix, L.L.C. (“Promix”)	50%		28.9		30.9
Baton Rouge Fractionators LLC (“BRF”)	32.2%		16.3		17.0
Skelly-Belvieu Pipeline Company, L.L.C. (“Skelly-Belvieu”)	50%		35.6		37.0
Texas Express Pipeline LLC (“Texas Express”)	35%		337.6		314.4
Texas Express Gathering LLC (“TEG”)	45%		43.6		35.9
Front Range Pipeline LLC (“Front Range”)	33.3%		175.9		165.7
Delaware Basin Gas Processing LLC (“Delaware Processing”) (1)	100%		--		107.3
Crude Oil Pipelines & Services:
Seaway Crude Pipeline Company LLC (“Seaway”)	50%		1,369.7		1,378.9
Eagle Ford Pipeline LLC (“Eagle Ford Crude Oil Pipeline”)	50%		388.7		385.2
Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Corpus Christi”)	50%		109.1		75.1
Natural Gas Pipelines & Services:
White River Hub, LLC (“White River Hub”)	50%		20.1		20.8
Old Ocean Pipeline, LLC (“Old Ocean”)	50%		2.7		--
Petrochemical & Refined Products Services:
Centennial Pipeline LLC (“Centennial”)	50%		59.1		60.8
Baton Rouge Propylene Concentrator LLC (“BRPC”)	30%		3.2		4.1
Transport 4, LLC (“Transport 4”)	25%		0.5		0.6
Total		$	2,615.1	$	2,659.4

(1)In March 2018, we acquired the remaining 50% membership interest in our Delaware Processing joint venture. See Note 12 for information regarding this acquisition.

NGL Pipelines & Services

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

§	VESCO owns a natural gas processing facility in south Louisiana and a related gathering system that gathers natural gas from certain offshore developments for delivery to its natural gas processing facility.

Promix owns an NGL fractionation facility located in south Louisiana. The facility receives mixed NGLs via pipeline from natural gas processing plants located in southern Louisiana and along the Mississippi Gulf Coast. In addition, Promix owns an NGL gathering system that gathers mixed NGLs from processing plants in southern Louisiana for its fractionator.

§	BRF owns an NGL fractionation facility located in south Louisiana that receives mixed NGLs from natural gas processing plants located in Alabama, Mississippi and southern Louisiana. In addition, BRF leases an NGL storage cavern.

§	Skelly-Belvieu owns a pipeline that transports mixed NGLs from Skellytown, Texas to Mont Belvieu, Texas. The Skelly-Belvieu Pipeline receives NGLs through a pipeline interconnect with our Mid-America Pipeline System in Skellytown.

Texas Express owns an NGL pipeline that extends from Skellytown to our 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. The pipeline also transports mixed NGLs from two gathering systems owned by TEG to Mont Belvieu. In addition, mixed NGLs from the Denver-Julesburg Basin in Colorado are transported to the Texas Express Pipeline using the Front Range Pipeline.

TEG owns two NGL gathering systems that deliver mixed NGLs to the Texas Express Pipeline. The Elk City gathering system gathers mixed NGLs from natural gas processing plants in the Anadarko/Granite Wash production area located in the Texas Panhandle and western Oklahoma. The North Texas gathering system gathers mixed NGLs from natural gas processing plants in the Barnett Shale production area in North Texas.

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

Crude Oil Pipelines & Services

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

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

The Longhaul System, which consists of two pipelines, provides north-to-south transportation of crude oil from the Cushing hub to Seaway’s Jones Creek terminal near Freeport, Texas and a terminal that we own located near Katy, Texas.

The Freeport System consists of a marine import and export dock, three pipelines and other related facilities that transport crude oil to and from Freeport and the Jones Creek terminal. The Texas City System consists of a marine import and export dock, storage tanks, various pipelines and other related facilities that transport crude oil to refineries in the Texas City, Texas area and to and from terminals in the Galena Park area, our Enterprise Crude Houston (“ECHO”) terminal and locations along the Houston Ship Channel. The Texas City System also receives production from certain offshore Gulf of Mexico developments.

Eagle Ford Crude Oil Pipeline owns a crude oil pipeline that transports crude oil and condensate for producers in South Texas. The system consists of a crude oil and condensate pipeline system originating in Gardendale, Texas in LaSalle County to Three Rivers, Texas in Live Oak County and extending to Corpus Christi, Texas. The system also includes a pipeline segment that interconnects with our South Texas Crude Oil Pipeline System in Wilson County. This system includes a marine terminal facility in Corpus Christi and storage capacity across the system.

§	Eagle Ford Corpus Christi is a joint venture formed in March 2015 to construct and operate a new deep-water marine crude oil terminal that is designed to handle a variety of ocean-going vessels. The new terminal is expected to be placed into service during the second quarter of 2019.

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. The facility enables producers to access six interstate natural gas pipelines.

Old Ocean was formed in May 2018 with Energy Transfer Partners, L.P. (“ETP”) to facilitate the resumption of full service on the Old Ocean natural gas pipeline owned by ETP. The 24-inch diameter Old Ocean Pipeline originates in Maypearl, Texas in Ellis County and extends south approximately 240 miles to Sweeny, Texas in Brazoria County. ETP serves as operator of the pipeline.

Petrochemical & Refined Products Services

The principal business activity of each investee included in our Petrochemical & Refined Products Services segment is described as follows:

§	Centennial owns an interstate refined products pipeline that extends from Beaumont, Texas, to Bourbon, Illinois. Centennial also owns a refined products storage terminal located near Creal Springs, Illinois.

§	BRPC owns a propylene fractionation facility located in south Louisiana that fractionates refinery grade propylene into chemical grade propylene.

§	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,
	2018			2017			2016
NGL Pipelines & Services	$	117.0		$	73.4		$	61.4
Crude Oil Pipelines & Services		365.4			358.4			311.9
Natural Gas Pipelines & Services		6.8			3.8			3.8
Petrochemical & Refined Products Services (1)		(9.2	)		(9.6	)		(15.1	)
Total	$	480.0		$	426.0		$	362.0

(1)Losses are primarily attributable to our investment in Centennial. As a result of a trend in declining earnings, we estimated the fair value of this equity-method investment during each of the last three fiscal years. Our estimates, based on a combination of market and income approaches, indicate that the fair value of this investment remains in excess of its carrying value.

Excess Cost

On occasion, the price we pay to acquire an ownership interest in a company exceeds the underlying carrying value of the capital accounts we acquire. These excess cost amounts are attributable to the fair value of the underlying tangible assets of these entities exceeding their respective book carrying values at the time of our acquisition of ownership interests in these entities. We amortize such excess cost amounts as a reduction to equity earnings in a manner similar to depreciation. The following table presents our unamortized excess cost amounts by business segment at the dates indicated:

	December 31,
	2018		2017
NGL Pipelines & Services	$	21.7	$	22.9
Crude Oil Pipelines & Services		17.4		18.2
Petrochemical & Refined Products Services		1.7		1.8
Total	$	40.8	$	42.9

In total, amortization of excess cost amounts were $2.1 million for each of the years ended December 31, 2018, 2017 and 2016. We forecast that our amortization of excess cost amount will approximate $2.1 million in each of the next five years.

Summarized Combined Financial Information of Unconsolidated Affiliates

Combined balance sheet information for the last two years and results of operations data for the last three years for our unconsolidated affiliates are summarized in the following table (all data presented on a 100% basis):

	December 31,
	2018		2017
Balance Sheet Data:
Current assets	$	350.2	$	288.8
Property, plant and equipment, net		5,359.1		5,509.7
Other assets		80.4		71.2
Total assets	$	5,789.7	$	5,869.7

Current liabilities	$	220.6	$	233.5
Other liabilities		77.9		84.8
Combined equity		5,491.2		5,551.4
Total liabilities and combined equity	$	5,789.7	$	5,869.7

	For the Year Ended December 31,
	2018		2017		2016
Income Statement Data:
Revenues	$	1,721.3	$	1,509.0	$	1,342.0
Operating income		1,074.6		925.9		786.7
Net income		1,069.1		929.5		781.7

Intangible Assets and Goodwill

12 Months Ended

Dec. 31, 2018

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, 2018							December 31, 2017
	Gross Value		Accumulated Amortization			Carrying Value		Gross Value		Accumulated Amortization			Carrying Value
NGL Pipelines & Services:
Customer relationship intangibles	$	457.3	$	(201.9	)	$	255.4	$	447.4	$	(187.5	)	$	259.9
Contract-based intangibles		363.4		(238.7	)		124.7		280.8		(218.4	)		62.4
Segment total		820.7		(440.6	)		380.1		728.2		(405.9	)		322.3
Crude Oil Pipelines & Services:
Customer relationship intangibles		2,203.5		(174.1	)		2,029.4		2,203.5		(127.0	)		2,076.5
Contract-based intangibles		276.9		(211.7	)		65.2		281.0		(171.0	)		110.0
Segment total		2,480.4		(385.8	)		2,094.6		2,484.5		(298.0	)		2,186.5
Natural Gas Pipelines & Services:
Customer relationship intangibles		1,350.3		(447.8	)		902.5		1,350.3		(417.1	)		933.2
Contract-based intangibles		464.7		(387.9	)		76.8		464.7		(379.5	)		85.2
Segment total		1,815.0		(835.7	)		979.3		1,815.0		(796.6	)		1,018.4
Petrochemical & Refined Products Services:
Customer relationship intangibles		181.4		(51.8	)		129.6		181.4		(45.9	)		135.5
Contract-based intangibles		46.0		(21.2	)		24.8		46.0		(18.4	)		27.6
Segment total		227.4		(73.0	)		154.4		227.4		(64.3	)		163.1
Total intangible assets	$	5,343.5	$	(1,735.1	)	$	3,608.4	$	5,255.1	$	(1,564.8	)	$	3,690.3

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

	For the Year Ended December 31,
	2018		2017		2016
NGL Pipelines & Services	$	34.7	$	28.9	$	30.6
Crude Oil Pipelines & Services		87.8		92.5		98.4
Natural Gas Pipelines & Services		39.1		36.2		33.2
Petrochemical & Refined Products Services		8.7		9.3		9.1
Total	$	170.3	$	166.9	$	171.3

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

2019				2020				2021				2022				2023
$	167.1			$	159.8			$	162.1			$	167.6			$	167.8

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, 2018, the carrying value of our portfolio of customer relationship intangible assets was $3.3 billion, the principal components of which were as follows:

	Weighted Average Remaining Amortization Period	December 31, 2018
	Weighted Average Remaining Amortization Period	Gross Value		Accumulated Amortization			Carrying Value
Basin-specific customer relationships:
EFS Midstream	23.4 years	$	1,409.8	$	(117.0	)	$	1,292.8
State Line and Fairplay	28.2 years		895.0		(183.2	)		711.8
San Juan Gathering	20.8 years		331.3		(227.7	)		103.6
Encinal	8.0 years		132.9		(103.5	)		29.4
General customer relationships:
Oiltanking	25.0 years		1,192.5		(86.1	)		1,106.4

The EFS Midstream customer relationships provide us with long-term access to natural gas, NGL and condensate producers served by our EFS Midstream System, which we acquired in 2015. The EFS Midstream System serves producers in the Eagle Ford Shale, providing condensate gathering and processing services as well as gathering, treating and compression services for associated natural gas.

The State Line and Fairplay customer relationships provide us with long-term access to natural gas producers served by our Haynesville and Fairplay Gathering Systems, which we acquired in 2010. 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 eastern Texas for delivery to regional markets, including (through an interconnect with the Haynesville Extension pipeline) markets served by our Acadian Gas System. The Fairplay Gathering System gathers natural gas produced from the Cotton Valley formation within Panola and Rusk Counties in East Texas for delivery to regional markets.

The San Juan Gathering customer relationships provide us with long-term access to natural gas producers served by our San Juan Gathering System, which we acquired in 2004. The San Juan Gathering System gathers and treats natural gas produced from the San Juan Basin in northern New Mexico and southern Colorado and delivers the natural gas either directly into interstate pipelines (if dry natural gas) or to regional natural gas plants, including our Chaco facility, for further processing (if rich natural gas) prior to being transported on interstate pipelines.

§	The Encinal customer relationships provide us with long-term access to natural gas producers in the Olmos and Wilcox formations in South Texas. We acquired this intangible asset in 2006.

§	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. We acquired this intangible asset in 2014.

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, 2018, the carrying value of our portfolio of contract-based intangible assets was $291.5 million, the principal components of which were as follows:

	Weighted Average Remaining Amortization Period	December 31, 2018
	Weighted Average Remaining Amortization Period	Gross Value		Accumulated Amortization			Carrying Value
Oiltanking customer contracts	4.0 years	$	293.3	$	(221.1	)	$	72.2
Jonah natural gas gathering agreements	23.0 years		224.4		(166.3	)		58.1
Delaware Basin natural gas processing contracts	8.0 years		82.6		(6.4	)		76.2

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 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 2018 in connection with our step acquisition of the remaining 50% member interest in 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.

Goodwill

Goodwill represents the excess of the purchase price of an acquired business over the amounts assigned to assets acquired and liabilities assumed in the transaction. Goodwill is not amortized; however, it is subject to annual impairment testing at the end of each fiscal year, and more frequently, if circumstances indicate it is probable that the fair value of goodwill is below its carrying amount. We did not record any goodwill impairment charges, or reclassify any goodwill amounts between business segments, during the years ended December 31, 2018, 2017 or 2016. Based on our most recent goodwill impairment test at December 31, 2018, we estimated that the fair value of each of our reporting units was substantially in excess of its carrying value (i.e., by at least 10%). See Note 10 for our goodwill by segment balances.

Debt Obligations

12 Months Ended

Dec. 31, 2018

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,
	2018			2017
EPO senior debt obligations:
Commercial Paper Notes, variable-rates	$	--		$	1,755.7
Senior Notes V, 6.65% fixed-rate, due April 2018		--			349.7
Senior Notes OO, 1.65% fixed-rate, due May 2018		--			750.0
Senior Notes N, 6.50% fixed-rate, due January 2019		700.0			700.0
364-Day Revolving Credit Agreement, variable-rate, due September 2019		--			--
Senior Notes LL, 2.55% fixed-rate, due October 2019		800.0			800.0
Senior Notes Q, 5.25% fixed-rate, due January 2020		500.0			500.0
Senior Notes Y, 5.20% fixed-rate, due September 2020		1,000.0			1,000.0
Senior Notes TT, 2.80% fixed-rate, due February 2021		750.0			--
Senior Notes RR, 2.85% fixed-rate, due April 2021		575.0			575.0
Senior Notes VV, 3.50% fixed-rate, due February 2022		750.0			--
Senior Notes CC, 4.05% fixed-rate, due February 2022		650.0			650.0
Multi-Year Revolving Credit Facility, variable-rate, due September 2022		--			--
Senior Notes HH, 3.35% fixed-rate, due March 2023		1,250.0			1,250.0
Senior Notes JJ, 3.90% fixed-rate, due February 2024		850.0			850.0
Senior Notes MM, 3.75% fixed-rate, due February 2025		1,150.0			1,150.0
Senior Notes PP, 3.70% fixed-rate, due February 2026		875.0			875.0
Senior Notes SS, 3.95% fixed-rate, due February 2027		575.0			575.0
Senior Notes WW, 4.15% fixed-rate, due October 2028		1,000.0			--
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			--
Senior Notes XX, 4.80% fixed-rate, due February 2049		1,250.0			--
Senior Notes NN, 4.95% fixed-rate, due October 2054		400.0			400.0
TEPPCO senior debt obligations:
TEPPCO Senior Notes, 6.65% fixed-rate, due April 2018		--			0.3
TEPPCO Senior Notes, 7.55% fixed-rate, due April 2038		0.4			0.4
Total principal amount of senior debt obligations		23,750.0			21,605.7
EPO Junior Subordinated Notes A, variable-rate, redeemed August 2018		--			521.1
EPO Junior Subordinated Notes B, fixed/variable-rate, redeemed March 2018		--			682.7
EPO Junior Subordinated Notes C, fixed/variable-rate, due June 2067 (1)		256.4			256.4
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			--
TEPPCO Junior Subordinated Notes, fixed/variable-rate, due June 2067		14.2			14.2
Total principal amount of senior and junior debt obligations		26,420.6			24,780.1
Other, non-principal amounts		(242.4	)		(211.4	)
Less current maturities of debt		(1,500.1	)		(2,855.0	)
Total long-term debt	$	$ 24,678.1		$	$ 21,713.7

(1)Variable rate is reset quarterly and based on 3-month 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 in this footnote to “TEPPCO” mean TEPPCO Partners, L.P. prior to its merger with one of our wholly owned subsidiaries in October 2009.

Information Regarding Variable Interest Rates Paid

The following table presents the range of interest rates and weighted-average interest rates paid on our consolidated variable-rate debt during the year ended December 31, 2018:

	Range of Interest Rates Paid	Weighted-Average Interest Rate Paid
Commercial Paper Notes	1.50% to 2.50%	2.24%
Multi-Year Revolving Credit Facility	2.58% to 5.00%	3.37%
EPO Junior Subordinated Notes A (prior to redemption)	5.08% to 6.07%	5.71%
EPO Junior Subordinated Notes B (prior to redemption)	7.03%	7.03%
EPO Junior Subordinated Notes C	4.26% to 5.52%	4.91%

The following table presents contractually scheduled maturities of our consolidated debt obligations outstanding at December 31, 2018 for the next five years, and in total thereafter:

				Scheduled Maturities of Debt
	Total			2019			2020			2021			2022			2023			Thereafter
Senior Notes		$	23,750.0		$	1,500.0		$	1,500.0		$	1,325.0		$	1,400.0		$	1,250.0		$	16,775.0
Junior Subordinated Notes			2,670.6			--			--			--			--			--			2,670.6
Total		$	26,420.6		$	1,500.0		$	1,500.0		$	1,325.0		$	1,400.0		$	1,250.0		$	19,445.6

Parent-Subsidiary Guarantor Relationships

Enterprise Products Partners L.P. acts as guarantor of the consolidated debt obligations of EPO, with the exception of the remaining debt obligations of TEPPCO. If EPO were to default on any of its guaranteed debt, Enterprise Products Partners L.P. would be responsible for full and unconditional repayment of that obligation.

EPO Debt Obligations

Commercial Paper Notes

In June 2018, EPO increased the aggregate principal amount of short-term notes that it could issue (and have outstanding at any time) under its commercial paper program from $2.5 billion to $3.0 billion. As a back-stop to the program, we intend to maintain a minimum available borrowing capacity under EPO’s Multi-Year Revolving Credit Facility 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 Enterprise Products Partners L.P.

364-Day Credit Agreement

In September 2018, EPO entered into a 364-Day Revolving Credit Agreement that replaced its prior 364-day credit facility. The new 364-Day Revolving Credit Agreement matures in September 2019. There are currently no principal amounts outstanding under this revolving credit agreement.

Under the terms of the new 364-Day Revolving Credit Agreement, EPO may borrow up to $2.0 billion (which may be increased by up to $200 million to $2.2 billion at EPO’s election, provided certain conditions are met) at a variable interest rate for a term of up to 364 days, subject to the terms and conditions set forth therein. To the extent that principal amounts are outstanding at the maturity date, EPO may elect to have the entire principal balance then outstanding continued as a non-revolving term loan for a period of one additional year, payable in September 2020. Borrowings under this revolving credit agreement may be used for working capital, capital expenditures, acquisitions and general company purposes.

The new 364-Day Revolving Credit Agreement contains customary representations, warranties, covenants (affirmative and negative) and events of default, the occurrence of which would permit the lenders to accelerate the maturity date of any amounts borrowed under this credit agreement. The credit agreement also restricts EPO’s ability to pay cash distributions to its parent, Enterprise Products Partners L.P., if an event of default (as defined in the credit agreement) has occurred and is continuing at the time such distribution is scheduled to be paid or would result therefrom.

EPO’s obligations under the new 364-Day Revolving Credit Agreement are not secured by any collateral; however, they are guaranteed by Enterprise Products Partners L.P.

Multi-Year Revolving Credit Facility

In September 2017, EPO entered into a revolving credit agreement that matures in September 2022 (the “Multi-Year Revolving Credit Facility”). This new facility replaced EPO’s prior multi-year revolving credit facility that was scheduled to mature in September 2020. There are currently no principal amounts outstanding under the new credit facility.

Under the terms of the new Multi-Year Revolving Credit Facility, EPO may borrow up to $4.0 billion (which may be increased by up to $500 million to $4.5 billion at EPO’s election, provided certain conditions are met) at a variable interest rate for a term of five years, subject to the terms and conditions set forth therein. Borrowings under this revolving credit facility may be used as a backstop for commercial paper and for working capital, capital expenditures, acquisitions and general company purposes.

The Multi-Year Revolving Credit Facility contains customary representations, warranties, covenants (affirmative and negative) and events of default, the occurrence of which would permit the lenders to accelerate the maturity date of any amounts borrowed under this credit facility. The credit facility also restricts EPO’s ability to pay cash distributions to its parent, Enterprise Products Partners L.P., if an event of default (as defined in the credit facility) has occurred and is continuing at the time such distribution is scheduled to be paid or would result therefrom.

EPO’s obligations under the Multi-Year Revolving Credit Facility are not secured by any collateral; however, they are guaranteed by Enterprise Products Partners L.P.

Senior Notes

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 $5.0 billion and $1.25 billion of senior notes during the years ended December 31, 2018 and 2016, respectively.

In February 2018, EPO issued $2.0 billion aggregate principal amount of senior notes comprised of (i) $750 million principal amount of senior notes due February 2021 (“Senior Notes TT”) and (ii) $1.25 billion principal amount of senior notes due February 2048 (“Senior Notes UU”).

Net proceeds from the February 2018 senior notes offerings, together with the net proceeds from the February 2018 offering of Junior Subordinated Notes F (described below), were used by EPO for the temporary repayment of amounts outstanding under its commercial paper program, general company purposes, and the redemption of all $682.7 million outstanding aggregate principal amount of its Junior Subordinated Notes B.

Senior Notes TT were issued at 99.946% of their principal amount and have a fixed-rate interest rate of 2.80% per year. Senior Notes UU were issued at 99.865% of their principal amount and have a fixed-rate interest rate of 4.25% per year. Enterprise Products Partners L.P. has guaranteed the senior notes through an unconditional guarantee on an unsecured and unsubordinated basis.

In October 2018, EPO issued $3.0 billion aggregate principal amount of senior notes comprised of (i) $750 million principal amount of senior notes due February 2022 (“Senior Notes VV”), (ii) $1.00 billion principal amount of senior notes due October 2028 (“Senior Notes WW”) and (iii) $1.25 billion principal amount of senior notes due February 2049 (“Senior Notes XX”). Net proceeds from this offering were used by EPO for the temporary repayment of amounts outstanding under its commercial paper program and for general company purposes, including for growth capital expenditures.

Senior Notes VV were issued at 99.985% of their principal amount and have a fixed-rate interest rate of 3.50% per year. Senior Notes WW were issued at 99.764% of their principal amount and have a fixed-rate interest rate of 4.15% per year. Senior Notes XX were issued at 99.390% of their principal amount and have a fixed-rate interest rate of 4.80% per year. Enterprise Products Partners L.P. has guaranteed the senior notes through an unconditional guarantee on an unsecured and unsubordinated basis.

EPO Junior Subordinated Notes

EPO’s payment obligations under its junior notes are subordinated to all of its current and future senior indebtedness (as defined in the related indenture agreement). Enterprise Products Partners L.P. guarantees repayment of amounts due under these junior notes through an unsecured and subordinated guarantee. The indenture agreement governing these notes allows EPO to defer interest payments on one or more occasions for up to ten consecutive years subject to certain conditions. Subject to certain exceptions, during any period in which interest payments are deferred, neither we nor EPO can declare or make any distributions on any of our respective equity securities or make any payments on indebtedness or other obligations that rank equal with or are subordinate to our junior notes. Each series of our junior notes rank equal with each other. Generally, each series of junior notes are not redeemable by EPO while such notes bear interest at a fixed annual rate. In total, EPO issued $700.0 million and $1.7 billion of junior notes during the years ended December 31, 2018 and 2017, respectively.

In connection with the issuance of EPO’s Junior Subordinated Notes A, Junior Subordinated Notes B and Junior Subordinated Notes C, EPO entered into separate Replacement Capital Covenants in favor of covered debt holders (as defined in the underlying documents) pursuant to which EPO agreed, for the benefit of such debt holders, that it would not redeem or repurchase such junior notes unless such redemption or repurchase is made using proceeds from the issuance of certain securities.

In February 2018, EPO issued $700 million in principal amount of junior subordinated notes. The Junior Subordinated Notes F are redeemable at EPO’s option, in whole or in part, on one or more occasions, on or after February 15, 2028 at 100% of their principal amount, plus any accrued and unpaid interest thereon, and bear interest at a fixed rate of 5.375% per year through February 14, 2028. Beginning February 15, 2028, the Junior Subordinated Notes F will bear interest at a floating rate based on a three-month LIBOR rate plus 2.57%, reset quarterly. Enterprise Products Partners L.P. has guaranteed the Junior Subordinated Notes F through an unconditional guarantee on an unsecured and subordinated basis.

In March 2018, EPO redeemed all of the $682.7 million outstanding aggregate principal amount of its Junior Subordinated Notes B at a price equal to 100% of the principal amount of the notes being redeemed, plus all accrued and unpaid interest thereon to, but not including, the redemption date. This redemption was funded by EPO’s issuance of senior notes and junior subordinated notes in February 2018.

In August 2018, EPO redeemed all of the $521.1 million outstanding aggregate principal amount of its Junior Subordinated Notes A at a price equal to 100% of the principal amount of the notes being redeemed, plus all accrued and unpaid interest thereon to, but not including, the redemption date. This redemption was funded by the issuance of short-term notes under EPO’s commercial paper program.

Letters of Credit

At December 31, 2018, EPO had $101.4 million of letters of credit outstanding primarily related to our commodity hedging activities.

Lender Financial Covenants

We were in compliance with the financial covenants of our consolidated debt agreements at December 31, 2018.

Equity and Distributions

12 Months Ended

Dec. 31, 2018

Equity and Distributions [Abstract]

Equity and Distributions

Note 8. Equity and Distributions

Partners Equity

Partners’ equity reflects the various classes of limited partner interests (i.e., common units, including restricted common units) outstanding. The following table summarizes changes in the number of our outstanding units since January 1, 2016:

	Common Units (Unrestricted)			Restricted Common Units			Total Common Units
Number of units outstanding at January 1, 2016		2,010,592,504			1,960,520			2,012,553,024
Common units issued in connection with ATM program		87,867,037			--			87,867,037
Common units issued in connection with DRIP and EUPP		16,316,534			--			16,316,534
Common units issued in connection with the vesting of phantom unit awards		1,761,455			--			1,761,455
Common units issued in connection with the vesting of restricted common unit awards		1,234,502			(1,234,502	)		--
Forfeiture of restricted common unit awards		--			(43,724	)		(43,724	)
Cancellation of treasury units acquired in connection with the vesting of equity-based awards		(1,000,619	)		--			(1,000,619	)
Other		134,707			--			134,707
Number of units outstanding at December 31, 2016		2,116,906,120			682,294			2,117,588,414
Common units issued in connection with ATM program		21,807,726			--			21,807,726
Common units issued in connection with DRIP and EUPP		19,046,019			--			19,046,019
Common units issued in connection with the vesting of phantom unit awards		2,485,580			--			2,485,580
Common units issued in connection with the vesting of restricted common unit awards		681,044			(681,044	)		--
Forfeiture of restricted common unit awards		--			(1,250	)		(1,250	)
Cancellation of treasury units acquired in connection with the vesting of equity-based awards		(1,027,798	)		--			(1,027,798	)
Common units issued in connection with employee compensation		1,176,103			--			1,176,103
Other		14,685			--			14,685
Number of units outstanding at December 31, 2017		2,161,089,479			--			2,161,089,479
Common units issued in connection with DRIP and EUPP		19,861,951			--			19,861,951
Common units issued in connection with the vesting of phantom unit awards		3,479,958			--			3,479,958
Cancellation of treasury units acquired in connection with the vesting of equity-based awards		(1,037,522	)		--			(1,037,522	)
Common units issued in connection with employee compensation		1,443,586			--			1,443,586
Common units issued in connection with land acquisition (see Note 4)		1,223,242			--			1,223,242
Cancellation of treasury units acquired in connection with buyback program		(1,236,800	)		--			(1,236,800	)
Other		45,135			--			45,135
Number of units outstanding at December 31, 2018		2,184,869,029			--			2,184,869,029

Our common units represent limited partner interests, which give the holders thereof the right to participate in distributions and to exercise the other rights or privileges available to them under our Sixth Amended and Restated Agreement of Limited Partnership (as amended from time to time, the “Partnership Agreement”). We are managed by our general partner, Enterprise GP.

In accordance with our Partnership Agreement, capital accounts are maintained for our limited partners. The capital account provisions of our Partnership Agreement incorporate principles established for U.S. federal income tax purposes and are not comparable to the equity amounts presented in our consolidated financial statements prepared in accordance with GAAP. Earnings and cash distributions are allocated to holders of our common units in accordance with their respective percentage interests.

The net cash proceeds we received from the issuance of common units during the year ended December 31, 2018 were used to temporarily reduce amounts outstanding under EPO’s commercial paper program and revolving credit facilities and for general partnership purposes.

Universal shelf registration statement

We have a universal shelf registration statement (the “2016 Shelf”) on file with the SEC which allows Enterprise Products Partners L.P. and EPO (each on a standalone basis) to issue an unlimited amount of equity and debt securities, respectively. EPO issued $5.7 billion aggregate principal amount of senior notes and junior subordinated notes using the 2016 Shelf during the year ended December 31, 2018 (see Note 7). In addition, EPO issued (i) $1.7 billion of junior subordinated notes using the 2016 Shelf during the year ended December 31, 2017 and (ii) $1.25 billion of senior notes using a similar prior universal shelf registration statement during the year ended December 31, 2016. The 2016 Shelf will expire in May 2019, and we expect to file a replacement universal shelf registration statement at or before such time. We may issue additional equity and debt securities in the future to assist us in meeting our funding and liquidity requirements, including those related to capital investments.

At-the-Market (“ATM”) Program

In November 2017, we filed an amended registration statement with the SEC covering the issuance of up to $2.54 billion of our common units in amounts, at prices and on terms to be determined by market conditions and other factors at the time of such offerings in connection with our ATM program. Pursuant to this program, we may sell common units under an equity distribution agreement between Enterprise Products Partners L.P. and certain broker-dealers from time-to-time by means of ordinary brokers’ transactions through the NYSE at market prices, in block transactions or as otherwise agreed to with the broker-dealer parties to the agreement.

We did not issue any common units under the ATM program in 2018. During 2017, we issued 21,807,726 common units under the ATM program for aggregate gross cash proceeds of $603.1 million, resulting in total net cash proceeds of $597.0 million. During 2016, we issued 87,867,037 common units under the ATM program for aggregate gross cash proceeds of $2.17 billion, resulting in total net cash proceeds of $2.16 billion. This includes 3,830,256 common units sold in January 2016 to privately held affiliates of EPCO, which generated gross proceeds of $100 million.

After taking into account the aggregate sales price of common units sold under the ATM program through December 31, 2018, we have the capacity to issue additional common units under the ATM program up to an aggregate sales price of $2.54 billion.

Distribution reinvestment plan

We have a registration statement on file with the SEC in connection with our distribution reinvestment plan (“DRIP”). The DRIP provides unitholders of record and beneficial owners of our common units a voluntary means by which they can increase the number of our common units they own by reinvesting the quarterly cash distributions they receive from us into the purchase of additional common units at a discount ranging from 0% to 5%. Beginning with the distribution declared with respect to the fourth quarter of 2017 and paid in February 2018, the discount was reduced from 5% to 2.5%. Likewise, beginning with the distribution declared with respect to the fourth quarter of 2018 and paid in February 2019, the discount was reduced from 2.5% to 0%. We have the sole discretion to determine whether common units purchased under the DRIP will come from our authorized but unissued common units or from common units purchased on the open market by the DRIP administrator.

Activity under our DRIP for the last three years was as follows: 19,316,781 new common units issued during 2018, which generated net cash proceeds of $523.3 million; 18,541,355 new common units issued during 2017, which generated net cash proceeds of $462.9 million; and 15,809,503 new common units issued during 2016, which generated net cash proceeds of $374.0 million. Privately held affiliates of EPCO reinvested $213 million, $100 million and $100 million through the DRIP in each of the years ended December 31, 2018, 2017 and 2016, respectively (this amount being a component of the net cash proceeds presented for each period).

After taking into account the number of common units issued under the DRIP through December 31, 2018, we have the capacity to deliver an additional 61,400,359 common units under this plan.

Employee unit purchase plan

In addition to the DRIP, we have registration statements on file with the SEC in connection with our employee unit purchase plan (“EUPP”). Activity under our EUPP for the last three years was as follows: 545,170 new common units issued during 2018, which generated net cash proceeds of $15.1 million; 504,664 new common units issued during 2017, which generated net cash proceeds of $13.5 million; and 507,031 new common units issued during 2016, which generated net cash proceeds of $12.7 million.

After taking into account the number of common units issued under the EUPP through December 31, 2018, we have the capacity to deliver an additional 5,215,641 common units under this plan.

Registration Rights Agreement with Oiltanking Holding Americas, Inc. (“OTA”)

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 (“IDRs”) held by Oiltanking GP from OTA, a U.S. corporation, as the first step of a two-step acquisition of Oiltanking. In February 2015, we completed the second step of this 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, pursuant to Section 4(a)(2) thereof, and we granted OTA registration rights with respect to these common units under a Registration Rights Agreement between us and OTA (the “Registration Rights Agreement”). The Registration Rights Agreement provides that, subject to the terms and conditions set forth therein, OTA may request that we prepare and file a registration statement to permit and otherwise facilitate the public resale of all or a portion of the 54,807,352 Enterprise common units that OTA owns. Our obligation to OTA to effect such transactions is limited to five registration statements and underwritten offerings.

Common units issued in connection with employee compensation

In February 2018 and 2017, certain employees of EPCO received discretionary bonus payments, less any retirement plan deductions and applicable withholding taxes, for work performed on our behalf during the prior fiscal year (e.g., the February 2018 bonus amount was with respect to the year ended December 31, 2017). The net dollar value of the bonus amounts was remitted to employees through the issuance of an equivalent value of newly issued Enterprise common units under EPCO’s 2008 Enterprise Products Long-Term Incentive Plan (Third Amendment and Restatement) (“2008 Plan”). In February 2018, we issued 1,443,586 common units, which had a value of $39.1 million, in connection with the employee bonus awards. In February 2017, we issued 1,176,103 common units, which had a value of $33.7 million. The compensation expense associated with each bonus award was recognized during the year in which the work was performed. See Note 13 for additional information regarding the 2008 Plan.

Treasury Units

In December 1998, we announced a common unit buyback, or repurchase, program whereby we, together with certain affiliates, could repurchase up to 4,000,000 of our common units on the open market. We purchased the remaining authorized amount of 1,236,800 common units in late December 2018 for $30.8 million at an average price of $24.92 per unit.

During the year ended December 31, 2018, a total of 3,479,958 phantom units vested and 1,037,522 units were sold back to us by employees to cover withholding tax requirements related to the vesting of phantom unit awards. The total cost of these treasury unit purchases was $27.3 million. We cancelled such treasury units immediately upon acquisition. See Note 13 for additional information regarding our equity-based awards.

See Note 22 for subsequent event information regarding the establishment of a $2.0 billion unit buyback program in January 2019.

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), January 1, 2017	$	(83.8	)	$	(199.8	)	$	3.6		$	(280.0	)
Other comprehensive income (loss) for period, before reclassifications		(38.5	)		(5.7	)		(0.1	)		(44.3	)
Reclassification of losses (gains) to net income during period		112.2			40.4			--			152.6
Total other comprehensive income (loss) for period		73.7			34.7			(0.1	)		108.3
Accumulated Other Comprehensive Income (Loss), December 31, 2017		(10.1	)		(165.1	)		3.5			(171.7	)
Other comprehensive income (loss) for period, before reclassifications		293.2			22.2			(0.5	)		314.9
Reclassification of losses (gains) to net income during period		(130.4	)		38.1			--			(92.3	)
Total other comprehensive income (loss) for period		162.8			60.3			(0.5	)		222.6
Accumulated Other Comprehensive Income (Loss), December 31, 2018	$	152.7		$	(104.8	)	$	3.0		$	50.9

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,
	Location	2018			2017
Losses (gains) on cash flow hedges:
Interest rate derivatives	Interest expense	$	38.1		$	40.4
Commodity derivatives	Revenue		(131.7	)		111.6
Commodity derivatives	Operating costs and expenses		1.3			0.6
Total		$	(92.3	)	$	152.6

Noncontrolling Interests

Noncontrolling interests represent third party ownership interests in our consolidated subsidiaries.

Enterprise Navigator Ethylene Terminal LLC

In January 2018, we formed a new business venture with Navigator Ethylene Terminals LLC (“Navigator”) to construct and own an ethylene export terminal, which is located at Morgan’s Point on the Houston Ship Channel. Navigator holds a noncontrolling 50% equity interest in Enterprise Navigator Ethylene Terminal LLC, which owns the export facility.

Whitethorn Pipeline Company LLC

In June 2018, an affiliate of Western Gas Partners, LP (“Western”) acquired a noncontrolling 20% equity interest in our subsidiary, Whitethorn Pipeline Company LLC (“Whitethorn”), for $189.6 million in cash. This amount is a component of contributions from noncontrolling interests as presented on our Statement of Consolidated Cash Flows for the year ended December 31, 2018. Whitethorn owns the majority of our Midland-to-ECHO 1 Pipeline System.

Cash Distributions

The following table presents Enterprise’s declared quarterly cash distribution rates per common unit with respect to the quarter indicated. Actual cash distributions are paid by Enterprise within 45 days after the end of each fiscal quarter.

	Distribution Per Common Unit		Record Date	Payment Date
2016:
1st Quarter	$	0.3950	4/29/2016	5/6/2016
2nd Quarter	$	0.4000	7/29/2016	8/5/2016
3rd Quarter	$	0.4050	10/31/2016	11/7/2016
4th Quarter	$	0.4100	1/31/2017	2/7/2017
2017:
1st Quarter	$	0.4150	4/28/2017	5/8/2017
2nd Quarter	$	0.4200	7/31/2017	8/7/2017
3rd Quarter	$	0.4225	10/31/2017	11/7/2017
4th Quarter	$	0.4250	1/31/2018	2/7/2018
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

In January 2019, based on current expectations, management announced its plans to continue to recommend to the Board an increase of $0.0025 per unit per quarter to our cash distribution rate with respect to 2019. The anticipated rate of increase would result in distributions for 2019 (of $1.7650 per unit) being 2.3% higher than those paid for 2018 (of $1.7250 per unit). The payment of any quarterly cash distribution is subject to Board approval and management’s evaluation of our financial condition, results of operations and cash flows in connection with such payment.

Shin Oak NGL Pipeline Option

In May 2018, we granted Apache Corporation (“Apache”) an option to acquire up to a 33% equity interest in our subsidiary that owns the Shin Oak NGL Pipeline, which entered limited commercial service in February 2019. In November 2018, Apache contributed the Shin Oak option to Altus Midstream Company (“Altus”), which is majority-owned by Apache. The option is exercisable within sixty days after certain completion milestones are met (as defined in the underlying agreements), which we expect to occur in the second quarter of 2019.

Revenues

12 Months Ended

Dec. 31, 2018

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., processing, fractionation, transportation, 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,
	2018 (1)		2017 (2)		2016 (2)
NGL Pipelines & Services:
Sales of NGLs and related products	$	12,920.9	$	10,521.3	$	8,380.5
Segment midstream services:
Natural gas processing and fractionation		1,341.0		719.1		714.6
Transportation		1,007.0		891.7		885.6
Storage and terminals		380.0		335.9		261.8
Total segment midstream services		2,728.0		1,946.7		1,862.0
Total NGL Pipelines & Services		15,648.9		12,468.0		10,242.5
Crude Oil Pipelines & Services:
Sales of crude oil		10,001.2		7,365.2		5,802.5
Segment midstream services:
Transportation		676.5		473.9		411.1
Storage and terminals		364.9		317.7		301.4
Total segment midstream services		1,041.4		791.6		712.5
Total Crude Oil Pipelines & Services		11,042.6		8,156.8		6,515.0
Natural Gas Pipelines & Services:
Sales of natural gas		2,411.7		2,238.5		1,591.9
Segment midstream services:
Transportation		1,042.7		907.1		951.1
Total segment midstream services		1,042.7		907.1		951.1
Total Natural Gas Pipelines & Services		3,454.4		3,145.6		2,543.0
Petrochemical & Refined Products Services:
Sales of petrochemicals and refined products		5,535.4		4,696.3		2,921.9
Segment midstream services:
Fractionation and isomerization		188.3		156.3		142.6
Transportation, including marine logistics		481.8		430.7		456.2
Storage and terminals		182.8		187.8		201.1
Total segment midstream services		852.9		774.8		799.9
Total Petrochemical & Refined Products Services		6,388.3		5,471.1		3,721.8
Total consolidated revenues	$	36,534.2	$	29,241.5	$	23,022.3

(1) Revenues are accounted for under ASC 606 upon implementation at January 1, 2018. (2) Revenues are accounted for under ASC 605 for historical periods prior to January 1, 2018.

Substantially all of our revenues are derived from contracts with customers as defined within ASC 606. In total, product sales and midstream services accounted for 84% and 16%, respectively, of our consolidated revenues for the year ended December 31, 2018. During the year ended December 31, 2017, product sales and midstream services accounted for 85% and 15%, respectively, of our consolidated revenues. During the year ended December 31, 2016, product sales and midstream services accounted for 81% and 19%, respectively, of our consolidated revenues.

Apart from the following information regarding natural gas processing, we did not have any significant changes in connection with the adoption of ASC 606.

Natural gas processing utilizes service contracts that are either fee-based, commodity-based or a combination of the two. Our commodity-based contracts include keepwhole, margin-band, percent-of-liquids, percent-of-proceeds and contracts featuring a combination of commodity and fee-based terms. When a cash fee for natural gas processing services is stipulated by a contract, we record revenue as a producer’s natural gas has been processed.

Under ASC 605, our natural gas processing business did not recognize revenue in connection with non-cash consideration (the “equity NGL volumes”) it received under percent-of-liquids and similar arrangements. We recognized revenue when the associated NGLs were delivered and sold to downstream customers under NGL marketing product sales contracts.

Under ASC 606, our natural gas processing business recognizes the value of the equity NGL volumes it receives from customers as a form of midstream service revenue. The value assigned to this non-cash consideration and related inventory is based on the market value of the equity NGLs we are entitled to when the services are performed. We also recognize revenue, along with a corresponding cost of sales, when the NGLs are delivered and sold to downstream customers under NGL marketing product sales contracts.

The additional service revenue recognized for the non-cash consideration increased our total revenues by approximately 2% for the year ended December 31, 2018 when compared to the amount of revenues we would have recognized under ASC 605 for the year. Due to the rapid turnover of our inventories of NGL products each month, there was no significant change in our gross operating margin from natural gas processing and related NGL marketing activities as a result of the changes required by ASC 606.

The 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 merchant activities such as 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 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 revenues related to the equity NGLs we receive under commodity-based contracts (once the processing service has been performed and we are entitled to such volumes) at market value.

NGL pipeline transportation contracts and tariffs typically generate revenue based on a fixed fee per gallon of liquids multiplied by the volume transported and delivered (or capacity reserved). Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies or contractual arrangements. Under certain agreements customers are required to ship a minimum volume 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 pursuant to such agreements is initially deferred and subsequently recognized at the earlier of when the deficiency volume is shipped, when the likelihood of the shipper’s ability to meet the minimum volume commitment becomes remote, or when the pipeline is otherwise released from its performance obligation.

NGL fractionation primarily generates revenue under fee-based arrangements. These fees are contractually subject to adjustment for changes in certain fractionation expenses (e.g., natural gas fuel costs) and are recognized in the period services are provided.

NGL and related product storage contracts generate revenue from capacity 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 pursuant 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 loaded or unloaded at our terminals. Revenue is recognized as the 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, regional natural gas processing plants and on the open market. Revenue from these sales contracts is recognized when natural gas is sold and delivered to customers at market-based prices.

Midstream services

Natural gas transportation contracts generate revenues based on a fee per unit of volume transported multiplied by the volume gathered or delivered. Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies or contractual arrangements. Certain of our natural gas pipelines offer firm capacity reservation services whereby the shipper pays a contractual fee based on the level of throughput capacity reserved. Revenues are recognized when the volumes are transported and delivered to customers or in the period we provide firm capacity services for the shipper.

Petrochemical & Refined Products Services

Sales of petrochemicals and refined products

Our petrochemical marketing activities include the purchase and fractionation of refinery grade propylene obtained on the open market and generate revenues from the sale and delivery of polymer grade propylene to customers at market-based prices. Revenues from our PDH facility are dependent on the level of minimum volume commitments by customers and the associated contractual fees paid by them for polymer grade propylene during a given period.

Revenue from the production and sale of octane additives and high purity isobutylene is dependent on the volume of such commodities sold and delivered to customers at market-based prices.

Revenue from refined products marketing is dependent on the volume of such commodities purchased on the open market and sold and delivered to customers at market-based prices.

Midstream services

Propylene fractionation and butane isomerization facilities generate revenue through fee-based toll arrangements with customers, with such arrangements typically including a base-processing fee subject to adjustment for changes in power, fuel and labor costs. Revenue resulting from such agreements is recognized in the period the services are provided.

Petrochemical and refined products transportation contracts generate revenue based upon a fixed fee per volume multiplied by the volume transported and delivered. Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies or contractual arrangements. 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 loaded or unloaded at our terminals. Revenue is recognized as the service is provided.

Unbilled Revenue and Deferred Revenue

The following table provides information regarding our contract assets and contract liabilities at December 31, 2018:

Contract Asset	Location	Balance
Unbilled revenue (current amount)	Prepaid and other current assets	$	13.3
Total		$	13.3

Contract Liability	Location	Balance
Deferred revenue (current amount)	Other current liabilities	$	80.9
Deferred revenue (noncurrent)	Other long-term liabilities		210.3
Total		$	291.2

The following table presents significant changes in our unbilled revenue and deferred revenue balances during the year ended December 31, 2018:

	Unbilled Revenue			Deferred Revenue
Balance at January 1, 2018 (upon adoption of ASC 606)	$	--		$	224.7
Amount included in opening balance transferred to other accounts during period (1)		--			(90.8	)
Amount recorded during period		321.7			432.5
Amounts recorded during period transferred to other accounts (1)		(310.6	)		(274.8	)
Amount recorded in connection with business combination		2.2			--
Other changes		--			(0.4	)
Balance at December 31, 2018	$	13.3		$	291.2

(1)Unbilled revenues are transferred to accounts receivable once we have an unconditional right to consideration from the customer. Deferred revenues are recognized as revenue upon satisfaction of our performance obligation to the customer.

Remaining Performance Obligations

The following table presents estimated fixed consideration from contracts with customers 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 at December 31, 2018. 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 as we recognize revenue equal to the amount that we have the right to invoice.

2019				2020				2021				2022				2023				Thereafter				Total
$	3,530.6			$	3,187.3			$	2,641.4			$	2,145.0			$	1,798.7			$	7,289.9			$	20,592.9

Impact of Change in Accounting Policy – ASC 606 Transition Disclosures

The following information and tables are provided to summarize the impacts of adopting ASC 606 on our consolidated financial statements for the year ended December 31, 2018.

As noted previously, additional service revenue and related inventory is now recognized in connection with the equity NGL volumes (a form of non-cash consideration) we receive under natural gas processing agreements. When the inventory is sold through our NGL marketing activities, we reflect additional cost of sales amounts within our operating costs and expenses.

Unbilled revenues have historically been presented as a component of accounts receivable on our consolidated balance sheets. Upon implementation of ASC 606, we reclassified these amounts to “Prepaid and other current assets” since these amounts represent conditional rights to consideration. Once we have an unconditional right to consideration, the amount is transferred to accounts receivable.

Historically, amounts received from customers as CIACs related to pipeline construction activities and production well tie-ins have been netted against property, plant and equipment on our consolidated balance sheets and presented as a cash inflow within the investing activities section of our statements of consolidated cash flows. Upon implementation of ASC 606, these amounts are now recognized as a component of midstream service revenue on our statement of operations and are a component of cash provided by operating activities as presented on our statements of consolidated cash flows.

Consolidated Balance Sheet Information at December 31, 2018

	Impact of change in accounting policy
	Balances without adoption of ASC 606		Impact of adoption of ASC 606			As Reported
Assets
Accounts receivable – trade, net	$	3,672.4	$	(13.3	)	$	3,659.1
Prepaid and other current assets		298.2		13.3			311.5
Property, plant and equipment, net		38,639.3		98.3			38,737.6
Liabilities and Equity
Other current liabilities		404.3		0.5			404.8
Other long-term liabilities		664.8		86.8			751.6
Partners' equity		23,842.5		11.0			23,853.5

The impact of adoption of ASC 606 includes the reclassification of unbilled revenue amounts of $13.3 million from accounts receivable to other current assets.

Consolidated Statement of Operations Information for the Year Ended December 31, 2018

	Impact of change in accounting policy
	Balances without adoption of ASC 606		Impact of adoption of ASC 606		As Reported
Revenues	$	35,901.5	$	632.7	$	36,534.2
Costs and expenses:
Operating costs and expenses:		30,775.6		621.7		31,397.3

The impact of adopting ASC 606 on revenues for the year ended December 31, 2018 includes the recognition of $621.7 million of revenues from non-cash consideration (i.e., equity NGLs) earned when providing natural gas processing services and $11.0 million recognized in connection with CIACs. Operating costs and expenses for the year ended December 31, 2018 includes $621.7 million attributable to cost of sales recognized when the equity NGL products were sold and delivered to customers.

Consolidated Statement of Cash Flows Information for the Year Ended December 31, 2018

	Impact of change in accounting policy
	Balances without adoption of ASC 606			Impact of adoption of ASC 606			As Reported
Operating activities:
Net income	$	4,227.5		$	11.0		$	4,238.5
Net effect of changes in operating accounts		(71.1	)		87.3			16.2
Investing activities:
Contributions in aid of construction costs		87.3			(87.3	)		--

Business Segments

12 Months Ended

Dec. 31, 2018

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 chief operating decision makers in deciding how to allocate resources and in assessing operating and financial performance. The principal executive and financial officers of our general partner have been identified as our chief operating decision makers. While these two officers evaluate results in a number of different ways, the business segment structure is the primary basis for which the allocation of resources and financial results are assessed.

The following information summarizes the assets and operations of each business segment (mileage and other statistics are unaudited):

Our NGL Pipelines & Services business segment currently includes our natural gas processing plants and associated NGL marketing activities; approximately 19,200 miles of NGL pipelines; NGL and related product storage facilities; and 16 NGL fractionators. This segment also includes our NGL export docks and related operations.

§	Our Crude Oil Pipelines & Services business segment currently includes approximately 5,300 miles of crude oil pipelines, crude oil storage terminals located in Oklahoma and Texas, and associated crude oil marketing activities.

Our Natural Gas Pipelines & Services business segment currently includes approximately 19,700 miles of natural gas pipeline systems that provide for the gathering and transportation of natural gas in Colorado, Louisiana, New Mexico, Texas and Wyoming. This segment also includes our natural gas marketing activities.

Our Petrochemical & Refined Products Services business segment currently includes (i) propylene production facilities, which include our propylene fractionation units and recently completed PDH facility, approximately 800 miles of pipelines, and associated marketing operations; (ii) a butane isomerization complex and related deisobutanizer units; (iii) octane enhancement and high purity isobutylene production facilities; (iv) refined products pipelines aggregating approximately 4,100 miles, terminals and associated marketing activities; and (v) marine transportation.

Our plants, pipelines and other fixed assets are located in the U.S.

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,
	2018			2017			2016
Operating income	$	5,408.6		$	3,928.9		$	3,580.7
Adjustments to reconcile operating income to total gross operating margin:
Add depreciation, amortization and accretion expense in operating costs and expenses		1,687.0			1,531.3			1,456.7
Add asset impairment and related charges in operating costs and expenses		50.5			49.8			52.8
Subtract net gains attributable to asset sales in operating costs and expenses		(28.7	)		(10.7	)		(2.5	)
Add general and administrative costs		208.3			181.1			160.1
Adjustments for make-up rights on certain new pipeline projects:
Add non-refundable payments received from shippers attributable to make-up rights (1)		21.5			24.1			17.5
Subtract the subsequent recognition of revenues attributable to make-up rights (2)		(56.2	)		(29.9	)		(34.6	)
Total segment gross operating margin	$	7,291.0		$	5,674.6		$	5,230.7

(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 new pipeline projects (Texas Express Pipeline, Front Range Pipeline, ATEX, Aegis Ethane Pipeline and Seaway Pipeline). From an internal (and segment) reporting standpoint, management considers the transportation fees paid by committed shippers on these pipeline projects, including any non-refundable revenues that may be deferred under GAAP related to make-up rights, to be important in assessing the financial performance of these pipeline assets. Although the adjustments for make-up rights are included in segment gross operating margin, our consolidated revenues do not reflect any deferred revenues until the conditions for recognizing such revenues are met in accordance with GAAP.

Gross operating margin by segment is calculated by subtracting segment operating costs and expenses from segment revenues, with both segment totals reflecting the adjustments noted in the preceding table, as applicable, and before the elimination of intercompany transactions. The following table presents gross operating margin by segment for the years indicated:

	For the Year Ended December 31,
	2018		2017		2016
Gross operating margin by segment:
NGL Pipelines & Services	$	3,830.7	$	3,258.3	$	2,990.6
Crude Oil Pipelines & Services		1,511.3		987.2		854.6
Natural Gas Pipelines & Services		891.2		714.5		734.9
Petrochemical & Refined Products Services		1,057.8		714.6		650.6
Total segment gross operating margin	$	7,291.0	$	5,674.6	$	5,230.7

Summarized Segment Financial Information

Information by business segment, together with reconciliations to amounts presented on our Statements of Consolidated Operations, is presented in the following table:

	Reportable Business Segments
	NGL Pipelines & Services		Crude Oil Pipelines & Services		Natural Gas Pipelines & Services		Petrochemical & Refined Products Services			Adjustments and Eliminations			Consolidated Total
Revenues from third parties:
Year ended December 31, 2018	$	15,630.5	$	10,968.2	$	3,439.5	$	6,388.3		$	--		$	36,426.5
Year ended December 31, 2017		12,455.7		8,137.2		3,132.5		5,471.1			--			29,196.5
Year ended December 31, 2016		10,232.7		6,478.7		2,532.4		3,721.8			--			22,965.6
Revenues from related parties:
Year ended December 31, 2018		18.4		74.4		14.9		--			--			107.7
Year ended December 31, 2017		12.3		19.6		13.1		--			--			45.0
Year ended December 31, 2016		9.8		36.3		10.6		--			--			56.7
Intersegment and intrasegment revenues:
Year ended December 31, 2018		26,453.6		35,490.4		721.9		2,917.5			(65,583.4	)		--
Year ended December 31, 2017		27,278.6		15,943.0		850.8		1,766.9			(45,839.3	)		--
Year ended December 31, 2016		19,150.0		9,052.0		668.5		1,234.8			(30,105.3	)		--
Total revenues:
Year ended December 31, 2018		42,102.5		46,533.0		4,176.3		9,305.8			(65,583.4	)		36,534.2
Year ended December 31, 2017		39,746.6		24,099.8		3,996.4		7,238.0			(45,839.3	)		29,241.5
Year ended December 31, 2016		29,392.5		15,567.0		3,211.5		4,956.6			(30,105.3	)		23,022.3
Equity in income (loss) of unconsolidated affiliates:
Year ended December 31, 2018		117.0		365.4		6.8		(9.2	)		--			480.0
Year ended December 31, 2017		73.4		358.4		3.8		(9.6	)		--			426.0
Year ended December 31, 2016		61.4		311.9		3.8		(15.1	)		--			362.0

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 equity method investees) provides services to producers and consumers of natural gas, NGLs, crude oil, refined products and certain petrochemicals. In general, hydrocarbons may enter our asset system in a number of ways, such as through a natural gas processing plant, a natural gas gathering pipeline, a crude oil pipeline or terminal, an NGL fractionator, an NGL storage facility or an NGL gathering or transportation pipeline. Many of our equity investees are included within our integrated midstream asset network. For example, we use the Front Range Pipeline and Texas Express Pipeline to transport mixed NGLs to our Mont Belvieu 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 our equity method investees to our operations, we believe the presentation of equity earnings from such investees as a component of gross operating margin and operating income is meaningful and appropriate.

Information by business segment, together with reconciliations to our Consolidated Balance Sheet totals, is presented in the following table:

	Reportable Business Segments
	NGL Pipelines & Services		Crude Oil Pipelines & Services		Natural Gas Pipelines & Services		Petrochemical & Refined Products Services		Adjustments and Eliminations		Consolidated Total
Property, plant and equipment, net: (see Note 4)
At December 31, 2018	$	14,845.4	$	5,847.7	$	8,303.8	$	6,213.9	$	3,526.8	$	38,737.6
At December 31, 2017		13,831.2		5,208.4		8,375.0		3,507.7		4,698.1		35,620.4
At December 31, 2016		14,091.5		4,216.1		8,403.0		3,261.2		3,320.7		33,292.5
Investments in unconsolidated affiliates: (see Note 5)
At December 31, 2018		662.0		1,867.5		22.8		62.8		--		2,615.1
At December 31, 2017		733.9		1,839.2		20.8		65.5		--		2,659.4
At December 31, 2016		750.4		1,824.6		21.7		80.6		--		2,677.3
Intangible assets, net: (see Note 6)
At December 31, 2018		380.1		2,094.6		979.3		154.4		--		3,608.4
At December 31, 2017		322.3		2,186.5		1,018.4		163.1		--		3,690.3
At December 31, 2016		350.2		2,279.0		1,054.5		180.4		--		3,864.1
Goodwill: (see Note 6)
At December 31, 2018		2,651.7		1,841.0		296.3		956.2		--		5,745.2
At December 31, 2017		2,651.7		1,841.0		296.3		956.2		--		5,745.2
At December 31, 2016		2,651.7		1,841.0		296.3		956.2		--		5,745.2
Segment assets:
At December 31, 2018		18,539.2		11,650.8		9,602.2		7,387.3		3,526.8		50,706.3
At December 31, 2017		17,539.1		11,075.1		9,710.5		4,692.5		4,698.1		47,715.3
At December 31, 2016		17,843.8		10,160.7		9,775.5		4,478.4		3,320.7		45,579.1

Segment assets consist of property, plant and equipment, investments in unconsolidated affiliates, intangible assets and goodwill. The carrying values of such amounts are assigned to each segment based on each asset’s or investment’s principal operations and contribution to the gross operating margin of that particular segment. Since construction-in-progress amounts (a component of property, plant and equipment) generally do not contribute to segment gross operating margin, such amounts are excluded from segment asset totals until the underlying assets are placed in service. Intangible assets and goodwill are assigned to each segment based on the classification of the assets to which they relate. The remainder of our consolidated total assets, which consist primarily of working capital assets, are excluded from segment assets since these amounts are not attributable to one specific segment (e.g. cash).

Other Revenue and Expense Information

The following table presents supplemental information regarding our consolidated revenues and costs and expenses for the years indicated:

	For the Year Ended December 31,
	2018			2017			2016
Consolidated revenues:
NGL Pipelines & Services	$	15,648.9		$	12,468.0		$	10,242.5
Crude Oil Pipelines & Services		11,042.6			8,156.8			6,515.0
Natural Gas Pipelines & Services		3,454.4			3,145.6			2,543.0
Petrochemical & Refined Products Services		6,388.3			5,471.1			3,721.8
Total consolidated revenues	$	36,534.2		$	29,241.5		$	23,022.3

Consolidated costs and expenses:
Operating costs and expenses:
Cost of sales	$	26,789.8		$	21,487.0		$	15,710.9
Other operating costs and expenses (1)		2,898.7			2,500.1			2,425.6
Depreciation, amortization and accretion		1,687.0			1,531.3			1,456.7
Asset impairment and related charges		50.5			49.8			52.8
Net gains attributable to asset sales		(28.7	)		(10.7	)		(2.5	)
General and administrative costs		208.3			181.1			160.1
Total consolidated costs and expenses	$	31,605.6		$	25,738.6		$	19,803.6

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

Fluctuations in our product sales revenues and related cost of sales amounts are explained in part by changes in energy commodity prices. In general, lower energy commodity prices result in a decrease in our revenues attributable to product sales; however, these lower commodity prices also decrease the associated cost of sales as purchase costs decline. The same correlation would be true in the case of higher energy commodity sales prices and purchase costs.

Major Customer Information

Our largest non-affiliated customer for the years ended December 31, 2018, 2017 and 2016 was Vitol Holding B.V. and its affiliates (collectively, “Vitol”), which accounted for approximately 7.8%, 11.2% and 9.9%, respectively, of our consolidated revenues. Vitol is a global energy and commodity trading company.

Earnings Per Unit

12 Months Ended

Dec. 31, 2018

Earnings Per Unit [Abstract]

Earnings Per Unit

Note 11. Earnings Per Unit

Basic earnings per unit is computed by dividing net income or loss available to our common unitholders by the weighted-average number of our distribution-bearing units outstanding during a period. Diluted earnings per unit is computed by dividing net income or loss attributable to our limited partners by the sum of (i) the weighted-average number of our distribution-bearing units outstanding during a period (as used in determining basic earnings per unit) and (ii) the weighted-average number of our phantom units outstanding during a period.

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

	For the Year Ended December 31,
	2018			2017			2016
BASIC EARNINGS PER UNIT
Net income attributable to limited partners	$	4,172.4		$	2,799.3		$	2,513.1
Undistributed earnings allocated and cash payments on phantom unit awards (1)		(21.5	)		(15.9	)		(12.9	)
Net income available to common unitholders	$	4,150.9		$	2,783.4		$	2,500.2

Basic weighted-average number of common units outstanding		2,176.5			2,145.0			2,081.4

Basic earnings per unit	$	1.91		$	1.30		$	1.20

DILUTED EARNINGS PER UNIT
Net income attributable to limited partners	$	4,172.4		$	2,799.3		$	2,513.1

Diluted weighted-average number of units outstanding:
Distribution-bearing common units		2,176.5			2,145.0			2,081.4
Phantom units (1)		10.5			9.3			7.7
Total		2,187.0			2,154.3			2,089.1

Diluted earnings per unit	$	1.91		$	1.30		$	1.20

(1)Each phantom unit award includes a DER, which entitles the recipient to receive cash payments equal to the product of the number of phantom unit awards and the cash distribution per unit paid to our common unitholders. Cash payments made in connection with DERs are nonforfeitable. As a result, the phantom units are considered participating securities for purposes of computing basic earnings per unit.

Business Combinations

12 Months Ended

Dec. 31, 2018

Business Combinations [Abstract]

Business Combinations

Note 12. Business Combinations

Acquisition of Delaware Processing

On March 29, 2018, we acquired the remaining 50% member interest in our Delaware Processing joint venture for $150.6 million in cash, net of $3.9 million of cash held by the former joint venture. As a result, Delaware Processing is now our wholly-owned consolidated subsidiary. Delaware Processing owns a cryogenic natural gas processing facility having a capacity of 150 million cubic feet per day (“MMcf/d”). The facility is located in Reeves County, Texas and entered service in August 2016. The acquired business serves growing production of NGL-rich natural gas from 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 acquisition at March 29, 2018.

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 revenues, costs and expenses, operating income, net income attributable to Enterprise Products Partners L.P. and earnings per unit amounts for the years ended December 31, 2018 and 2017 would not have differed materially from those we actually reported had the acquisition been completed on January 1, 2017 rather than March 29, 2018.

At March 29, 2018, our 50% equity investment in Delaware Processing was recorded at $107.0 million. Upon acquisition of the remaining 50% member interest, our existing equity investment was remeasured to fair value resulting in the recognition of a non-cash $39.4 million gain, which is presented within “Other income (expense)” on our Consolidated Statement of Operations for the year ended December 31, 2018.

The results for this business are reported under the NGL Pipelines & Services business segment.

Acquisition of Azure Midstream

In April 2017, we closed the acquisition of a midstream energy business from Azure Midstream Partners, LP and its operating subsidiaries (collectively, “Azure”) for $191.4 million in cash. The acquired business assets, which are located primarily in East Texas, include over 750 miles of natural gas gathering pipelines and two natural gas processing facilities (Panola and Fairway) with an aggregate processing capacity of 130 MMcf/d. The acquired business primarily serves production from the Haynesville Shale and Bossier, Cotton Valley and Travis Peak formations.

The financial results of the acquired business are reflected in our consolidated results from April 30, 2017, which was the effective date of the Azure acquisition. On a historical pro forma consolidated basis, our revenues, costs and expenses, operating income, net income attributable to Enterprise Products Partners L.P., and earnings per unit amounts for the years ended December 31, 2017 and 2016 would not have differed materially from those we actually reported had the Azure acquisition been completed on January 1, 2016 rather than April 30, 2017.

The following table presents the final fair value allocation of assets acquired and liabilities assumed in the Azure acquisition at April 30, 2017.

Assets acquired in business combination:
Current assets	$	3.1
Property, plant and equipment		193.1
Total assets acquired		196.2
Liabilities assumed in business combination:
Current liabilities		(1.4	)
Long-term liabilities		(3.4	)
Total liabilities assumed		(4.8	)
Total identifiable net assets	$	191.4

The contribution of this newly acquired business to our consolidated revenues and net income was not material for the year ended December 31, 2017.

Equity-Based Awards

12 Months Ended

Dec. 31, 2018

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,
	2018		2017		2016
Equity-classified awards:
Phantom unit awards	$	99.7	$	92.8	$	78.6
Restricted common unit awards		--		0.5		4.7
Profits interest awards		6.1		6.0		5.4
Liability-classified awards		0.3		0.4		0.5
Total	$	106.1	$	99.7	$	89.2

The fair value of equity-classified awards is amortized into earnings over the requisite service or vesting period. Equity-classified awards are expected to result in the issuance of common units upon vesting. Compensation expense for liability-classified awards is recognized over the requisite service or vesting period based on the fair value of the award remeasured at each reporting date. Liability-classified awards are settled in cash upon vesting.

At December 31, 2018, all of the phantom unit awards outstanding had been granted under the 2008 Plan. The 2008 Plan is a long-term incentive plan under which any employee or consultant of EPCO, us or our affiliates that provides services to us, directly or indirectly, may receive incentive compensation awards in the form of options, restricted common units, phantom units, distribution equivalent rights (“DERs”), unit appreciation rights (“UARs”), unit awards, other unit-based awards or substitute awards. Non-employee directors of our general partner may also participate in the 2008 Plan. The maximum number of common units authorized for issuance under the 2008 Plan was 45,000,000 at December 31, 2018. This amount automatically increased under the terms of the 2008 Plan by 5,000,000 common units on January 1, 2019 and will continue to automatically increase annually on January 1 thereafter during the term of the 2008 Plan; provided, however, that in no event shall the maximum aggregate number exceed 70,000,000 common units. The 2008 Plan is effective until September 30, 2023 or, if earlier, until the time that all available common units under the 2008 Plan have been delivered to participants or the time of termination of the 2008 Plan by the Board of Directors of EPCO or by the Audit and Conflicts Committee. After giving effect to awards granted under the 2008 Plan through December 31, 2018, a total of 19,116,132 additional common units were available for issuance.

EPCO has six limited partnerships (generally referred to as “Employee Partnerships”) to serve as long-term incentive arrangements for key employees of EPCO by providing them a “profits interest” in an Employee Partnership. The Employee Partnerships named (i) EPD 2018 Unit IV L.P. (“EPD IV”) and (ii) EPCO Unit II L.P. (“EPCO II”) were formed in December 2018. The Employee Partnerships named (i) EPD PubCo Unit I L.P. (“PubCo I”), (ii) EPD PubCo Unit II L.P. (“PubCo II”), (iii) EPD PubCo Unit III L.P. (“PubCo III”) and (iv) EPD PrivCo Unit I L.P. (“PrivCo I”) were formed in 2016.

At December 31, 2018, there were no restricted common unit awards outstanding under the Enterprise Products 1998 Long-Term Incentive Plan (“1998 Plan”). The 1998 Plan is effectively closed and no new awards have been granted under this plan since 2014. The 1998 Plan provided for awards of our common units and other rights to our non-employee directors and to employees of EPCO and its affiliates providing services to us. Historically, awards under the 1998 Plan consisted of unit options and restricted common units.

Phantom Unit Awards

Phantom unit awards allow recipients to acquire our common units (at no cost to the recipient apart from fulfilling service and other conditions) once a defined vesting period expires, subject to customary forfeiture provisions. Phantom unit awards generally vest at a rate of 25% per year beginning one year after the grant date and are non-vested until the required service periods expire. All of the phantom unit awards were issued under the 2008 Plan.

At December 31, 2018, substantially all of our phantom unit awards are expected to result in the issuance of common units upon vesting; therefore, the applicable awards are accounted for as equity-classified awards. The grant date fair value of a phantom unit award is based on the market price per unit of our common units on the date of grant. Compensation expense is recognized based on the grant date fair value, net of an allowance for estimated forfeitures, over the requisite service or vesting period.

The following table presents phantom unit award activity for the years indicated:

	Number of Units			Weighted- Average Grant Date Fair Value per Unit (1)
Phantom unit awards at January 1, 2016		5,426,949		$	33.63
Granted (2)		4,508,310		$	21.90
Vested		(1,761,455	)	$	33.10
Forfeited		(406,303	)	$	28.52
Phantom unit awards at December 31, 2016		7,767,501		$	27.20
Granted (3)		4,268,920		$	28.83
Vested		(2,490,081	)	$	28.30
Forfeited		(256,839	)	$	27.60
Phantom unit awards at December 31, 2017		9,289,501		$	27.65
Granted (4)		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

(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 2016 was $98.7 million based on a grant date market price of our common units ranging from $21.86 to $27.39 per unit. An estimated annual forfeiture rate of 3.9% was applied to these awards. (3) The aggregate grant date fair value of phantom unit awards issued during 2017 was $123.1 million based on a grant date market price of our common units ranging from $24.55 to $28.87 per unit. An estimated annual forfeiture rate of 3.8% was applied to these awards. (4) 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 our common units ranging from $25.40 to $29.22 per unit. An estimated annual forfeiture rate of 3.2% was applied to these awards.

After taking into account tax withholding requirements, we issued 2,442,436, 1,687,692 and 1,170,600 common units in connection with the vesting of phantom unit awards in the years ended December 31, 2018, 2017 and 2016, respectively.

The 2008 Plan provides for the issuance of DERs in connection with phantom unit awards. A DER entitles the participant to nonforfeitable cash payments equal to the product of the number of phantom unit awards outstanding for the participant and the cash distribution per common unit paid to our common unitholders. Cash payments made in connection with DERs are charged to partners’ equity when the phantom unit award is expected to result in the issuance of common units; otherwise, such amounts are expensed.

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

	For the Year Ended December 31,
	2018		2017		2016
Cash payments made in connection with DERs	$	17.7	$	15.1	$	11.7
Total intrinsic value of phantom unit awards that vested during period	$	90.7	$	69.8	$	40.9

For the EPCO group of companies, the unrecognized compensation cost associated with phantom unit awards was $104.2 million at December 31, 2018, of which our share of the cost is currently estimated to be $84.6 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 2.1 years.

Profits Interest Awards

In 2018 and 2016, EPCO Holdings Inc. (“EPCO Holdings”), a privately held affiliate of EPCO, contributed a portion of the Enterprise common units it owned to each of the Employee Partnerships as disclosed in the table below. In exchange for these contributions, EPCO Holdings was admitted as the Class A limited partner of each Employee Partnership. Also on the applicable contribution date, certain key EPCO employees were issued Class B limited partner interests (i.e., profits interest awards) and admitted as Class B limited partners of each Employee Partnership, all without any capital contribution by such employees. EPCO serves as the general partner of each Employee Partnership.

In general, the Class A limited partner earns a quarterly preferred return (see table below for details) on the number of Enterprise common units contributed by EPCO Holdings to each Employee Partnership, with any residual cash amount remaining in each Employee Partnership being paid to the applicable Class B limited partners on a quarterly basis as a distribution. Upon liquidation of an Employee Partnership, assets having a then current fair market value equal to the Class A limited partner’s capital base in such Employee Partnership will be distributed to the Class A limited partner. Any remaining assets of such Employee Partnership will be distributed to the Class B limited partners of such Employee Partnership as a residual profits interest, which represents the appreciation in value of the Employee Partnership’s assets since the date of EPCO Holdings’ contribution to it, as described above.

Unless otherwise agreed to by EPCO and a majority in interest of the limited partners of each Employee Partnership, such Employee Partnership will terminate at the earliest to occur of (i) 30 days following its vesting date, (ii) a change of control or (iii) a dissolution of the Employee Partnership.

Individually, each Class B limited partner interest is subject to forfeiture if the participating employee’s employment with EPCO is terminated prior to vesting, with customary exceptions for death, disability and certain retirements. The risk of forfeiture will also lapse upon certain change of control events. Forfeited individual Class B limited partner interests are allocated to the remaining Class B limited partners.

The following table summarizes key elements of each Employee Partnership as of December 31, 2018:

Employee

Partnership

Enterprise

Common Units

Contributed to

Employee Partnership

by EPCO Holdings

Class A

Capital

Base (1)

Class A

Preference

Return (2)

Expected

Vesting/

Liquidation

Date

Estimated

Grant Date

Fair Value of

Profits Interest

Awards (3)

Unrecognized

Compensation

Cost (4)

PubCo I

2,723,052

$63.7 million

0.3900

Feb. 2020

$13.0 million

$4.3 million

PubCo II

2,834,198

$66.3 million

0.3900

Feb. 2021

$14.9 million

$7.3 million

PubCo III

105,000

$2.5 million

0.3900

Apr. 2020

$0.5 million

$0.2 million

PrivCo I

1,111,438

$26.0 million

0.3900

Feb. 2021

$5.8 million

$0.5 million

EPD IV

6,400,000

$172.9 million

0.4325

Dec. 2023

$26.7 million

$23.1 million

EPCO II

1,600,000

$43.2 million

0.4325

Dec. 2023

$6.7 million

$0.5 million

(1)Represents fair market value of the Enterprise common units contributed to each Employee Partnership at the applicable contribution date.

(2)Each quarter, the Class A limited partner in each Employee Partnership is paid a cash distribution equal to the product of (i) the number of common units owned by the Employee Partnership and (ii) the Class A Preference Return (subject to equitable adjustment in order to reflect any equity split, equity distribution or dividend, reverse split, combination, reclassification, recapitalization or other similar event affecting such common units). To the extent that the Employee Partnership has cash remaining after making this quarterly payment to the Class A limited partner, the residual cash is distributed to the Class B limited partners on a quarterly basis.

(3)Represents the total grant date fair value of the profits interest awards irrespective of how such costs will be allocated between us and EPCO and its privately held affiliates.

(4)Represents our expected share of the unrecognized compensation cost at December 31, 2018. We expect to recognize our share of the unrecognized compensation cost for PubCo I, PubCo II, PubCo III, PrivCo I, EPD IV and EPCO II over a weighted-average period of 1.1 years, 2.1 years, 1.3 years, 2.1 years, 4.9 years and 4.9 years, respectively.

The grant date fair value of each Employee Partnership is based on (i) the estimated value (as determined using a Black-Scholes option pricing model) of such Employee Partnership’s assets that would be distributed to the Class B limited partners thereof upon liquidation and (ii) the value, based on a discounted cash flow analysis, of the residual quarterly cash amounts that such Class B limited partners are expected to receive over the life of the Employee Partnership.

The following table summarizes the assumptions we used in applying a Black-Scholes option pricing model to derive that portion of the estimated grant date fair value of the profits interest awards for each Employee Partnership:

	Expected	Risk-Free	Expected	Expected Unit
Employee	Life	Interest	Distribution	Price
Partnership	of Award	Rate	Yield	Volatility
PubCo I	4.0 years	0.9% to 2.7%	5.9% to 7.0%	19% to 40%
PubCo II	5.0 years	1.1% to 3.0%	5.9% to 7.0%	19% to 40%
PubCo III	4.0 years	1.0% to 2.2%	6.1% to 6.8%	27% to 40%
PrivCo I	5.0 years	1.2% to 1.6%	6.1% to 6.7%	28% to 40%
EPD IV	5.0 years	2.8%	6.5%	27%
EPCO II	5.0 years	2.8%	6.5%	27%

Compensation expense attributable to the profits interest awards is based on the estimated grant date fair value of each award. A portion of the fair value of these equity-based awards is allocated to us under the ASA as a non-cash expense. We are not responsible for reimbursing EPCO for any expenses of the Employee Partnerships, including the value of any contributions of units made by EPCO Holdings.

Restricted Common Unit Awards

Restricted common unit awards allowed recipients to acquire our common units (at no cost to the recipient apart from fulfilling service and other conditions) once a defined vesting period expired, subject to customary forfeiture provisions. Restricted common unit awards generally vested at a rate of 25% per year beginning one year after the grant date and were non-vested until the required service periods expired. No restricted common unit awards have been outstanding since 2017.

The fair value of a restricted common unit award was based on the market price per unit of our common units on the date of grant. Compensation expense was recognized based on the grant date fair value, net of an allowance for estimated forfeitures, over the requisite service or vesting period.

The following table presents restricted common unit award activity for the years indicated:

	Number of Units			Weighted- Average Grant Date Fair Value per Unit (1)
Restricted common units at January 1, 2016		1,960,520		$	27.88
Vested		(1,234,502	)	$	27.45
Forfeited		(43,724	)	$	28.48
Restricted common units at December 31, 2016		682,294		$	28.61
Vested		(681,044	)	$	28.60
Forfeited		(1,250	)	$	31.07
Restricted common units at December 31, 2017		--		$	N/A

(1)Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued.

Each recipient of a restricted common unit award was entitled to nonforfeitable cash distributions equal to the product of the number of restricted common units outstanding for the participant and the cash distribution per unit paid to our common unitholders. These distributions were included in “Cash distributions paid to limited partners” as presented on our Statements of Consolidated Cash Flows.

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

	For the Year Ended December 31,
	2017		2016
Cash distributions paid to restricted common unitholders	$	0.3	$	1.6
Total intrinsic value of restricted common unit awards that vested during period	$	18.9	$	28.5

Derivative Instruments, Hedging Activities and Fair Value Measurements

12 Months Ended

Dec. 31, 2018

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

Derivative Instruments, Hedging Activities and Fair Value Measurements

Note 14. Derivative Instruments, Hedging Activities and Fair Value Measurements

In the normal course of our business operations, we are exposed to certain risks, including changes in interest rates and commodity prices. In order to manage risks associated with assets, liabilities and certain anticipated future transactions, we use derivative instruments such as futures, forward contracts, swaps, options and other instruments with similar characteristics. Substantially all of our derivatives are used for non-trading activities.

On January 1, 2018, we early adopted ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. Since the impact of the new guidance was not material to our consolidated financial statements, no transition adjustments were recorded. In accordance with ASU 2017-12 both the effective and ineffective portion of a cash flow hedge are initially reported as a component of accumulated other comprehensive income (loss) and reclassified into earnings when the forecasted transaction affects earnings.

Interest Rate Hedging Activities

We may utilize interest rate swaps, forward starting swaps and similar derivative instruments to manage our exposure to changes in interest rates charged on borrowings under certain consolidated debt agreements. This strategy may be used in controlling our overall cost of capital associated with such borrowings.

As a result of market conditions, we terminated an aggregate $275 million notional amount of forward starting swaps in 2018, 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 will be amortized to earnings (as a decrease in interest expense) over a 30-year period beginning in February 2019. Likewise, in 2017, we terminated an aggregate $275 million notional amount of forward starting swaps (cash flow hedges), which resulted in cash proceeds totaling $30.6 million that are being amortized to earnings (as a decrease in interest expense) over the 30-year life of the associated debt through February 2048. In 2016, we terminated an aggregate $250 million notional amount of forward starting swaps (cash flow hedges), which resulted in cash proceeds totaling $6.1 million that are being amortized to earnings (as a decrease in interest expense) over the 30-year life of the associated debt through September 2047.

In 2018, we sold swaptions related to our interest rate hedging activities that resulted in the recognition of an aggregate $29.4 million of cash gains (swaption premium income) that were reflected as a reduction in interest expense for the year.

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, 2018, 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, 2018 (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)		4.9		n/a	Cash flow hedge
Forecasted sales of NGLs (MMBbls)		1.0		n/a	Cash flow hedge
Octane enhancement:
Forecasted purchase of NGLs (MMBbls)		1.8		n/a	Cash flow hedge
Forecasted sales of octane enhancement products (MMBbls)		3.1		0.1	Cash flow hedge
Natural gas marketing:
Natural gas storage inventory management activities (Bcf)		3.3		n/a	Fair value hedge
NGL marketing:
Forecasted purchases of NGLs and related hydrocarbon products (MMBbls)		33.6		4.3	Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products (MMBbls)		45.0		1.7	Cash flow hedge
NGLs inventory management activities (MMBbls)		0.3		n/a	Fair value hedge
Refined products marketing:
Forecasted purchases of refined products (MMBbls)		1.0		n/a	Cash flow hedge
Forecasted sales of refined products (MMBbls)		2.0		n/a	Cash flow hedge
Refined products inventory management activities (MMBbls)		0.5		n/a	Fair value hedge
Crude oil marketing:
Forecasted purchases of crude oil (MMBbls)		18.4		1.9	Cash flow hedge
Forecasted sales of crude oil (MMBbls)		28.5		1.9	Cash flow hedge
Derivatives not designated as hedging instruments:
Natural gas risk management activities (Bcf) (3,4)		77.5		0.9	Mark-to-market
NGL risk management activities (MMBbls) (4)		3.3		n/a	Mark-to-market
Refined products risk management activities (MMBbls) (4)		2.6		n/a	Mark-to-market
Crude oil risk management activities (MMBbls) (4)		26.3		3.2	Mark-to-market

(1) Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes. (2) The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is December 2020, June 2019 and December 2020, respectively. (3) Current volume includes 29.8 Bcf of physical derivative instruments that are predominantly priced at a marked-based index plus a premium or minus a discount related to location differences. (4) Reflects the use of derivative instruments to manage risks associated with transportation, processing and storage assets.

The carrying amount of our inventories subject to fair value hedges was $50.2 million and $84.0 million at December 31, 2018 and 2017, 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, 2018			December 31, 2017			December 31, 2018			December 31, 2017
	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	$	--	Current liabilities	$	1.5
Interest rate derivatives	Other assets		--	Other assets		0.1	Other liabilities		--	Other liabilities		0.2
Total interest rate derivatives			--			0.1			--			1.7
Commodity derivatives	Current assets		138.5	Current assets		109.5	Current liabilities		115.0	Current liabilities		104.4
Commodity derivatives	Other assets		5.6	Other assets		6.4	Other liabilities		11.1	Other liabilities		6.8
Total commodity derivatives			144.1			115.9			126.1			111.2
Total derivatives designated as hedging instruments		$	144.1		$	116.0		$	126.1		$	112.9

Derivatives not designated as hedging instruments
Commodity derivatives	Current assets	$	15.9	Current assets	$	43.9	Current liabilities	$	33.2	Current liabilities	$	62.3
Commodity derivatives	Other assets		1.9	Other assets		1.9	Other liabilities		3.1	Other liabilities		3.4
Total commodity derivatives			17.8			45.8			36.3			65.7
Total derivatives not designated as hedging instruments		$	17.8		$	45.8		$	36.3		$	65.7

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, 2018:
Commodity derivatives		$	161.9		$	--		$	161.9		$	(158.6	)	$	--	$	--		$	3.3
As of December 31, 2017:
Interest rate derivatives		$	0.1		$	--		$	0.1		$	(0.1	)	$	--	$	--		$	--
Commodity derivatives			161.7			--			161.7			(157.8	)		--		--			3.9

	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, 2018:
Commodity derivatives		$	162.4		$	--		$	162.4		$	(158.6	)		$	(2.3	)		$	1.5
As of December 31, 2017:
Interest rate derivatives		$	1.7		$	--		$	1.7		$	(0.1	)		$	--			$	1.6
Commodity derivatives			176.9			--			176.9			(157.8	)			(17.3	)			1.8

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,
		2018		2017			2016
Interest rate derivatives	Interest expense	$	1.3	$	(0.2	)	$	0.3
Commodity derivatives	Revenue		9.9		1.1			(90.5	)
Total		$	11.2	$	0.9		$	(90.2	)

Derivatives in Fair Value Hedging Relationships	Location	Gain (Loss) Recognized in Income on Hedged Item
		For the Year Ended December 31,
		2018			2017		2016
Interest rate derivatives	Interest expense	$	(1.4	)	$	0.4	$	(0.4	)
Commodity derivatives	Revenue		(6.9	)		27.4		125.0
Total		$	(8.3	)	$	27.8	$	124.6

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,
	2018		2017			2016
Interest rate derivatives	$	22.2	$	(5.7	)	$	42.3
Commodity derivatives – Revenue (1)		293.0		(33.7	)		(197.4	)
Commodity derivatives – Operating costs and expenses (1)		0.2		(4.8	)		3.6
Total	$	315.4	$	(44.2	)	$	(151.5	)

(1)The fair value of these derivative instruments will be reclassified to their respective locations on the Statement of Consolidated Operations upon settlement of the underlying derivative transactions, as appropriate.

Derivatives in Cash Flow Hedging Relationships	Location	Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income
		For the Year Ended December 31,
		2018			2017			2016
Interest rate derivatives	Interest expense	$	(38.1	)	$	(40.4	)	$	(37.4	)
Commodity derivatives	Revenue		131.7			(111.6	)		(53.6	)
Commodity derivatives	Operating costs and expenses		(1.3	)		(0.6	)		0.2
Total		$	92.3		$	(152.6	)	$	(90.8	)

Over the next twelve months, we expect to reclassify $38.0 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 $168.1 million of gains attributable to commodity derivative instruments from accumulated other comprehensive income to earnings, $166.9 million as an increase in revenue and $1.2 million as a decrease to operating costs and expenses.

The following table presents the effect of our derivative instruments not designated as hedging instruments on our Statements of Consolidated Operations for the years indicated:

Derivatives Not Designated as Hedging Instruments	Location	Gain (Loss) Recognized in Income on Derivative
		For the Year Ended December 31,
		2018			2017			2016
Commodity derivatives	Revenue	$	(462.9	)	$	(42.7	)	$	(38.4	)
Commodity derivatives	Operating costs and expenses		8.2			0.1			(0.4	)
Total		$	(454.7	)	$	(42.6	)	$	(38.8	)

The $454.7 million loss recognized in 2018 from derivatives not designated as hedging instruments (as noted in the preceding table) reflects $443.8 million of realized losses and $10.9 million of net unrealized mark-to-market losses.

In the aggregate, our net unrealized mark-to-market loss for the year ended December 31, 2018 attributable to derivatives designated as fair value hedges and derivatives not designated as hedging instruments was $19.1 million. The following table summarizes the impact of this net unrealized loss on our gross operating margin by segment for the year ended December 31, 2018:

Unrealized mark-to-market gains (losses) by segment:
NGL Pipelines & Services	$	18.0
Crude Oil Pipelines & Services		(44.1	)
Natural Gas Pipelines & Services		5.3
Petrochemical & Refined Products Services		1.7
Total	$	(19.1	)

Fair Value Measurements

The following tables set forth, by level within the Level 1, 2 and 3 fair value hierarchy (see Note 2), the carrying values of our financial assets and liabilities at the dates indicated. These assets and liabilities are measured on a recurring basis and are classified based on the lowest level of input used to estimate their fair value. Our assessment of the relative significance of such inputs requires judgment.

The values for commodity derivatives 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, 2018 Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total
Financial assets:
Commodity derivatives:
Value before application of CME Rule 814	$	172.3		$	282.4		$	2.2		$	456.9
Impact of CME Rule 814 change		(134.8	)		(159.3	)		(0.9	)		(295.0	)
Total commodity derivatives		37.5			123.1			1.3			161.9
Total	$	37.5		$	123.1		$	1.3		$	161.9

Financial liabilities:
Liquidity Option Agreement (see Note 17)	$	--		$	--		$	390.0		$	390.0
Commodity derivatives:
Value before application of CME Rule 814		85.5			291.2			21.4			398.1
Impact of CME Rule 814 change		(48.6	)		(172.9	)		(14.2	)		(235.7	)
Total commodity derivatives		36.9			118.3			7.2			162.4
Total	$	36.9		$	118.3		$	397.2		$	552.4

In the aggregate, the fair value of our commodity hedging portfolios at December 31, 2018 was a net derivative asset of $58.8 million prior to the impact of CME Rule 814.

	At December 31, 2017 Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total
Financial assets:
Interest rate derivatives	$	--		$	0.1		$	--	$	0.1
Commodity derivatives:
Value before application of CME Rule 814		47.1			184.9			2.9		234.9
Impact of CME Rule 814 change		(47.1	)		(26.1	)		--		(73.2	)
Total commodity derivatives		--			158.8			2.9		161.7
Total	$	--		$	158.9		$	2.9	$	161.8

Financial liabilities:
Liquidity Option Agreement (see Note 17)	$	--		$	--		$	333.9	$	333.9
Interest rate derivatives		--			1.7			--		1.7
Commodity derivatives:
Value before application of CME Rule 814		118.4			270.6			1.7		390.7
Impact of CME Rule 814 change		(118.4	)		(95.4	)		--		(213.8	)
Total commodity derivatives		--			175.2			1.7		176.9
Total	$	--		$	176.9		$	335.6	$	512.5

The following tables provide quantitative information regarding our recurring Level 3 fair value measurements for commodity derivatives at the dates indicated:

	Fair Value At December 31, 2018
	Financial Assets		Financial Liabilities		Valuation Techniques	Unobservable Input	Range
Commodity derivatives – Crude oil	$	0.9	$	0.8	Discounted cash flow	Forward commodity prices	$37.59-$51.99/barrel
Commodity derivatives – Ethane		0.4		0.6	Discounted cash flow	Forward commodity prices	$0.28-$0.31/gallon
Commodity derivatives – Propane		--		1.0	Discounted cash flow	Forward commodity prices	$0.61-$0.66/gallon
Commodity derivatives – Normal butane		--		0.7	Discounted cash flow	Forward commodity prices	$0.66-$0.72/gallon
Commodity derivatives – Natural gasoline		--		4.1	Discounted cash flow	Forward commodity prices	$0.99-$1.01/gallon
Total	$	1.3	$	7.2

	Fair Value At December 31, 2017
	Financial Assets		Financial Liabilities		Valuation Techniques	Unobservable Input	Range
Commodity derivatives – Crude oil	$	2.9	$	1.7	Discounted cash flow	Forward commodity prices	$60.21-$66.05/barrel
Total	$	2.9	$	1.7

With respect to commodity derivatives, we believe forward commodity prices are the most significant unobservable inputs in determining our Level 3 recurring fair value measurements at December 31, 2018. In general, changes in the price of the underlying commodity increases or decreases the fair value of a commodity derivative depending on whether the derivative was purchased or sold. We generally expect changes in the fair value of our derivative instruments to be offset by corresponding changes in the fair value of our hedged exposures.

The recurring fair value measurement pertaining to the Liquidity Option Agreement is based on a number of Level 3 inputs. See Note 17 for a discussion of this liability.

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:

		For the Year Ended December 31,
	Location	2018			2017
Financial asset (liability) balance, net, January 1		$	(332.7	)	$	(268.2	)
Total gains (losses) included in:
Net income (1)	Revenue		0.7			2.3
Net income	Other expense, net – Liquidity Option Agreement		(56.1	)		(64.3	)
Other comprehensive income (loss)	Commodity derivative instruments – changes in fair value of cash flow hedges		(3.2	)		0.1
Settlements (1)	Revenue		(1.9	)		(2.4	)
Transfers out of Level 3 (2)			(2.7	)		(0.2	)
Financial liability balance, net, December 31 (2)		$	(395.9	)	$	(332.7	)

(1)There were $1.2 million and $0.1 million of unrealized losses included in these amounts for the years ended December 31, 2018 and 2017, respectively. (2)Transfers out of Level 3 into Level 2 were due to shorter remaining transaction maturities falling inside of the Level 2 range at December 31, 2018 and 2017.

Nonrecurring Fair Value Measurements

Long-lived assets (including intangible assets with finite useful lives and property, plant and equipment) are reviewed for impairment (i.e., subject to nonrecurring fair value measurements) when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Long-lived assets with carrying values that are not expected to be recovered through future cash flows are written-down to their estimated fair values. Similarly, we evaluate our equity method investments for impairment to determine whether there are events or changes in circumstances that indicate there is a loss in value of the investment attributable to an other than temporary decline. In the event we determine that the loss in value of an investment is an other than temporary decline, we record a non-cash impairment charge to equity earnings to adjust the carrying value of the investment to its estimated fair value.

The following table summarizes our non-cash asset impairment charges by segment during the years indicated:

	For the Year Ended December 31,
	2018		2017		2016
NGL Pipelines & Services	$	18.6	$	11.5	$	21.0
Crude Oil Pipelines & Services		11.2		10.2		2.3
Natural Gas Pipelines & Services		13.9		14.3		12.3
Petrochemical & Refined Products Services		3.1		1.8		9.6
Total	$	46.8	$	37.8	$	45.2

As presented in the following tables, our estimated fair values were based on management’s expectation of the market values for such assets based on their knowledge and experience in the industry (a Level 3 type measure involving significant unobservable inputs). In many cases, there are no active markets (Level 1) or other similar recent transactions (Level 2) to compare to. Our assumptions used in such analyses are based on the highest and best use of the asset and includes estimated probabilities where multiple cash flow outcomes are possible.

When probability weights are used, the weights are generally obtained from business management personnel having oversight responsibilities for the assets being tested. Key commercial assumptions (e.g., anticipated operating margins, throughput or processing volume growth rates, timing of cash flows, etc.) that represent Level 3 unobservable inputs and test results are reviewed and certified by members of senior management.

There were no impairment charges related to our equity method investments during the years ended December 31, 2018, 2017 or 2016.

The following table presents categories of long-lived assets, primarily property, plant and equipment, that were subject to non-recurring fair value measurements during the year ended December 31, 2018:

				Fair Value Measurements at the End of the Reporting Period Using
	Carrying Value at December 31, 2018			Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total Non-Cash Impairment Loss
Long-lived assets disposed of other than by sale		$	--		$	--		$	--		$	--		$	43.7
Long-lived assets held and used			--			--			--			--			3.1
Total														$	46.8

Total non-cash asset impairment and related charges during 2018 were $50.5 million, which consisted of $46.8 million of impairment charges attributable to long-lived assets and $3.7 million of impairment charges attributable to the write-down of surplus materials classified as current assets. Impairment charges attributable to long-lived assets were primarily due to the planned abandonment of certain terminal and natural gas processing plants in Texas.

			Fair Value Measurements at the End of the Reporting Period Using
	Carrying Value at December 31, 2017		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Non-Cash Impairment Loss
Long-lived assets disposed of other than by sale	$	--	$	--	$	--	$	--	$	16.7
Long-lived assets held and used		1.5		--		--		1.5		15.4
Long-lived assets held for sale		2.5		--		--		2.5		2.5
Long-lived assets disposed of by sale		--		--		--		--		3.2
Total									$	37.8

Total non-cash asset impairment and related charges during 2017 were $49.8 million, which consisted of $37.8 million of impairment charges attributable to long-lived assets and $12.0 million of impairment charges attributable to the write-down of surplus materials classified as current assets. Impairment charges attributable to long-lived assets were primarily due to the write-down of certain natural gas pipeline laterals and other pipelines in Texas, which accounted for $13.0 million in charges, and for the planned abandonment of certain storage and pipeline assets in Texas, which accounted for an additional $12.4 million in charges.

The following table presents categories of long-lived assets that were subject to non-recurring fair value measurements during the year ended December 31, 2016:

			Fair Value Measurements at the End of the Reporting Period Using
	Carrying Value at December 31, 2016		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Non-Cash Impairment Loss
Long-lived assets disposed of other than by sale	$	--	$	--	$	--	$	--	$	29.9
Long-lived assets held and used		8.0		8.0		--		--		2.2
Long-lived assets disposed of by sale		--		--		--		--		13.1
Total									$	45.2

Total non -cash asset impairment and related charges during 2016 were $53.5 million, which consisted of $45.2 million of impairment charges attributable to long-lived assets, $1.2 million of impairment charges attributable to the write-down of surplus materials classified as current assets, and $7.1 million of related charges for equipment destroyed by fire at our Pascagoula gas plant. Impairment charges attributable to long-lived assets primarily relate to the planned abandonment of certain plant and pipeline assets in Texas and New Mexico.

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 $25.97 billion and $23.47 billion at December 31, 2018 and 2017, respectively. The aggregate carrying value of these debt obligations was $26.15 billion and $21.48 billion at December 31, 2018 and 2017, respectively. These values are primarily based on quoted market prices for such debt or debt of similar terms and maturities (Level 2) and our credit standing. Changes in market rates of interest affect the fair value of our fixed-rate debt. The amounts reported for fixed-rate debt obligations exclude those amounts hedged using fixed-to-floating interest rate swaps. See “Interest Rate Hedging Activities” within this Note 14 for additional information.

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, 2018

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,
	2018		2017		2016
Revenues – related parties:
Unconsolidated affiliates	$	107.7	$	45.0	$	56.7
Costs and expenses – related parties:
EPCO and its privately held affiliates	$	1,089.6	$	1,010.9	$	963.2
Unconsolidated affiliates		447.4		223.4		253.9
Total	$	1,537.0	$	1,234.3	$	1,217.1

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

	December 31,
	2018		2017
Accounts receivable - related parties:
Unconsolidated affiliates	$	3.5	$	1.8

Accounts payable - related parties:
EPCO and its privately held affiliates	$	116.3	$	99.3
Unconsolidated affiliates		23.9		28.0
Total	$	140.2	$	127.3

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, 2018, EPCO and its privately held affiliates (including Dan Duncan LLC and certain Duncan family trusts) beneficially owned the following limited partner interests in us:

Total Number of Units	Percentage of Total Units Outstanding
697,529,483	31.9%

Of the total number of units held by EPCO and its privately held affiliates, 108,222,618 have been pledged as security under the credit facilities of EPCO and its privately held affiliates at December 31, 2018. These credit facilities contain customary and other events of default, including defaults by us and other affiliates of EPCO. An event of default, followed by a foreclosure on the pledged collateral, could ultimately result in a change in ownership of these units and affect the market price of our common units.

We and Enterprise GP are both separate legal entities apart from each other and apart from EPCO and its other affiliates, with assets and liabilities that are also separate from those of EPCO and its other affiliates. EPCO and its privately held affiliates depend on the cash distributions they receive from us and other investments to fund their other activities and to meet their debt obligations. During the years ended December 31, 2018, 2017 and 2016, we paid EPCO and its privately held affiliates cash distributions totaling $1.16 billion, $1.12 billion and $1.07 billion, respectively.

From time-to-time, EPCO and its privately held affiliates elect to purchase additional common units under our DRIP and our ATM program. During the years ended December 31, 2018, 2017 and 2016, privately held affiliates of EPCO reinvested $213 million, $100 million and $100 million, respectively, through our DRIP. In addition, during 2016, privately held affiliates of EPCO purchased common units from us under our ATM program, generating gross proceeds of $100 million. See Note 8 for additional information regarding our DRIP and ATM program.

We lease office space from affiliates of EPCO. The rental rates in these lease agreements approximate market rates.

EPCO ASA. We have no employees. All of our operating functions and general and administrative support services are provided by employees of EPCO pursuant to the ASA or by other service providers. We and our general partner are parties to the ASA. The significant terms of the ASA are as follows:

EPCO will provide selling, general and administrative services and management and operating services as may be necessary to manage and operate our businesses, properties and assets (all in accordance with prudent industry practices). EPCO will employ or otherwise retain the services of such personnel.

We are required to reimburse EPCO for its services in an amount equal to the sum of all costs and expenses incurred by EPCO which are directly or indirectly related to our business or activities (including expenses reasonably allocated to us by EPCO). In addition, we have agreed to pay all sales, use, excise, value added or similar taxes, if any, that may be applicable from time to time with respect to the services provided to us by EPCO.

§	EPCO will allow us to participate as a named insured in its overall insurance program, with the associated premiums and other costs being allocated to us. See Note 18 for additional information regarding our insurance programs.

Our operating costs and expenses include amounts paid to EPCO for the costs it incurs to operate our facilities, including the compensation of its employees. We reimburse EPCO for actual direct and indirect expenses it incurs related to the operation of our assets. Likewise, our general and administrative costs include amounts paid to EPCO for administrative services, including the compensation of its employees. In general, our reimbursement to EPCO for administrative services is either (i) on an actual basis for direct expenses it may incur on our behalf (e.g., the purchase of office supplies) or (ii) based on an allocation of such charges between the various parties to the ASA based on the estimated use of such services by each party (e.g., the allocation of legal or accounting salaries based on estimates of time spent on each entity’s business and affairs).

The following table presents our related party costs and expenses attributable to the ASA with EPCO for the years indicated:

	For the Year Ended December 31,
	2018		2017		2016
Operating costs and expenses	$	948.8	$	882.1	$	840.7
General and administrative expenses		124.2		110.4		105.3
Total costs and expenses	$	1,073.0	$	992.5	$	946.0

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 current unconsolidated affiliates:

For the years ended December 31, 2018, 2017 and 2016, we paid Seaway $163.2 million, $98.8 million and $161.2 million, respectively, for pipeline transportation and storage services in connection with our crude oil marketing activities. Revenues from Seaway were $74.4 million, $19.6 million and $36.3 million for the years ended December 31, 2018, 2017 and 2016, respectively.

§	During the year ended December 31, 2018, we purchased $157.9 million of NGLs from VESCO.

We pay Promix for the transportation, storage and fractionation of NGLs. In addition, we sell natural gas to Promix for its plant fuel requirements. Revenues from Promix were $9.5 million, $7.8 million and $7.0 million for the years ended December 31, 2018, 2017 and 2016, respectively. Expenses with Promix were $31.9 million, $27.8 million and $27.1 million for the years ended December 31, 2018, 2017 and 2016, respectively.

§	For the years ended December 31, 2018, 2017 and 2016, we paid Texas Express $57.6 million, $29.5 million and $22.8 million, respectively, for pipeline transportation services.

§	For the years ended December 31, 2018, 2017 and 2016, we paid Eagle Ford Crude Oil Pipeline $18.5 million, $42.8 million and $39.4 million, respectively, for crude oil transportation.

§	We perform management services for certain of our unconsolidated affiliates. We charged such affiliates $11.6 million, $10.6 million and $10.7 million for the years ended December 31, 2018, 2017 and 2016, respectively.

Provision for Income Taxes

12 Months Ended

Dec. 31, 2018

Provision for Income Taxes [Abstract]

Provision for Income Taxes

Note 16. Provision for Income Taxes

Publicly traded partnerships like ours are treated as corporations unless they have 90% or more in “qualifying income” (as that term is defined in the Internal Revenue Code). We satisfied this requirement in each of the years ended December 31, 2018, 2017 and 2016 and, as a result, are not subject to federal income tax. However, our partners are individually responsible for paying federal income tax on their share of our taxable income. Net earnings for financial reporting purposes may differ significantly from taxable income reportable to our unitholders as a result of differences between the tax basis and financial reporting basis of certain assets and liabilities and other factors. We do not have access to information regarding each partner’s individual tax basis in our limited partner interests.

Provision for income taxes primarily reflects our state tax obligations under the Revised Texas Franchise Tax (the “Texas Margin Tax”). Deferred income tax assets and liabilities are recognized for temporary differences between the assets and liabilities of our tax paying entities for financial reporting and tax purposes.

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

	For the Year Ended December 31,
	2018			2017			2016
Current:
Federal	$	5.3		$	0.1		$	(0.5	)
State		33.1			18.5			16.7
Foreign		0.5			1.0			0.6
Total current		38.9			19.6			16.8
Deferred:
Federal		(0.3	)		(1.8	)		1.1
State		21.7			7.9			5.2
Foreign		--			--			0.3
Total deferred		21.4			6.1			6.6
Total provision for income taxes	$	60.3		$	25.7		$	23.4

A reconciliation of the provision for income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows:

	For the Year Ended December 31,
	2018		2017			2016
Pre-Tax Net Book Income (“NBI”)	$	4,298.8	$	2,881.3		$	2,576.4

Texas Margin Tax (1)	$	54.8	$	26.4		$	22.1
State income taxes (net of federal benefit)		0.2		0.5			0.2
Federal income taxes computed by applying the federal statutory rate to NBI of corporate entities		2.1		0.1			0.8
Other permanent differences		3.2		(1.3	)		0.3
Provision for income taxes	$	60.3	$	25.7		$	23.4

Effective income tax rate		1.4%		0.9%			0.9%

(1)Although the Texas Margin Tax is not considered a state income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers our Texas-sourced revenues and expenses.

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

	December 31,
	2018		2017
Deferred tax assets:
Net operating loss carryovers (1)	$	0.1	$	0.2
Accruals		2.6		1.4
Total deferred tax assets		2.7		1.6
Less: Deferred tax liabilities:
Property, plant and equipment		80.8		58.0
Equity investment in partnerships		2.3		2.1
Total deferred tax liabilities		83.1		60.1
Total net deferred tax liabilities	$	80.4	$	58.5

(1)These losses expire in various years between 2019 and 2033 and are subject to limitations on their utilization.

Accounting guidance provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. We did not rely on any uncertain tax positions in recording our income tax-related amounts during the years ended December 31, 2018, 2017 or 2016.

Commitments and Contingencies

12 Months Ended

Dec. 31, 2018

Commitments and Contingencies [Abstract]

Commitments and Contingencies

Note 17. Commitments and Contingencies

Litigation

As part of our normal business activities, we may be named as defendants in legal proceedings, including those arising from regulatory and environmental matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to fully indemnify us against losses arising from future legal proceedings. We will vigorously defend the partnership in litigation matters.

Management has regular quarterly litigation reviews, including updates from legal counsel, to assess the possible need for accounting recognition and disclosure of these contingencies. We accrue an undiscounted liability for those contingencies where the loss is probable and the amount can be reasonably estimated. If a range of probable loss amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum amount in the range is accrued.

We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material to our consolidated financial statements, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss. Based on a consideration of all relevant known facts and circumstances, we do not believe that the ultimate outcome of any currently pending litigation directed against us will have a material impact on our consolidated financial statements either individually at the claim level or in the aggregate.

At December 31, 2018 and 2017, our accruals for litigation contingencies were $0.5 million and $4.5 million, respectively, and were recorded in our Consolidated Balance Sheets as a component of “Other current liabilities.” Our evaluation of litigation contingencies is based on the facts and circumstances of each case and predicting the outcome of these matters involves uncertainties. In the event the assumptions we use to evaluate these matters change in future periods or new information becomes available, we may be required to record additional accruals. In an effort to mitigate expenses associated with litigation, we may settle legal proceedings out of court.

Energy Transfer Matter

In connection with a proposed pipeline project, we and ETP signed a non-binding letter of intent in April 2011 that disclaimed any partnership or joint venture related to such project absent executed definitive documents and board approvals of the respective companies. Definitive agreements were never executed and board approval was never obtained for the potential pipeline project. In August 2011, the proposed pipeline project was cancelled due to a lack of customer support.

In September 2011, ETP filed suit against us and a third party in connection with the cancelled project alleging, among other things, that we and ETP had formed a “partnership.” The case was tried in the District Court of Dallas County, Texas, 298th Judicial District. While we firmly believe, and argued during our defense, that no agreement was ever executed forming a legal joint venture or partnership between the parties, the jury found that the actions of the two companies, nevertheless, constituted a legal partnership. As a result, the jury found that ETP was wrongfully excluded from a subsequent pipeline project involving a third party, and awarded ETP $319.4 million in actual damages on March 4, 2014. On July 29, 2014, the trial court entered judgment against us in an aggregate amount of $535.8 million, which included (i) $319.4 million as the amount of actual damages awarded by the jury, (ii) an additional $150.0 million in disgorgement for the alleged benefit we received due to a breach of fiduciary duties by us against ETP and (iii) prejudgment interest in the amount of $66.4 million. The trial court also awarded post-judgment interest on such aggregate amount, to accrue at a rate of 5%, compounded annually.

We filed our Brief of the Appellant in the Court of Appeals for the Fifth District of Dallas, Texas on March 30, 2015 and ETP filed its Brief of Appellees on June 29, 2015. We filed our Reply Brief of Appellant on September 18, 2015. Oral argument was conducted on April 20, 2016, and the case was then submitted to the Court of Appeals for its consideration. On July 18, 2017, a panel of the Court of Appeals issued a unanimous opinion reversing the trial court’s judgment as to all of ETP’s claims against us, rendering judgment that ETP take nothing on those claims, and affirming our counterclaim against ETP of $0.8 million, plus interest.

On August 31, 2017, ETP filed a motion for rehearing before the Dallas Court of Appeals, which was denied on September 13, 2017. On December 27, 2017, ETP filed its Petition for Review with the Supreme Court of Texas and we filed our Response to the Petition for Review on February 26, 2018. On June 8, 2018, the Supreme Court of Texas requested that the parties file briefs on the merits, and the parties have filed their respective submittals. As of December 31, 2018, we have not recorded a provision for this matter as management continues to believe that payment of damages by us in this case is not probable. We continue to monitor developments involving this matter.

PDH Litigation

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 propane dehydrogenation (“PDH”) facility. In November 2014, Foster Wheeler was acquired by an affiliate of AMEC plc to form Amec Foster Wheeler plc, and Foster Wheeler is now known as Amec Foster Wheeler USA Corporation (“AFW”). In December 2015, Enterprise and AFW entered into a transition services agreement under which AFW was partially terminated from the PDH project. In December 2015, Enterprise engaged a second contractor, Optimized Process Designs LLC, to complete the construction and installation of the PDH facility.

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, 2018, we had approximately 7.7 trillion British thermal units (“TBtus”) of natural gas, 18.4 MMBbls of crude oil, and 38.5 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 associated with 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, 2018. A description of each type of contractual obligation follows:

	Payment or Settlement due by Period
Contractual Obligations	Total		2019		2020		2021		2022		2023		Thereafter
Scheduled maturities of debt obligations	$	26,420.6	$	1,500.0	$	1,500.0	$	1,325.0	$	1,400.0	$	1,250.0	$	19,445.6
Estimated cash interest payments	$	25,520.2	$	1,190.4	$	1,132.5	$	1,062.9	$	1,010.1	$	969.9	$	20,154.4
Operating lease obligations	$	324.8	$	50.5	$	45.6	$	38.7	$	30.8	$	20.9	$	138.3
Purchase obligations:
Product purchase commitments:
Estimated payment obligations:
Natural gas	$	1,631.2	$	572.0	$	599.4	$	459.8	$	--	$	--	$	--
NGLs	$	3,437.2	$	760.6	$	739.4	$	620.3	$	527.7	$	310.3	$	478.9
Crude oil	$	4,778.2	$	1,038.6	$	771.3	$	557.1	$	543.1	$	438.1	$	1,430.0
Petrochemicals & refined products	$	399.7	$	179.0	$	178.3	$	42.4	$	--	$	--	$	--
Other	$	27.4	$	8.2	$	8.3	$	4.3	$	2.3	$	2.4	$	1.9
Service payment commitments	$	403.8	$	75.1	$	72.2	$	55.3	$	53.7	$	38.9	$	108.6
Capital expenditure commitments	$	171.8	$	171.8	$	--	$	--	$	--	$	--	$	--

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, 2018, the contractually scheduled maturities of such balances, and the applicable interest rates. Our estimated cash payments for interest are significantly influenced by the long-term maturities of our $2.67 billion in junior subordinated notes (due June 2067 through February 2078). Our estimated cash payments for interest assume that these subordinated notes are not repaid prior to their respective maturity dates. Our estimated cash payments for interest with respect to each junior subordinated note are based on either the current fixed interest rate charged or the weighted-average variable rate paid in 2018, as applicable, for each note applied to the remaining term through the respective maturity date. See Note 7 for information regarding fixed and weighted-average variable interest rates charged in 2018.

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) leased office space with affiliates of EPCO. Currently, our significant lease agreements have terms that range from 5 to 30 years. The agreements for leased office space with affiliates of EPCO and 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.

Consolidated costs and expenses include lease and rental expense amounts of $86.4 million, $103.6 million and $110.1 million during the years ended December 31, 2018, 2017 and 2016, respectively.

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: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transactions. We classify our unconditional purchase obligations into the following categories:

We have long-term product purchase obligations for natural gas, NGLs, crude oil, petrochemicals and refined products with third party suppliers. The prices that we are obligated to pay under these contracts approximate market prices at the time we take delivery of the volumes. The preceding table shows our estimated payment obligations under these contracts for the years indicated. Our estimated future payment obligations are based on the contractual price in each agreement at December 31, 2018 applied to all future volume commitments. Actual future payment obligations may vary depending on prices at the time of delivery.

We have long-term commitments to pay service providers. Our contractual service payment commitments primarily represent our obligations under firm pipeline transportation contracts. Payment obligations vary by contract, but generally represent a price per unit of volume multiplied by a firm transportation volume commitment.

We have short-term payment obligations relating to our capital investment program, including our share of the capital expenditures of unconsolidated affiliates. These commitments represent unconditional payment obligations for services to be rendered or products to be delivered in connection with capital projects.

Other Commitments

In connection with our acquisition of the EFS Midstream System in 2015, we are obligated to spend up to an aggregate of $270 million on specified midstream gathering assets for certain producers, over a ten-year period. If constructed, these new assets would be owned by us and be a component of the EFS Midstream System. As of December 31, 2018, 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,
	2018		2017
Noncurrent portion of AROs (see Note 4)	$	121.4	$	81.1
Deferred revenues – non-current portion (see Note 9)		210.3		135.5
Liquidity Option Agreement		390.0		333.9
Derivative liabilities		14.2		10.4
Centennial guarantees		3.6		4.5
Other		12.1		13.0
Total	$	751.6	$	578.4

Liquidity Option Agreement

We entered into a put option agreement (the “Liquidity Option Agreement” or “Liquidity Option”) with OTA and Marquard & Bahls AG, a German corporation and the ultimate parent company of OTA (“M&B”), in connection with the Oiltanking acquisition. Under the Liquidity Option Agreement, we granted M&B the option to sell to us 100% of the issued and outstanding capital stock of OTA at any time within a 90-day period commencing on February 1, 2020. If the Liquidity Option is exercised during this period, we would indirectly acquire the Enterprise common units then owned by OTA, currently 54,807,352 units, and assume all future income tax obligations of OTA associated with (i) owning common units encumbered by the entity-level taxes of a U.S. corporation and (ii) any associated net deferred taxes. If we assume net deferred tax liabilities that exceed the then current book value of the Liquidity Option liability at the exercise date, we will recognize expense for the difference.

The aggregate consideration to be paid by us for OTA’s capital stock would equal 100% of the then-current fair market value of the Enterprise common units owned by OTA at the exercise date. The consideration paid may be in the form of newly issued Enterprise common units, cash or any mix thereof, as determined solely by us. We have the ability to issue the requisite number of common units needed to satisfy any potential obligation under the Liquidity Option.

The Liquidity Option may be exercised prior to February 2020 if a Trigger Event (as defined in the underlying agreements) occurs. The exercise period for a Trigger Event is 135 days following the notice of such event. Trigger Events include, among other scenarios, any Enterprise Tax Event (as defined in the underlying agreements), which includes certain events in which OTA would recognize a taxable gain on the Enterprise common units that it owns.

The carrying value of the Liquidity Option Agreement, which is a component of “Other long-term liabilities” on our Consolidated Balance Sheet, was $390.0 million and $333.9 million at December 31, 2018 and 2017, respectively. The fair value of the Liquidity Option, at any measurement date, represents the present value of estimated federal and state income tax payments that we believe a market participant would incur on the future taxable income of OTA. We expect that OTA’s taxable income would, in turn, be based on an allocation of our partnership’s taxable income to the common units held by OTA and reflect certain tax planning strategies we believe could be employed.

Changes in the fair value of the Liquidity Option are recognized in earnings as a component of other income (expense) on our Statements of Consolidated Operations. Results for the years ended December 31, 2018, 2017 and 2016 include $56.1 million, $64.3 million and $24.5 million, respectively, of aggregate non-cash expense attributable to accretion and changes in management estimates regarding inputs to the valuation model.

In addition to the effects of recently enacted tax reforms, our valuation estimate for the Liquidity Option at December 31, 2018 is based on several inputs that are not readily observable in the market (i.e., Level 3 inputs) such as the following:

§	OTA remains in existence (i.e., is not dissolved and its assets sold) between one and 30 years following exercise of the Liquidity Option, depending on the liquidity preference of its owner. An equal probability that OTA will be dissolved was assigned to each year in the 30-year forecast period;

§	Forecasted annual growth rates of Enterprise’s taxable earnings before interest, taxes, depreciation and amortization ranging from 1.9% to 5.6%;

§	OTA’s ownership interest in Enterprise common units is assumed to be diluted over time in connection with Enterprise’s issuance of equity for general company reasons. For purposes of the valuation at December 31, 2018, we used ownership interests ranging from 2.3% to 2.5%;

§	OTA pays an aggregate federal and state income tax rate of 24% on its taxable income; and

§	A discount rate of 7.9% based on our weighted-average cost of capital at December 31, 2018.

Furthermore, our valuation estimate incorporates probability-weighted scenarios reflecting the likelihood that M&B may elect to divest a portion of the Enterprise common units held by OTA prior to exercise of the option (see Note 8 for information regarding the Registration Rights Agreement granted to OTA). At December 31, 2018, based on these scenarios, we expect that OTA would own approximately 94% of the 54,807,352 Enterprise common units it received in Step 1 when the option period begins in February 2020. If our valuation estimate assumed that OTA owned all of the Enterprise common units it received in Step 1 at the time of exercise (and all other inputs remained the same), the estimated fair value of the Liquidity Option liability at December 31, 2018 would increase by $23.1 million.

Centennial Guarantees

At December 31, 2018, Centennial’s debt obligations consisted of $41.8 million borrowed under a master shelf loan agreement. Borrowings under the master shelf agreement mature in May 2024 and are collateralized by substantially all of Centennial’s assets and severally guaranteed 50% by us and 50% by our joint venture partner in Centennial. If Centennial were to default on its debt obligations, we and our joint venture partner would each be required to make an approximate $20.9 million payment to Centennial’s lenders in connection with the guarantee agreements (based on Centennial’s debt principal outstanding at December 31, 2018). We recognized a liability of $3.1 million for our share of the Centennial debt guaranty at December 31, 2018.

In lieu of Centennial procuring insurance to satisfy third party claims arising from a catastrophic event, we and Centennial’s other joint venture partner have entered a limited cash call agreement. We are obligated to contribute up to a maximum of $50.0 million in the event of a catastrophic event. At December 31, 2018, we have a recorded liability of $1.3 million representing the estimated fair value of our cash call guaranty. Our cash contributions to Centennial under the agreement may be covered by our other insurance policies depending on the nature of the catastrophic event.

Significant Risks and Uncertainties	12 Months Ended
Significant Risks and Uncertainties	Dec. 31, 2018
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, petrochemical and refined products. As such, changes in the prices of hydrocarbon products and in the relative price levels among hydrocarbon products could have a material adverse effect on our financial position, results of operations and cash flows. Changes in prices may impact demand for hydrocarbon products, which in turn may impact production, demand and the volumes of products for which we provide services. In addition, decreases in demand may be caused by other factors, including prevailing economic conditions, reduced demand by consumers for the end products made with hydrocarbon products, increased competition, adverse weather conditions and government regulations affecting prices and production levels. The natural gas, NGLs and crude oil currently transported, gathered or processed at our facilities originate primarily from existing domestic resource basins, which naturally deplete over time. To offset this natural decline, our facilities need access to production from newly discovered properties. Many economic and business factors beyond our control can adversely affect the decision by producers to explore for and develop new reserves. These factors could include relatively low crude oil and natural gas prices, cost and availability of equipment and labor, regulatory changes, capital budget limitations, the lack of available capital or the probability of success in finding hydrocarbons. A decrease in exploration and development activities in the regions where our facilities and other energy logistics assets are located could result in a decrease in volumes handled by our assets, which could have a material adverse effect on our financial position, results of operations and cash flows. Even if crude oil and natural gas reserves exist in the areas served by our assets, we may not be chosen by producers in these areas to gather, transport, process, fractionate, store or otherwise handle the hydrocarbons extracted. We compete with other companies, including producers of crude oil and natural gas, for any such production on the basis of many factors, including but not limited to geographic proximity to the production, costs of connection, available capacity, rates and access to markets. Credit Risk We may incur credit risk to the extent counterparties do not fulfill their obligations to us in connection with our marketing of natural gas, NGLs, petrochemicals, refined products and crude oil and long-term contracts with minimum volume commitments or fixed demand charges. Risks of nonpayment and nonperformance by customers are a major consideration in our businesses, and our credit procedures and policies may not be adequate to sufficiently eliminate customer credit risk. Further, adverse economic conditions in our industry, such as those experienced in 2015 and 2016, increase the risk of nonpayment and nonperformance by customers, particularly customers that have sub-investment grade credit ratings or small-scale companies. We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions may utilize letters of credit, prepayments, net out agreements and guarantees. However, these procedures and policies do not fully eliminate customer credit risk. Our primary markets are located in the Gulf Coast, Southwest, Rocky Mountain, Northeast and Midwest regions of the U.S. We have a concentration of trade receivable balances due from independent and major integrated oil and gas companies and other pipelines and wholesalers. These concentrations of market areas may affect our overall credit risk in that these energy industry customers may be similarly affected by changes in economic, regulatory or other factors. In those situations where we are exposed to credit risk in our derivative instrument transactions, we analyze the counterparty’s financial condition prior to entering into an agreement, establish credit and/or margin limits and monitor the appropriateness of these limits on an ongoing basis. Generally, we do not require collateral for such transactions nor do we currently anticipate nonperformance by our material counterparties. Insurance Matters We participate as a named insured in EPCO’s insurance program, which provides us with property damage, business interruption and other insurance coverage, the scope and amounts of which we believe are customary and prudent for the nature and extent of our operations. While we believe EPCO maintains adequate insurance coverage on our behalf, insurance may not fully cover every type of damage, interruption or other loss that might occur. If we were to incur a significant loss for which we were not fully insured, it could have a material impact on our financial position, results of operations and cash flows. In addition, there may be timing differences between amounts we accrue related to property damage expense, amounts we are required to pay in connection with a loss, and amounts we subsequently receive from insurance carriers as reimbursements. Any event that materially interrupts the revenues generated by our consolidated operations, or other losses that require us to make material expenditures not reimbursed by insurance, could reduce our ability to pay distributions to our unitholders and, accordingly, adversely affect the market price of our common units. Involuntary conversions result from the loss of an asset due to some unforeseen event (e.g., destruction due to a fire). Some of these events are covered by insurance, thus resulting in a property damage insurance recovery. Amounts we receive from insurance carriers are net of any deductibles related to the covered event. We record a receivable from insurance to the extent we recognize a loss from an involuntary conversion event and the likelihood of our recovering such loss is deemed probable. To the extent that any of our insurance claim receivables are later judged not probable of recovery (e.g., due to new information), such amounts are expensed. We recognize gains on involuntary conversions when the amount received from insurance exceeds the net book value of the retired assets. In addition, we do not recognize gains related to insurance recoveries until all contingencies related to such proceeds have been resolved, that is, a non-refundable cash payment is received from the insurance carrier or we have a binding settlement agreement with the carrier that clearly states that a non-refundable payment will be made. To the extent that an asset is rebuilt, the associated expenditures are capitalized, as appropriate, on our Consolidated Balance Sheets and presented as “Capital expenditures” on our Statements of Consolidated Cash Flows. Under our current insurance program, the standalone deductible for property damage claims is $30 million. We also have business interruption protection; however, such claims must involve physical damage and have a combined loss value in excess of $30 million and the period of interruption must exceed 60 days. With respect to named windstorm claims, the maximum amount of insurance coverage available to us for any single event is $200 million, after applying the appropriate deductibles. A named windstorm is a hurricane, typhoon, tropical storm or cyclone as declared by the U.S. National Weather Service.

Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2018

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,
	2018			2017			2016
Decrease (increase) in:
Accounts receivable – trade	$	730.2		$	(1,076.2	)	$	(679.0	)
Accounts receivable – related parties		(2.3	)		(0.7	)		0.4
Inventories		121.4			194.6			(871.8	)
Prepaid and other current assets		214.4			226.0			(49.3	)
Other assets		(9.7	)		(111.0	)		(2.0	)
Increase (decrease) in:
Accounts payable – trade		18.3			66.6			(21.5	)
Accounts payable – related parties		51.4			56.0			21.0
Accrued product payables		(1,132.0	)		952.3			1,193.3
Accrued interest		37.6			17.3			(11.4	)
Other current liabilities		(70.9	)		(291.4	)		189.9
Other liabilities		57.8			(1.3	)		49.5
Net effect of changes in operating accounts	$	16.2		$	32.2		$	(180.9	)

Cash payments for interest, net of $147.9, $192.1 and $168.2 capitalized in 2018, 2017 and 2016, respectively	$	1,017.9		$	912.1		$	947.9

Cash payments for federal and state income taxes	$	15.5		$	20.9		$	18.7

We incurred liabilities for construction in progress that had not been paid at December 31, 2018, 2017 and 2016 of $567.6 million, $373.0 million and $124.3 million, respectively. Such amounts are not included under the caption “Capital expenditures” on our Statements of Consolidated Cash Flows.

Capital expenditures for the years ended December 31, 2017 and 2016 reflect the receipt of $46.1 million and $41.0 million, respectively, of CIACs from third parties.

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

	For the Year Ended December 31,
	2018		2017		2016
Cash proceeds from sale of Red River System	$	134.9	$	--	$	--
Cash proceeds from other asset sales		26.3		40.1		46.5
Total	$	161.2	$	40.1	$	46.5

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

	For the Year Ended December 31,
	2018		2017		2016
Gains attributable to sale of Red River System	$	20.6	$	--	$	--
Net gains attributable to other asset sales		8.1		10.7		2.5
Total	$	28.7	$	10.7	$	2.5

In July 2015, we purchased EFS Midstream LLC for $2.1 billion in cash, which was payable in two installments. The second and final installment of $1.0 billion was paid in July 2016.

See Note 14 for information regarding asset impairment and related charges as presented on our Statements of Consolidated Cash Flows.

Quarterly Financial Information (Unaudited)

12 Months Ended

Dec. 31, 2018

Quarterly Financial Information (Unaudited) [Abstract]

Quarterly Financial Information (Unaudited)

Note 20. Quarterly Financial Information (Unaudited)

The following table presents selected quarterly financial data for the periods indicated:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
For the Year Ended December 31, 2018:
Revenues	$	9,298.5	$	8,467.5	$	9,585.9	$	9,182.3
Operating income		1,138.5		986.4		1,643.3		1,640.4
Net income		911.5		687.2		1,334.6		1,305.2
Net income attributable to limited partners		900.7		673.8		1,313.2		1,284.7

Earnings per unit:
Basic	$	0.41	$	0.31	$	0.60	$	0.59
Diluted	$	0.41	$	0.31	$	0.60	$	0.59

For the Year Ended December 31, 2017:
Revenues	$	7,320.4	$	6,607.6	$	6,886.9	$	8,426.6
Operating income		1,031.6		938.7		879.2		1,079.4
Net income		771.0		666.0		621.3		797.3
Net income attributable to limited partners		760.7		653.7		610.9		774.0

Earnings per unit:
Basic	$	0.36	$	0.30	$	0.28	$	0.36
Diluted	$	0.36	$	0.30	$	0.28	$	0.36

The sum of our quarterly earnings per unit amounts may not equal our full year amounts due to slight rounding differences.

Condensed Consolidating Financial Information

12 Months Ended

Dec. 31, 2018

Condensed Consolidating Financial Information [Abstract]

Condensed Consolidating Financial Information

Note 21. Condensed Consolidating Financial Information

EPO conducts all of our business. Currently, we have no independent operations and no material assets outside those of EPO.

EPO has issued publicly traded debt securities. As the parent company of EPO, Enterprise Products Partners L.P. guarantees substantially all of the debt obligations of EPO. If EPO were to default on any of its guaranteed debt, Enterprise Products Partners L.P. would be responsible for full and unconditional repayment of that obligation. See Note 7 for additional information regarding our consolidated debt obligations.

There are no significant restrictions on the ability of EPO to receive funds from Enterprise Products Partners L.P.

Enterprise Products Partners L.P.

Condensed Consolidating Balance Sheet

December 31, 2018

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non- guarantor)		EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries		Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
ASSETS
Current assets:
Cash and cash equivalents and restricted cash	$	393.4	$	50.3	$	(33.6	)	$	410.1	$	--	$	--		$	410.1
Accounts receivable – trade, net		1,303.1		2,356.8		(0.8	)		3,659.1		--		--			3,659.1
Accounts receivable – related parties		141.8		1,423.7		(1,530.1	)		35.4		0.8		(32.7	)		3.5
Inventories		889.3		633.2		(0.4	)		1,522.1		--		--			1,522.1
Derivative assets		105.0		49.1		0.3			154.4		--		--			154.4
Prepaid and other current assets		166.0		155.1		(10.2	)		310.9		--		0.6			311.5
Total current assets		2,998.6		4,668.2		(1,574.8	)		6,092.0		0.8		(32.1	)		6,060.7
Property, plant and equipment, net		6,112.7		32,628.7		(3.8	)		38,737.6		--		--			38,737.6
Investments in unconsolidated affiliates		43,962.6		4,170.6		(45,518.1	)		2,615.1		24,273.6		(24,273.6	)		2,615.1
Intangible assets, net		659.2		2,963.0		(13.8	)		3,608.4		--		--			3,608.4
Goodwill		459.5		5,285.7		--			5,745.2		--		--			5,745.2
Other assets		292.1		131.9		(222.1	)		201.9		0.9		--			202.8
Total assets	$	54,484.7	$	49,848.1	$	(47,332.6	)	$	57,000.2	$	24,275.3	$	(24,305.7	)	$	56,969.8

LIABILITIES AND EQUITY
Current liabilities:
Current maturities of debt	$	1,500.0	$	0.1	$	--		$	1,500.1	$	--	$	--		$	1,500.1
Accounts payable – trade		404.0		734.3		(35.5	)		1,102.8		--		--			1,102.8
Accounts payable – related parties		1,557.3		127.5		(1,543.9	)		140.9		31.9		(32.6	)		140.2
Accrued product payables		1,574.7		1,902.3		(1.2	)		3,475.8		--		--			3,475.8
Accrued interest		395.5		0.9		(0.8	)		395.6		--		--			395.6
Derivative liabilities		86.2		61.7		0.3			148.2		--		--			148.2
Other current liabilities		87.9		326.3		(9.4	)		404.8		--		--			404.8
Total current liabilities		5,605.6		3,153.1		(1,590.5	)		7,168.2		31.9		(32.6	)		7,167.5
Long-term debt		24,663.4		14.7		--			24,678.1		--		--			24,678.1
Deferred tax liabilities		17.0		62.0		(0.9	)		78.1		--		2.3			80.4
Other long-term liabilities		65.2		518.4		(221.9	)		361.7		389.9		--			751.6
Commitments and contingencies
Equity:
Partners’ and other owners’ equity		24,133.5		46,031.8		(45,917.9	)		24,247.4		23,853.5		(24,247.4	)		23,853.5
Noncontrolling interests		--		68.1		398.6			466.7		--		(28.0	)		438.7
Total equity		24,133.5		46,099.9		(45,519.3	)		24,714.1		23,853.5		(24,275.4	)		24,292.2
Total liabilities and equity	$	54,484.7	$	49,848.1	$	(47,332.6	)	$	57,000.2	$	24,275.3	$	(24,305.7	)	$	56,969.8

Enterprise Products Partners L.P.

Condensed Consolidating Balance Sheet

December 31, 2017

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non- guarantor)		EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries		Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
ASSETS
Current assets:
Cash and cash equivalents and restricted cash	$	65.2	$	31.5	$	(26.4	)	$	70.3	$	--	$	--		$	70.3
Accounts receivable – trade, net		1,382.3		2,976.6		(0.5	)		4,358.4		--		--			4,358.4
Accounts receivable – related parties		110.3		1,182.1		(1,289.3	)		3.1		--		(1.3	)		1.8
Inventories		1,038.9		572.3		(1.4	)		1,609.8		--		--			1,609.8
Derivative assets		110.0		43.4		--			153.4		--		--			153.4
Prepaid and other current assets		136.3		189.0		(12.6	)		312.7		--		--			312.7
Total current assets		2,843.0		4,994.9		(1,330.2	)		6,507.7		--		(1.3	)		6,506.4
Property, plant and equipment, net		5,622.6		29,996.3		1.5			35,620.4		--		--			35,620.4
Investments in unconsolidated affiliates		41,616.6		4,298.0		(43,255.2	)		2,659.4		22,881.5		(22,881.5	)		2,659.4
Intangible assets, net		675.5		3,028.6		(13.8	)		3,690.3		--		--			3,690.3
Goodwill		459.5		5,285.7		--			5,745.2		--		--			5,745.2
Other assets		296.4		110.0		(211.0	)		195.4		1.0		--			196.4
Total assets	$	51,513.6	$	47,713.5	$	(44,808.7	)	$	54,418.4	$	22,882.5	$	(22,882.8	)	$	54,418.1

LIABILITIES AND EQUITY
Current liabilities:
Current maturities of debt	$	2,854.6	$	0.4	$	--		$	2,855.0	$	--	$	--		$	2,855.0
Accounts payable – trade		290.2		537.8		(26.4	)		801.6		0.1		--			801.7
Accounts payable – related parties		1,320.3		112.0		(1,305.0	)		127.3		1.3		(1.3	)		127.3
Accrued product payables		1,825.9		2,741.7		(1.3	)		4,566.3		--		--			4,566.3
Accrued interest		358.0		--		--			358.0		--		--			358.0
Derivative liabilities		115.2		53.0		--			168.2		--		--			168.2
Other current liabilities		108.9		320.1		(10.8	)		418.2		--		0.4			418.6
Total current liabilities		6,873.1		3,765.0		(1,343.5	)		9,294.6		1.4		(0.9	)		9,295.1
Long-term debt		21,699.0		14.7		--			21,713.7		--		--			21,713.7
Deferred tax liabilities		6.7		50.2		(0.5	)		56.4		--		2.1			58.5
Other long-term liabilities		60.4		396.5		(212.4	)		244.5		333.9		--			578.4
Commitments and contingencies
Equity:
Partners’ and other owners’ equity		22,874.4		43,412.0		(43,433.3	)		22,853.1		22,547.2		(22,853.1	)		22,547.2
Noncontrolling interests		--		75.1		181.0			256.1		--		(30.9	)		225.2
Total equity		22,874.4		43,487.1		(43,252.3	)		23,109.2		22,547.2		(22,884.0	)		22,772.4
Total liabilities and equity	$	51,513.6	$	47,713.5	$	(44,808.7	)	$	54,418.4	$	22,882.5	$	(22,882.8	)	$	54,418.1

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Operations

For the Year Ended December 31, 2018

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments			Consolidated Total
Revenues	$	42,946.4		$	23,756.4		$	(30,168.6	)	$	36,534.2		$	--		$	--		$	36,534.2
Costs and expenses:
Operating costs and expenses		41,718.2			19,845.2			(30,166.1	)		31,397.3			--			--			31,397.3
General and administrative costs		31.8			172.0			2.1			205.9			2.3			0.1			208.3
Total costs and expenses		41,750.0			20,017.2			(30,164.0	)		31,603.2			2.3			0.1			31,605.6
Equity in income of unconsolidated affiliates		4,148.3			587.2			(4,255.5	)		480.0			4,230.8			(4,230.8	)		480.0
Operating income		5,344.7			4,326.4			(4,260.1	)		5,411.0			4,228.5			(4,230.9	)		5,408.6
Other income (expense):
Interest expense		(1,097.1	)		(10.5	)		10.9			(1,096.7	)		--			--			(1,096.7	)
Other, net		12.1			41.8			(10.9	)		43.0			(56.1	)		--			(13.1	)
Total other expense, net		(1,085.0	)		31.3			--			(1,053.7	)		(56.1	)		--			(1,109.8	)
Income before income taxes		4,259.7			4,357.7			(4,260.1	)		4,357.3			4,172.4			(4,230.9	)		4,298.8
Provision for income taxes		(29.2	)		(29.6	)		--			(58.8	)		--			(1.5	)		(60.3	)
Net income		4,230.5			4,328.1			(4,260.1	)		4,298.5			4,172.4			(4,232.4	)		4,238.5
Net loss (income) attributable to noncontrolling interests		--			(7.6	)		(63.8	)		(71.4	)		--			5.3			(66.1	)
Net income attributable to entity	$	4,230.5		$	4,320.5		$	(4,323.9	)	$	4,227.1		$	4,172.4		$	(4,227.1	)	$	4,172.4

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Operations

For the Year Ended December 31, 2017

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments			Consolidated Total
Revenues	$	40,696.8		$	18,451.2		$	(29,906.5	)	$	29,241.5		$	--		$	--		$	29,241.5
Costs and expenses:
Operating costs and expenses		39,809.6			15,654.9			(29,907.0	)		25,557.5			--			--			25,557.5
General and administrative costs		31.4			148.0			(0.1	)		179.3			1.8			--			181.1
Total costs and expenses		39,841.0			15,802.9			(29,907.1	)		25,736.8			1.8			--			25,738.6
Equity in income of unconsolidated affiliates		2,990.1			566.8			(3,130.9	)		426.0			2,865.4			(2,865.4	)		426.0
Operating income		3,845.9			3,215.1			(3,130.3	)		3,930.7			2,863.6			(2,865.4	)		3,928.9
Other income (expense):
Interest expense		(982.5	)		(11.8	)		9.7			(984.6	)		--			--			(984.6	)
Other, net		9.2			1.8			(9.7	)		1.3			(64.3	)		--			(63.0	)
Total other expense, net		(973.3	)		(10.0	)		--			(983.3	)		(64.3	)		--			(1,047.6	)
Income before income taxes		2,872.6			3,205.1			(3,130.3	)		2,947.4			2,799.3			(2,865.4	)		2,881.3
Provision for income taxes		(12.0	)		(13.7	)		--			(25.7	)		--			--			(25.7	)
Net income		2,860.6			3,191.4			(3,130.3	)		2,921.7			2,799.3			(2,865.4	)		2,855.6
Net loss (income) attributable to noncontrolling interests		--			(6.5	)		(55.1	)		(61.6	)		--			5.3			(56.3	)
Net income attributable to entity	$	2,860.6		$	3,184.9		$	(3,185.4	)	$	2,860.1		$	2,799.3		$	(2,860.1	)	$	2,799.3

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Operations

For the Year Ended December 31, 2016

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments			Consolidated Total
Revenues	$	28,958.7		$	15,296.8		$	(21,233.2	)	$	23,022.3		$	--		$	--		$	23,022.3
Costs and expenses:
Operating costs and expenses		28,108.2			12,768.9			(21,233.6	)		19,643.5			--			--			19,643.5
General and administrative costs		22.5			135.3			--			157.8			2.3			--			160.1
Total costs and expenses		28,130.7			12,904.2			(21,233.6	)		19,801.3			2.3			--			19,803.6
Equity in income of unconsolidated affiliates		2,686.1			521.7			(2,845.8	)		362.0			2,539.9			(2,539.9	)		362.0
Operating income		3,514.1			2,914.3			(2,845.4	)		3,583.0			2,537.6			(2,539.9	)		3,580.7
Other income (expense):
Interest expense		(973.1	)		(17.3	)		7.8			(982.6	)		--			--			(982.6	)
Other, net		8.3			2.3			(7.8	)		2.8			(24.5	)		--			(21.7	)
Total other expense, net		(964.8	)		(15.0	)		--			(979.8	)		(24.5	)		--			(1,004.3	)
Income before income taxes		2,549.3			2,899.3			(2,845.4	)		2,603.2			2,513.1			(2,539.9	)		2,576.4
Provision for income taxes		(13.1	)		(8.2	)		--			(21.3	)		--			(2.1	)		(23.4	)
Net income		2,536.2			2,891.1			(2,845.4	)		2,581.9			2,513.1			(2,542.0	)		2,553.0
Net loss (income) attributable to noncontrolling interests		--			(7.4	)		(37.8	)		(45.2	)		--			5.3			(39.9	)
Net income attributable to entity	$	2,536.2		$	2,883.7		$	(2,883.2	)	$	2,536.7		$	2,513.1		$	(2,536.7	)	$	2,513.1

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Comprehensive Income

For the Year Ended December 31, 2018

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
Comprehensive income	$	4,312.6	$	4,468.5		$	(4,260.1	)	$	4,521.0		$	4,395.0	$	(4,454.9	)	$	4,461.1
Comprehensive loss (income) attributable to noncontrolling interests		--		(7.6	)		(63.8	)		(71.4	)		--		5.3			(66.1	)
Comprehensive income attributable to entity	$	4,312.6	$	4,460.9		$	(4,323.9	)	$	4,449.6		$	4,395.0	$	(4,449.6	)	$	4,395.0

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Comprehensive Income

For the Year Ended December 31, 2017

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
Comprehensive income	$	2,951.7	$	3,208.6		$	(3,130.2	)	$	3,030.1		$	2,907.6	$	(2,973.8	)	$	2,963.9
Comprehensive loss (income) attributable to noncontrolling interests		--		(6.5	)		(55.1	)		(61.6	)		--		5.3			(56.3	)
Comprehensive income attributable to entity	$	2,951.7	$	3,202.1		$	(3,185.3	)	$	2,968.5		$	2,907.6	$	(2,968.5	)	$	2,907.6

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Comprehensive Income

For the Year Ended December 31, 2016

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
Comprehensive income	$	2,544.3	$	2,822.1		$	(2,845.3	)	$	2,521.1		$	2,452.2	$	(2,481.1	)	$	2,492.2
Comprehensive loss (income) attributable to noncontrolling interests		--		(7.4	)		(37.8	)		(45.2	)		--		5.3			(39.9	)
Comprehensive income attributable to entity	$	2,544.3	$	2,814.7		$	(2,883.1	)	$	2,475.9		$	2,452.2	$	(2,475.8	)	$	2,452.3

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2018

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments			Consolidated Total
Operating activities:
Net income	$	4,230.5		$	4,328.1		$	(4,260.1	)	$	4,298.5		$	4,172.4		$	(4,232.4	)	$	4,238.5
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		279.9			1,512.1			(0.4	)		1,791.6			--			--			1,791.6
Equity in income of unconsolidated affiliates		(4,148.3	)		(587.2	)		4,255.5			(480.0	)		(4,230.8	)		4,230.8			(480.0	)
Distributions received on earnings from unconsolidated affiliates		1,248.9			263.0			(1,032.5	)		479.4			3,780.0			(3,780.0	)		479.4
Net effect of changes in operating accounts and other operating activities		3,221.5			(3,244.2	)		(2.3	)		(25.0	)		121.2			0.6			96.8
Net cash flows provided by operating activities		4,832.5			2,271.8			(1,039.8	)		6,064.5			3,842.8			(3,781.0	)		6,126.3
Investing activities:
Capital expenditures		(692.0	)		(3,476.0	)		--			(4,168.0	)		(55.2	)		--			(4,223.2	)
Cash used for business combinations, net of cash received		--			(150.6	)		--			(150.6	)		--			--			(150.6	)
Proceeds from asset sales		129.3			31.9			--			161.2			--			--			161.2
Other investing activities		(2,288.2	)		196.2			2,023.0			(69.0	)		(523.3	)		523.3			(69.0	)
Cash used in investing activities		(2,850.9	)		(3,398.5	)		2,023.0			(4,226.4	)		(578.5	)		523.3			(4,281.6	)
Financing activities:
Borrowings under debt agreements		79,588.7			11.5			(11.5	)		79,588.7			--			--			79,588.7
Repayments of debt		(77,956.7	)		(0.4	)		--			(77,957.1	)		--			--			(77,957.1	)
Cash distributions paid to partners		(3,780.0	)		(1,333.1	)		1,333.1			(3,780.0	)		(3,726.9	)		3,780.0			(3,726.9	)
Cash payments made in connection with DERs		--			--			--			--			(17.7	)		--			(17.7	)
Cash distributions paid to noncontrolling interests		--			(9.2	)		(73.4	)		(82.6	)		--			1.0			(81.6	)
Cash contributions from noncontrolling interests		--			--			238.1			238.1			--			--			238.1
Net cash proceeds from issuance of common units		--			--			--			--			538.4			--			538.4
Common units acquired in connection with buyback program		--			--			--			--			(30.8	)		--			(30.8	)
Cash contributions from owners		523.3			2,476.7			(2,476.7	)		523.3			--			(523.3	)		--
Other financing activities		(28.7	)		--			--			(28.7	)		(27.3	)		--			(56.0	)
Cash provided by (used in) financing activities		(1,653.4	)		1,145.5			(990.4	)		(1,498.3	)		(3,264.3	)		3,257.7			(1,504.9	)
Net change in cash and cash equivalents, including restricted cash		328.2			18.8			(7.2	)		339.8			--			--			339.8
Cash and cash equivalents, including restricted cash, January 1		65.2			31.5			(26.4	)		70.3			--			--			70.3
Cash and cash equivalents, including restricted cash, December 31	$	393.4		$	50.3		$	(33.6	)	$	410.1		$	--		$	--		$	410.1

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2017

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments			Consolidated Total
Operating activities:
Net income	$	2,860.6		$	3,191.4		$	(3,130.3	)	$	2,921.7		$	2,799.3		$	(2,865.4	)	$	2,855.6
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		216.6			1,427.8			(0.4	)		1,644.0			--			--			1,644.0
Equity in income of unconsolidated affiliates		(2,990.1	)		(566.8	)		3,130.9			(426.0	)		(2,865.4	)		2,865.4			(426.0	)
Distributions received on earnings from unconsolidated affiliates		1,162.8			272.7			(1,001.8	)		433.7			3,574.6			(3,574.6	)		433.7
Net effect of changes in operating accounts and other operating activities		2,812.2			(2,726.3	)		(19.1	)		66.8			93.2			(1.0	)		159.0
Net cash flows provided by operating activities		4,062.1			1,598.8			(1,020.7	)		4,640.2			3,601.7			(3,575.6	)		4,666.3
Investing activities:
Capital expenditures		(846.8	)		(2,255.0	)		--			(3,101.8	)		--			--			(3,101.8	)
Cash used for business combinations, net of cash received		(7.3	)		(191.4	)		--			(198.7	)		--			--			(198.7	)
Proceeds from asset sales		17.0			23.1			--			40.1			--			--			40.1
Other investing activities		(1,908.5	)		(28.0	)		1,910.8			(25.7	)		(1,060.5	)		1,060.5			(25.7	)
Cash used in investing activities		(2,745.6	)		(2,451.3	)		1,910.8			(3,286.1	)		(1,060.5	)		1,060.5			(3,286.1	)
Financing activities:
Borrowings under debt agreements		69,349.3			--			(34.0	)		69,315.3			--			--			69,315.3
Repayments of debt		(68,459.5	)		(0.1	)		--			(68,459.6	)		--			--			(68,459.6	)
Cash distributions paid to partners		(3,574.6	)		(1,065.3	)		1,065.3			(3,574.6	)		(3,569.9	)		3,574.6			(3,569.9	)
Cash payments made in connection with DERs		--			--			--			--			(15.1	)		--			(15.1	)
Cash distributions paid to noncontrolling interests		--			(9.6	)		(40.6	)		(50.2	)		--			1.0			(49.2	)
Cash contributions from noncontrolling interests		--			0.1			0.3			0.4			--			--			0.4
Net cash proceeds from issuance of common units		--			--			--			--			1,073.4			--			1,073.4
Cash contributions from owners		1,060.5			1,900.0			(1,900.0	)		1,060.5			--			(1,060.5	)		--
Other financing activities		6.8			--			--			6.8			(29.6	)		--			(22.8	)
Cash provided by (used in) financing activities		(1,617.5	)		825.1			(909.0	)		(1,701.4	)		(2,541.2	)		2,515.1			(1,727.5	)
Net change in cash and cash equivalents, including restricted cash		(301.0	)		(27.4	)		(18.9	)		(347.3	)		--			--			(347.3	)
Cash and cash equivalents, including restricted cash, January 1		366.2			58.9			(7.5	)		417.6			--			--			417.6
Cash and cash equivalents, including restricted cash, December 31	$	65.2		$	31.5		$	(26.4	)	$	70.3		$	--		$	--		$	70.3

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2016

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments			Consolidated Total
Operating activities:
Net income	$	2,536.2		$	2,891.1		$	(2,845.4	)	$	2,581.9		$	2,513.1		$	(2,542.0	)	$	2,553.0
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		185.4			1,367.0			(0.4	)		1,552.0			--			--			1,552.0
Equity in income of unconsolidated affiliates		(2,686.1	)		(521.7	)		2,845.8			(362.0	)		(2,539.9	)		2,539.9			(362.0	)
Distributions received on earnings from unconsolidated affiliates		1,127.3			265.9			(1,012.7	)		380.5			3,331.2			(3,331.2	)		380.5
Net effect of changes in operating accounts and other operating activities		2,448.6			(2,568.5	)		43.1			(76.8	)		18.9			1.2			(56.7	)
Net cash flows provided by operating activities		3,611.4			1,433.8			(969.6	)		4,075.6			3,323.3			(3,332.1	)		4,066.8
Investing activities:
Capital expenditures		(1,327.4	)		(1,656.7	)		--			(2,984.1	)		--			--			(2,984.1	)
Cash used for business combinations, net of cash received		--			(1,000.0	)		--			(1,000.0	)		--			--			(1,000.0	)
Proceeds from asset sales		28.8			17.7			--			46.5			--			--			46.5
Other investing activities		(2,301.9	)		(63.2	)		2,296.9			(68.2	)		(2,530.9	)		2,530.9			(68.2	)
Cash used in investing activities		(3,600.5	)		(2,702.2	)		2,296.9			(4,005.8	)		(2,530.9	)		2,530.9			(4,005.8	)
Financing activities:
Borrowings under debt agreements		62,813.9			41.8			(41.8	)		62,813.9			--			--			62,813.9
Repayments of debt		(61,672.5	)		(0.1	)		--			(61,672.6	)		--			--			(61,672.6	)
Cash distributions paid to partners		(3,331.2	)		(1,089.6	)		1,089.6			(3,331.2	)		(3,300.5	)		3,331.2			(3,300.5	)
Cash payments made in connection with DERs		--			--			--			--			(11.7	)		--			(11.7	)
Cash distributions paid to noncontrolling interests		--			(8.5	)		(39.8	)		(48.3	)		--			0.9			(47.4	)
Cash contributions from noncontrolling interests		--			20.4			--			20.4			--			--			20.4
Net cash proceeds from issuance of common units		--			--			--			--			2,542.8			--			2,542.8
Cash contributions from owners		2,530.9			2,292.2			(2,292.2	)		2,530.9			--			(2,530.9	)		--
Other financing activities		(0.2	)		--			--			(0.2	)		(23.0	)		--			(23.2	)
Cash provided by (used in) financing activities		340.9			1,256.2			(1,284.2	)		312.9			(792.4	)		801.2			321.7
Net change in cash and cash equivalents, including restricted cash		351.8			(12.2	)		43.1			382.7			--			--			382.7
Cash and cash equivalents, including restricted cash, January 1		14.4			71.1			(50.6	)		34.9			--			--			34.9
Cash and cash equivalents, including restricted cash, December 31	$	366.2		$	58.9		$	(7.5	)	$	417.6		$	--		$	--		$	417.6

Subsequent Event	12 Months Ended
Subsequent Event	Dec. 31, 2018
Subsequent Event [Abstract]
Subsequent Event	Note 22. Subsequent Event In January 2019, we announced that the Board of Enterprise GP had approved a $2.0 billion multi-year unit buyback program, which provides the partnership with an additional method to return capital to investors. The program authorizes the partnership to repurchase its common units from time to time, including through open market purchases and negotiated transactions. The timing and pace of buy backs under the program will be determined by a number of factors including (i) our financial performance and flexibility, (ii) organic growth and acquisition opportunities with higher potential returns on investment, (iii) our unit price and implied distributable cash flow yield and (iv) maintaining targeted financial leverage with a debt-to-normalized EBITDA ratio in the 3.5 times area. No time limit has been set for completion of the buyback program, and the program may be suspended or discontinued at any time. When units are repurchased, we plan to cancel such treasury units immediately upon their acquisition.

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2018

Summary of Significant Accounting Policies [Abstract]

Allowance for Doubtful Accounts

	For the Year Ended December 31,
	2018			2017			2016
Balance at beginning of period	$	12.1		$	11.3		$	12.1
Charged to costs and expenses		0.7			2.7			2.3
Deductions		(1.3	)		(1.9	)		(3.1	)
Balance at end of period	$	11.5		$	12.1		$	11.3

See “Credit Risk” in Note 18 for additional information.

Cash, Cash Equivalents and Restricted Cash

	December 31,
	2018		2017
Cash and cash equivalents	$	344.8	$	5.1
Restricted cash		65.3		65.2
Total cash, cash equivalents and restricted cash shown in the Statements of Consolidated Cash Flows	$	410.1	$	70.3

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,
	2018			2017			2016
Balance at beginning of period	$	11.6		$	11.9		$	13.0
Charged to costs and expenses		8.2			12.1			7.0
Acquisition-related additions and other		1.7			1.7			0.5
Deductions		(14.6	)		(14.1	)		(8.6	)
Balance at end of period	$	6.9		$	11.6		$	11.9

At December 31, 2018 and 2017, $3.2 million and $5.6 million, respectively, of our environmental reserves were classified as current liabilities.

Estimates

Fair Value Measurements

The characteristics of fair value amounts classified within each level of the hierarchy are described as follows:

Impairment Testing for Goodwill

See Note 6 for additional information regarding goodwill.

Impairment Testing for Long-Lived Assets

Impairment Testing for Unconsolidated Affiliates

Inventories

Property, Plant and Equipment

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

Recent Accounting Developments

Adoption of New Revenue Recognition Policies on January 1, 2018

See Note 9 regarding our new revenue disclosures.

Lease accounting standard

§	We will not reassess whether any expired or existing contracts are or contain leases or the lease classification for any existing or expired leases.

§	The impact of adopting ASC 842 will be prospective beginning January 1, 2019. We will not recast prior periods presented in our consolidated financial statements to reflect the new lease accounting guidance.

Fair value measurements

Credit losses

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2018

Summary of Significant Accounting Policies [Abstract]

Allowance for Doubtful Accounts Activity

	For the Year Ended December 31,
	2018			2017			2016
Balance at beginning of period	$	12.1		$	11.3		$	12.1
Charged to costs and expenses		0.7			2.7			2.3
Deductions		(1.3	)		(1.9	)		(3.1	)
Balance at end of period	$	11.5		$	12.1		$	11.3

Cash, Cash Equivalents and Restricted Cash

	December 31,
	2018		2017
Cash and cash equivalents	$	344.8	$	5.1
Restricted cash		65.3		65.2
Total cash, cash equivalents and restricted cash shown in the Statements of Consolidated Cash Flows	$	410.1	$	70.3

Environmental Reserves Activity

	For the Year Ended December 31,
	2018			2017			2016
Balance at beginning of period	$	11.6		$	11.9		$	13.0
Charged to costs and expenses		8.2			12.1			7.0
Acquisition-related additions and other		1.7			1.7			0.5
Deductions		(14.6	)		(14.1	)		(8.6	)
Balance at end of period	$	6.9		$	11.6		$	11.9

Inventories (Tables)

12 Months Ended

Dec. 31, 2018

Inventories [Abstract]

Inventory Amounts by Product Type

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

	December 31,
	2018		2017
NGLs	$	647.7	$	917.4
Petrochemicals and refined products		264.7		161.5
Crude oil		593.4		516.3
Natural gas		16.3		14.6
Total	$	1,522.1	$	1,609.8

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,
	2018		2017		2016
Cost of sales (1)	$	26,789.8	$	21,487.0	$	15,710.9
Lower of cost or net realizable value adjustments within cost of sales		11.5		9.1		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, 2018

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	2018		2017
Plants, pipelines and facilities (1)	3-45 (5)	$	42,371.0	$	37,132.2
Underground and other storage facilities (2)	5-40 (6)		3,624.2		3,460.9
Transportation equipment (3)	3-10		187.1		177.1
Marine vessels (4)	15-30		828.6		803.8
Land			359.5		273.1
Construction in progress			3,526.8		4,698.1
Total			50,897.2		46,545.2
Less accumulated depreciation			12,159.6		10,924.8
Property, plant and equipment, net		$	38,737.6	$	35,620.4

(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. We placed a number of growth projects into service since December 31, 2017 including a propane dehydrogenation facility at our Mont Belvieu complex, the first two processing trains at our Orla natural gas processing facility, and a ninth NGL fractionator in Chambers County, Texas at our Mont Belvieu NGL fractionation complex. (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,
	2018		2017		2016
Depreciation expense (1)	$	1,436.2	$	1,296.1	$	1,215.7
Capitalized interest (2)		147.9		192.1		168.2
(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,
	2018			2017			2016
ARO liability beginning balance	$	86.7		$	85.4		$	58.5
Liabilities incurred		24.4			4.7			4.2
Liabilities settled		(2.5	)		(2.2	)		(5.7	)
Revisions in estimated cash flows		11.5			(6.7	)		24.6
Accretion expense		6.2			5.5			3.8
ARO liability ending balance	$	126.3		$	86.7		$	85.4

Forecasted Accretion Expense Associated with AROs

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

2019				2020				2021				2022				2023
$	8.1			$	8.6			$	9.0			$	9.6			$	10.3

Investments in Unconsolidated Affiliates (Tables)

12 Months Ended

Dec. 31, 2018

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,
	2018	2018		2017
NGL Pipelines & Services:
Venice Energy Service Company, L.L.C. (“VESCO”)	13.1%	$	24.1	$	25.7
K/D/S Promix, L.L.C. (“Promix”)	50%		28.9		30.9
Baton Rouge Fractionators LLC (“BRF”)	32.2%		16.3		17.0
Skelly-Belvieu Pipeline Company, L.L.C. (“Skelly-Belvieu”)	50%		35.6		37.0
Texas Express Pipeline LLC (“Texas Express”)	35%		337.6		314.4
Texas Express Gathering LLC (“TEG”)	45%		43.6		35.9
Front Range Pipeline LLC (“Front Range”)	33.3%		175.9		165.7
Delaware Basin Gas Processing LLC (“Delaware Processing”) (1)	100%		--		107.3
Crude Oil Pipelines & Services:
Seaway Crude Pipeline Company LLC (“Seaway”)	50%		1,369.7		1,378.9
Eagle Ford Pipeline LLC (“Eagle Ford Crude Oil Pipeline”)	50%		388.7		385.2
Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Corpus Christi”)	50%		109.1		75.1
Natural Gas Pipelines & Services:
White River Hub, LLC (“White River Hub”)	50%		20.1		20.8
Old Ocean Pipeline, LLC (“Old Ocean”)	50%		2.7		--
Petrochemical & Refined Products Services:
Centennial Pipeline LLC (“Centennial”)	50%		59.1		60.8
Baton Rouge Propylene Concentrator LLC (“BRPC”)	30%		3.2		4.1
Transport 4, LLC (“Transport 4”)	25%		0.5		0.6
Total		$	2,615.1	$	2,659.4

(1)In March 2018, we acquired the remaining 50% membership interest in our Delaware Processing joint venture. See Note 12 for information regarding this acquisition.

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,
	2018			2017			2016
NGL Pipelines & Services	$	117.0		$	73.4		$	61.4
Crude Oil Pipelines & Services		365.4			358.4			311.9
Natural Gas Pipelines & Services		6.8			3.8			3.8
Petrochemical & Refined Products Services (1)		(9.2	)		(9.6	)		(15.1	)
Total	$	480.0		$	426.0		$	362.0

(1)Losses are primarily attributable to our investment in Centennial. As a result of a trend in declining earnings, we estimated the fair value of this equity-method investment during each of the last three fiscal years. Our estimates, based on a combination of market and income approaches, indicate that the fair value of this investment remains in excess of its carrying value.

	December 31,
	2018		2017
NGL Pipelines & Services	$	21.7	$	22.9
Crude Oil Pipelines & Services		17.4		18.2
Petrochemical & Refined Products Services		1.7		1.8
Total	$	40.8	$	42.9

Summarized Combined Financial Information of Unconsolidated Affiliates

	December 31,
	2018		2017
Balance Sheet Data:
Current assets	$	350.2	$	288.8
Property, plant and equipment, net		5,359.1		5,509.7
Other assets		80.4		71.2
Total assets	$	5,789.7	$	5,869.7

Current liabilities	$	220.6	$	233.5
Other liabilities		77.9		84.8
Combined equity		5,491.2		5,551.4
Total liabilities and combined equity	$	5,789.7	$	5,869.7

	For the Year Ended December 31,
	2018		2017		2016
Income Statement Data:
Revenues	$	1,721.3	$	1,509.0	$	1,342.0
Operating income		1,074.6		925.9		786.7
Net income		1,069.1		929.5		781.7

Intangible Assets and Goodwill (Tables)

12 Months Ended

Dec. 31, 2018

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, 2018							December 31, 2017
	Gross Value		Accumulated Amortization			Carrying Value		Gross Value		Accumulated Amortization			Carrying Value
NGL Pipelines & Services:
Customer relationship intangibles	$	457.3	$	(201.9	)	$	255.4	$	447.4	$	(187.5	)	$	259.9
Contract-based intangibles		363.4		(238.7	)		124.7		280.8		(218.4	)		62.4
Segment total		820.7		(440.6	)		380.1		728.2		(405.9	)		322.3
Crude Oil Pipelines & Services:
Customer relationship intangibles		2,203.5		(174.1	)		2,029.4		2,203.5		(127.0	)		2,076.5
Contract-based intangibles		276.9		(211.7	)		65.2		281.0		(171.0	)		110.0
Segment total		2,480.4		(385.8	)		2,094.6		2,484.5		(298.0	)		2,186.5
Natural Gas Pipelines & Services:
Customer relationship intangibles		1,350.3		(447.8	)		902.5		1,350.3		(417.1	)		933.2
Contract-based intangibles		464.7		(387.9	)		76.8		464.7		(379.5	)		85.2
Segment total		1,815.0		(835.7	)		979.3		1,815.0		(796.6	)		1,018.4
Petrochemical & Refined Products Services:
Customer relationship intangibles		181.4		(51.8	)		129.6		181.4		(45.9	)		135.5
Contract-based intangibles		46.0		(21.2	)		24.8		46.0		(18.4	)		27.6
Segment total		227.4		(73.0	)		154.4		227.4		(64.3	)		163.1
Total intangible assets	$	5,343.5	$	(1,735.1	)	$	3,608.4	$	5,255.1	$	(1,564.8	)	$	3,690.3

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,
	2018		2017		2016
NGL Pipelines & Services	$	34.7	$	28.9	$	30.6
Crude Oil Pipelines & Services		87.8		92.5		98.4
Natural Gas Pipelines & Services		39.1		36.2		33.2
Petrochemical & Refined Products Services		8.7		9.3		9.1
Total	$	170.3	$	166.9	$	171.3

Forecasted Amortization Expense

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

2019				2020				2021				2022				2023
$	167.1			$	159.8			$	162.1			$	167.6			$	167.8

Significant Acquired Intangible Assets

At December 31, 2018, the carrying value of our portfolio of customer relationship intangible assets was $3.3 billion, the principal components of which were as follows:

	Weighted Average Remaining Amortization Period	December 31, 2018
	Weighted Average Remaining Amortization Period	Gross Value		Accumulated Amortization			Carrying Value
Basin-specific customer relationships:
EFS Midstream	23.4 years	$	1,409.8	$	(117.0	)	$	1,292.8
State Line and Fairplay	28.2 years		895.0		(183.2	)		711.8
San Juan Gathering	20.8 years		331.3		(227.7	)		103.6
Encinal	8.0 years		132.9		(103.5	)		29.4
General customer relationships:
Oiltanking	25.0 years		1,192.5		(86.1	)		1,106.4

	Weighted Average Remaining Amortization Period	December 31, 2018
	Weighted Average Remaining Amortization Period	Gross Value		Accumulated Amortization			Carrying Value
Oiltanking customer contracts	4.0 years	$	293.3	$	(221.1	)	$	72.2
Jonah natural gas gathering agreements	23.0 years		224.4		(166.3	)		58.1
Delaware Basin natural gas processing contracts	8.0 years		82.6		(6.4	)		76.2

Debt Obligations (Tables)

12 Months Ended

Dec. 31, 2018

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,
	2018			2017
EPO senior debt obligations:
Commercial Paper Notes, variable-rates	$	--		$	1,755.7
Senior Notes V, 6.65% fixed-rate, due April 2018		--			349.7
Senior Notes OO, 1.65% fixed-rate, due May 2018		--			750.0
Senior Notes N, 6.50% fixed-rate, due January 2019		700.0			700.0
364-Day Revolving Credit Agreement, variable-rate, due September 2019		--			--
Senior Notes LL, 2.55% fixed-rate, due October 2019		800.0			800.0
Senior Notes Q, 5.25% fixed-rate, due January 2020		500.0			500.0
Senior Notes Y, 5.20% fixed-rate, due September 2020		1,000.0			1,000.0
Senior Notes TT, 2.80% fixed-rate, due February 2021		750.0			--
Senior Notes RR, 2.85% fixed-rate, due April 2021		575.0			575.0
Senior Notes VV, 3.50% fixed-rate, due February 2022		750.0			--
Senior Notes CC, 4.05% fixed-rate, due February 2022		650.0			650.0
Multi-Year Revolving Credit Facility, variable-rate, due September 2022		--			--
Senior Notes HH, 3.35% fixed-rate, due March 2023		1,250.0			1,250.0
Senior Notes JJ, 3.90% fixed-rate, due February 2024		850.0			850.0
Senior Notes MM, 3.75% fixed-rate, due February 2025		1,150.0			1,150.0
Senior Notes PP, 3.70% fixed-rate, due February 2026		875.0			875.0
Senior Notes SS, 3.95% fixed-rate, due February 2027		575.0			575.0
Senior Notes WW, 4.15% fixed-rate, due October 2028		1,000.0			--
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			--
Senior Notes XX, 4.80% fixed-rate, due February 2049		1,250.0			--
Senior Notes NN, 4.95% fixed-rate, due October 2054		400.0			400.0
TEPPCO senior debt obligations:
TEPPCO Senior Notes, 6.65% fixed-rate, due April 2018		--			0.3
TEPPCO Senior Notes, 7.55% fixed-rate, due April 2038		0.4			0.4
Total principal amount of senior debt obligations		23,750.0			21,605.7
EPO Junior Subordinated Notes A, variable-rate, redeemed August 2018		--			521.1
EPO Junior Subordinated Notes B, fixed/variable-rate, redeemed March 2018		--			682.7
EPO Junior Subordinated Notes C, fixed/variable-rate, due June 2067 (1)		256.4			256.4
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			--
TEPPCO Junior Subordinated Notes, fixed/variable-rate, due June 2067		14.2			14.2
Total principal amount of senior and junior debt obligations		26,420.6			24,780.1
Other, non-principal amounts		(242.4	)		(211.4	)
Less current maturities of debt		(1,500.1	)		(2,855.0	)
Total long-term debt	$	$ 24,678.1		$	$ 21,713.7

(1)Variable rate is reset quarterly and based on 3-month 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, 2018:

	Range of Interest Rates Paid	Weighted-Average Interest Rate Paid
Commercial Paper Notes	1.50% to 2.50%	2.24%
Multi-Year Revolving Credit Facility	2.58% to 5.00%	3.37%
EPO Junior Subordinated Notes A (prior to redemption)	5.08% to 6.07%	5.71%
EPO Junior Subordinated Notes B (prior to redemption)	7.03%	7.03%
EPO Junior Subordinated Notes C	4.26% to 5.52%	4.91%

Consolidated Debt Maturities

The following table presents contractually scheduled maturities of our consolidated debt obligations outstanding at December 31, 2018 for the next five years, and in total thereafter:

				Scheduled Maturities of Debt
	Total			2019			2020			2021			2022			2023			Thereafter
Senior Notes		$	23,750.0		$	1,500.0		$	1,500.0		$	1,325.0		$	1,400.0		$	1,250.0		$	16,775.0
Junior Subordinated Notes			2,670.6			--			--			--			--			--			2,670.6
Total		$	26,420.6		$	1,500.0		$	1,500.0		$	1,325.0		$	1,400.0		$	1,250.0		$	19,445.6

Summary of Changes in Outstanding Units

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)
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Reference 2: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
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-URI http://asc.fasb.org/extlink&oid=114775744&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))
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Reference 5: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
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Reference 6: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 7: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
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Reference 8: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
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-URI http://asc.fasb.org/extlink&oid=75038535&loc=d3e64711-112823

Reference 9: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 55
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=114775985&loc=d3e28878-108400

Reference 10: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=109259400&loc=d3e21475-112644

+ Details

Equity and Distributions (Tables)

12 Months Ended

Dec. 31, 2018

Equity and Distributions [Abstract]

	Common Units (Unrestricted)			Restricted Common Units			Total Common Units
Number of units outstanding at January 1, 2016		2,010,592,504			1,960,520			2,012,553,024
Common units issued in connection with ATM program		87,867,037			--			87,867,037
Common units issued in connection with DRIP and EUPP		16,316,534			--			16,316,534
Common units issued in connection with the vesting of phantom unit awards		1,761,455			--			1,761,455
Common units issued in connection with the vesting of restricted common unit awards		1,234,502			(1,234,502	)		--
Forfeiture of restricted common unit awards		--			(43,724	)		(43,724	)
Cancellation of treasury units acquired in connection with the vesting of equity-based awards		(1,000,619	)		--			(1,000,619	)
Other		134,707			--			134,707
Number of units outstanding at December 31, 2016		2,116,906,120			682,294			2,117,588,414
Common units issued in connection with ATM program		21,807,726			--			21,807,726
Common units issued in connection with DRIP and EUPP		19,046,019			--			19,046,019
Common units issued in connection with the vesting of phantom unit awards		2,485,580			--			2,485,580
Common units issued in connection with the vesting of restricted common unit awards		681,044			(681,044	)		--
Forfeiture of restricted common unit awards		--			(1,250	)		(1,250	)
Cancellation of treasury units acquired in connection with the vesting of equity-based awards		(1,027,798	)		--			(1,027,798	)
Common units issued in connection with employee compensation		1,176,103			--			1,176,103
Other		14,685			--			14,685
Number of units outstanding at December 31, 2017		2,161,089,479			--			2,161,089,479
Common units issued in connection with DRIP and EUPP		19,861,951			--			19,861,951
Common units issued in connection with the vesting of phantom unit awards		3,479,958			--			3,479,958
Cancellation of treasury units acquired in connection with the vesting of equity-based awards		(1,037,522	)		--			(1,037,522	)
Common units issued in connection with employee compensation		1,443,586			--			1,443,586
Common units issued in connection with land acquisition (see Note 4)		1,223,242			--			1,223,242
Cancellation of treasury units acquired in connection with buyback program		(1,236,800	)		--			(1,236,800	)
Other		45,135			--			45,135
Number of units outstanding at December 31, 2018		2,184,869,029			--			2,184,869,029

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), January 1, 2017	$	(83.8	)	$	(199.8	)	$	3.6		$	(280.0	)
Other comprehensive income (loss) for period, before reclassifications		(38.5	)		(5.7	)		(0.1	)		(44.3	)
Reclassification of losses (gains) to net income during period		112.2			40.4			--			152.6
Total other comprehensive income (loss) for period		73.7			34.7			(0.1	)		108.3
Accumulated Other Comprehensive Income (Loss), December 31, 2017		(10.1	)		(165.1	)		3.5			(171.7	)
Other comprehensive income (loss) for period, before reclassifications		293.2			22.2			(0.5	)		314.9
Reclassification of losses (gains) to net income during period		(130.4	)		38.1			--			(92.3	)
Total other comprehensive income (loss) for period		162.8			60.3			(0.5	)		222.6
Accumulated Other Comprehensive Income (Loss), December 31, 2018	$	152.7		$	(104.8	)	$	3.0		$	50.9

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,
	Location	2018			2017
Losses (gains) on cash flow hedges:
Interest rate derivatives	Interest expense	$	38.1		$	40.4
Commodity derivatives	Revenue		(131.7	)		111.6
Commodity derivatives	Operating costs and expenses		1.3			0.6
Total		$	(92.3	)	$	152.6

Declared Quarterly Cash Distribution Rates

	Distribution Per Common Unit		Record Date	Payment Date
2016:
1st Quarter	$	0.3950	4/29/2016	5/6/2016
2nd Quarter	$	0.4000	7/29/2016	8/5/2016
3rd Quarter	$	0.4050	10/31/2016	11/7/2016
4th Quarter	$	0.4100	1/31/2017	2/7/2017
2017:
1st Quarter	$	0.4150	4/28/2017	5/8/2017
2nd Quarter	$	0.4200	7/31/2017	8/7/2017
3rd Quarter	$	0.4225	10/31/2017	11/7/2017
4th Quarter	$	0.4250	1/31/2018	2/7/2018
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

Revenues (Tables)

12 Months Ended

Dec. 31, 2018

Revenues [Abstract]

Revenues by Business Segment and Revenue Type

	For the Year Ended December 31,
	2018 (1)		2017 (2)		2016 (2)
NGL Pipelines & Services:
Sales of NGLs and related products	$	12,920.9	$	10,521.3	$	8,380.5
Segment midstream services:
Natural gas processing and fractionation		1,341.0		719.1		714.6
Transportation		1,007.0		891.7		885.6
Storage and terminals		380.0		335.9		261.8
Total segment midstream services		2,728.0		1,946.7		1,862.0
Total NGL Pipelines & Services		15,648.9		12,468.0		10,242.5
Crude Oil Pipelines & Services:
Sales of crude oil		10,001.2		7,365.2		5,802.5
Segment midstream services:
Transportation		676.5		473.9		411.1
Storage and terminals		364.9		317.7		301.4
Total segment midstream services		1,041.4		791.6		712.5
Total Crude Oil Pipelines & Services		11,042.6		8,156.8		6,515.0
Natural Gas Pipelines & Services:
Sales of natural gas		2,411.7		2,238.5		1,591.9
Segment midstream services:
Transportation		1,042.7		907.1		951.1
Total segment midstream services		1,042.7		907.1		951.1
Total Natural Gas Pipelines & Services		3,454.4		3,145.6		2,543.0
Petrochemical & Refined Products Services:
Sales of petrochemicals and refined products		5,535.4		4,696.3		2,921.9
Segment midstream services:
Fractionation and isomerization		188.3		156.3		142.6
Transportation, including marine logistics		481.8		430.7		456.2
Storage and terminals		182.8		187.8		201.1
Total segment midstream services		852.9		774.8		799.9
Total Petrochemical & Refined Products Services		6,388.3		5,471.1		3,721.8
Total consolidated revenues	$	36,534.2	$	29,241.5	$	23,022.3

(1) Revenues are accounted for under ASC 606 upon implementation at January 1, 2018. (2) Revenues are accounted for under ASC 605 for historical periods prior to January 1, 2018.

Unbilled Revenue and Deferred Revenue

The following table provides information regarding our contract assets and contract liabilities at December 31, 2018:

Contract Asset	Location	Balance
Unbilled revenue (current amount)	Prepaid and other current assets	$	13.3
Total		$	13.3

Contract Liability	Location	Balance
Deferred revenue (current amount)	Other current liabilities	$	80.9
Deferred revenue (noncurrent)	Other long-term liabilities		210.3
Total		$	291.2

The following table presents significant changes in our unbilled revenue and deferred revenue balances during the year ended December 31, 2018:

	Unbilled Revenue			Deferred Revenue
Balance at January 1, 2018 (upon adoption of ASC 606)	$	--		$	224.7
Amount included in opening balance transferred to other accounts during period (1)		--			(90.8	)
Amount recorded during period		321.7			432.5
Amounts recorded during period transferred to other accounts (1)		(310.6	)		(274.8	)
Amount recorded in connection with business combination		2.2			--
Other changes		--			(0.4	)
Balance at December 31, 2018	$	13.3		$	291.2

(1)Unbilled revenues are transferred to accounts receivable once we have an unconditional right to consideration from the customer. Deferred revenues are recognized as revenue upon satisfaction of our performance obligation to the customer.

Remaining Performance Obligations

2019				2020				2021				2022				2023				Thereafter				Total
$	3,530.6			$	3,187.3			$	2,641.4			$	2,145.0			$	1,798.7			$	7,289.9			$	20,592.9

Impact of Change in Accounting Policy

Consolidated Balance Sheet Information at December 31, 2018

	Impact of change in accounting policy
	Balances without adoption of ASC 606		Impact of adoption of ASC 606			As Reported
Assets
Accounts receivable – trade, net	$	3,672.4	$	(13.3	)	$	3,659.1
Prepaid and other current assets		298.2		13.3			311.5
Property, plant and equipment, net		38,639.3		98.3			38,737.6
Liabilities and Equity
Other current liabilities		404.3		0.5			404.8
Other long-term liabilities		664.8		86.8			751.6
Partners' equity		23,842.5		11.0			23,853.5

Consolidated Statement of Operations Information for the Year Ended December 31, 2018

	Impact of change in accounting policy
	Balances without adoption of ASC 606		Impact of adoption of ASC 606		As Reported
Revenues	$	35,901.5	$	632.7	$	36,534.2
Costs and expenses:
Operating costs and expenses:		30,775.6		621.7		31,397.3

Consolidated Statement of Cash Flows Information for the Year Ended December 31, 2018

	Impact of change in accounting policy
	Balances without adoption of ASC 606			Impact of adoption of ASC 606			As Reported
Operating activities:
Net income	$	4,227.5		$	11.0		$	4,238.5
Net effect of changes in operating accounts		(71.1	)		87.3			16.2
Investing activities:
Contributions in aid of construction costs		87.3			(87.3	)		--

Business Segments (Tables)

12 Months Ended

Dec. 31, 2018

Business Segments [Abstract]

Measurement of Total Segment Gross Operating Margin

	For the Year Ended December 31,
	2018			2017			2016
Operating income	$	5,408.6		$	3,928.9		$	3,580.7
Adjustments to reconcile operating income to total gross operating margin:
Add depreciation, amortization and accretion expense in operating costs and expenses		1,687.0			1,531.3			1,456.7
Add asset impairment and related charges in operating costs and expenses		50.5			49.8			52.8
Subtract net gains attributable to asset sales in operating costs and expenses		(28.7	)		(10.7	)		(2.5	)
Add general and administrative costs		208.3			181.1			160.1
Adjustments for make-up rights on certain new pipeline projects:
Add non-refundable payments received from shippers attributable to make-up rights (1)		21.5			24.1			17.5
Subtract the subsequent recognition of revenues attributable to make-up rights (2)		(56.2	)		(29.9	)		(34.6	)
Total segment gross operating margin	$	7,291.0		$	5,674.6		$	5,230.7

(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,
	2018		2017		2016
Gross operating margin by segment:
NGL Pipelines & Services	$	3,830.7	$	3,258.3	$	2,990.6
Crude Oil Pipelines & Services		1,511.3		987.2		854.6
Natural Gas Pipelines & Services		891.2		714.5		734.9
Petrochemical & Refined Products Services		1,057.8		714.6		650.6
Total segment gross operating margin	$	7,291.0	$	5,674.6	$	5,230.7

Information by business segment, together with reconciliations to amounts presented on our Statements of Consolidated Operations, is presented in the following table:

	Reportable Business Segments
	NGL Pipelines & Services		Crude Oil Pipelines & Services		Natural Gas Pipelines & Services		Petrochemical & Refined Products Services			Adjustments and Eliminations			Consolidated Total
Revenues from third parties:
Year ended December 31, 2018	$	15,630.5	$	10,968.2	$	3,439.5	$	6,388.3		$	--		$	36,426.5
Year ended December 31, 2017		12,455.7		8,137.2		3,132.5		5,471.1			--			29,196.5
Year ended December 31, 2016		10,232.7		6,478.7		2,532.4		3,721.8			--			22,965.6
Revenues from related parties:
Year ended December 31, 2018		18.4		74.4		14.9		--			--			107.7
Year ended December 31, 2017		12.3		19.6		13.1		--			--			45.0
Year ended December 31, 2016		9.8		36.3		10.6		--			--			56.7
Intersegment and intrasegment revenues:
Year ended December 31, 2018		26,453.6		35,490.4		721.9		2,917.5			(65,583.4	)		--
Year ended December 31, 2017		27,278.6		15,943.0		850.8		1,766.9			(45,839.3	)		--
Year ended December 31, 2016		19,150.0		9,052.0		668.5		1,234.8			(30,105.3	)		--
Total revenues:
Year ended December 31, 2018		42,102.5		46,533.0		4,176.3		9,305.8			(65,583.4	)		36,534.2
Year ended December 31, 2017		39,746.6		24,099.8		3,996.4		7,238.0			(45,839.3	)		29,241.5
Year ended December 31, 2016		29,392.5		15,567.0		3,211.5		4,956.6			(30,105.3	)		23,022.3
Equity in income (loss) of unconsolidated affiliates:
Year ended December 31, 2018		117.0		365.4		6.8		(9.2	)		--			480.0
Year ended December 31, 2017		73.4		358.4		3.8		(9.6	)		--			426.0
Year ended December 31, 2016		61.4		311.9		3.8		(15.1	)		--			362.0

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, 2018	$	14,845.4	$	5,847.7	$	8,303.8	$	6,213.9	$	3,526.8	$	38,737.6
At December 31, 2017		13,831.2		5,208.4		8,375.0		3,507.7		4,698.1		35,620.4
At December 31, 2016		14,091.5		4,216.1		8,403.0		3,261.2		3,320.7		33,292.5
Investments in unconsolidated affiliates: (see Note 5)
At December 31, 2018		662.0		1,867.5		22.8		62.8		--		2,615.1
At December 31, 2017		733.9		1,839.2		20.8		65.5		--		2,659.4
At December 31, 2016		750.4		1,824.6		21.7		80.6		--		2,677.3
Intangible assets, net: (see Note 6)
At December 31, 2018		380.1		2,094.6		979.3		154.4		--		3,608.4
At December 31, 2017		322.3		2,186.5		1,018.4		163.1		--		3,690.3
At December 31, 2016		350.2		2,279.0		1,054.5		180.4		--		3,864.1
Goodwill: (see Note 6)
At December 31, 2018		2,651.7		1,841.0		296.3		956.2		--		5,745.2
At December 31, 2017		2,651.7		1,841.0		296.3		956.2		--		5,745.2
At December 31, 2016		2,651.7		1,841.0		296.3		956.2		--		5,745.2
Segment assets:
At December 31, 2018		18,539.2		11,650.8		9,602.2		7,387.3		3,526.8		50,706.3
At December 31, 2017		17,539.1		11,075.1		9,710.5		4,692.5		4,698.1		47,715.3
At December 31, 2016		17,843.8		10,160.7		9,775.5		4,478.4		3,320.7		45,579.1

Consolidated Revenues and Expenses

Other Revenue and Expense Information

The following table presents supplemental information regarding our consolidated revenues and costs and expenses for the years indicated:

	For the Year Ended December 31,
	2018			2017			2016
Consolidated revenues:
NGL Pipelines & Services	$	15,648.9		$	12,468.0		$	10,242.5
Crude Oil Pipelines & Services		11,042.6			8,156.8			6,515.0
Natural Gas Pipelines & Services		3,454.4			3,145.6			2,543.0
Petrochemical & Refined Products Services		6,388.3			5,471.1			3,721.8
Total consolidated revenues	$	36,534.2		$	29,241.5		$	23,022.3

Consolidated costs and expenses:
Operating costs and expenses:
Cost of sales	$	26,789.8		$	21,487.0		$	15,710.9
Other operating costs and expenses (1)		2,898.7			2,500.1			2,425.6
Depreciation, amortization and accretion		1,687.0			1,531.3			1,456.7
Asset impairment and related charges		50.5			49.8			52.8
Net gains attributable to asset sales		(28.7	)		(10.7	)		(2.5	)
General and administrative costs		208.3			181.1			160.1
Total consolidated costs and expenses	$	31,605.6		$	25,738.6		$	19,803.6

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

Earnings Per Unit (Tables)

12 Months Ended

Dec. 31, 2018

Earnings Per Unit [Abstract]

Basic and Diluted Earnings Per Unit

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

	For the Year Ended December 31,
	2018			2017			2016
BASIC EARNINGS PER UNIT
Net income attributable to limited partners	$	4,172.4		$	2,799.3		$	2,513.1
Undistributed earnings allocated and cash payments on phantom unit awards (1)		(21.5	)		(15.9	)		(12.9	)
Net income available to common unitholders	$	4,150.9		$	2,783.4		$	2,500.2

Basic weighted-average number of common units outstanding		2,176.5			2,145.0			2,081.4

Basic earnings per unit	$	1.91		$	1.30		$	1.20

DILUTED EARNINGS PER UNIT
Net income attributable to limited partners	$	4,172.4		$	2,799.3		$	2,513.1

Diluted weighted-average number of units outstanding:
Distribution-bearing common units		2,176.5			2,145.0			2,081.4
Phantom units (1)		10.5			9.3			7.7
Total		2,187.0			2,154.3			2,089.1

Diluted earnings per unit	$	1.91		$	1.30		$	1.20

(1)Each phantom unit award includes a DER, which entitles the recipient to receive cash payments equal to the product of the number of phantom unit awards and the cash distribution per unit paid to our common unitholders. Cash payments made in connection with DERs are nonforfeitable. As a result, the phantom units are considered participating securities for purposes of computing basic earnings per unit.

Business Combinations (Tables)

12 Months Ended

Dec. 31, 2018

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 acquisition at March 29, 2018.

Purchase price for remaining 50% equity interest in Delaware Processing	$	154.5
Fair value of our 50% equity interest in Delaware Processing held before the acquisition		146.4
Total	$	300.9
Recognized amounts of identifiable assets acquired and liabilities assumed:
Assets acquired in business combination:
Current assets, including cash of $3.9 million	$	10.8
Property, plant and equipment		200.0
Contract-based intangible assets		82.6
Customer relationship intangible assets		9.9
Total assets acquired	$	303.3
Liabilities assumed in business combination:
Current liabilities	$	(1.8	)
Long-term liabilities		(0.6	)
Total liabilities assumed	$	(2.4	)
Total identifiable net assets	$	300.9
Goodwill	$	--

The following table presents the final fair value allocation of assets acquired and liabilities assumed in the Azure acquisition at April 30, 2017.

Assets acquired in business combination:
Current assets	$	3.1
Property, plant and equipment		193.1
Total assets acquired		196.2
Liabilities assumed in business combination:
Current liabilities		(1.4	)
Long-term liabilities		(3.4	)
Total liabilities assumed		(4.8	)
Total identifiable net assets	$	191.4

Equity-Based Awards (Tables)

12 Months Ended

Dec. 31, 2018

Equity-based Awards [Abstract]

Equity-based Award Expense

	For the Year Ended December 31,
	2018		2017		2016
Equity-classified awards:
Phantom unit awards	$	99.7	$	92.8	$	78.6
Restricted common unit awards		--		0.5		4.7
Profits interest awards		6.1		6.0		5.4
Liability-classified awards		0.3		0.4		0.5
Total	$	106.1	$	99.7	$	89.2

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 January 1, 2016		5,426,949		$	33.63
Granted (2)		4,508,310		$	21.90
Vested		(1,761,455	)	$	33.10
Forfeited		(406,303	)	$	28.52
Phantom unit awards at December 31, 2016		7,767,501		$	27.20
Granted (3)		4,268,920		$	28.83
Vested		(2,490,081	)	$	28.30
Forfeited		(256,839	)	$	27.60
Phantom unit awards at December 31, 2017		9,289,501		$	27.65
Granted (4)		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

(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 2016 was $98.7 million based on a grant date market price of our common units ranging from $21.86 to $27.39 per unit. An estimated annual forfeiture rate of 3.9% was applied to these awards. (3) The aggregate grant date fair value of phantom unit awards issued during 2017 was $123.1 million based on a grant date market price of our common units ranging from $24.55 to $28.87 per unit. An estimated annual forfeiture rate of 3.8% was applied to these awards. (4) 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 our common units ranging from $25.40 to $29.22 per unit. An estimated annual forfeiture rate of 3.2% was applied to these awards.

The following table summarizes key elements of each Employee Partnership as of December 31, 2018:

Employee

Partnership

Enterprise

Common Units

Contributed to

Employee Partnership

by EPCO Holdings

Class A

Capital

Base (1)

Class A

Preference

Return (2)

Expected

Vesting/

Liquidation

Date

Estimated

Grant Date

Fair Value of

Profits Interest

Awards (3)

Unrecognized

Compensation

Cost (4)

PubCo I

2,723,052

$63.7 million

0.3900

Feb. 2020

$13.0 million

$4.3 million

PubCo II

2,834,198

$66.3 million

0.3900

Feb. 2021

$14.9 million

$7.3 million

PubCo III

105,000

$2.5 million

0.3900

Apr. 2020

$0.5 million

$0.2 million

PrivCo I

1,111,438

$26.0 million

0.3900

Feb. 2021

$5.8 million

$0.5 million

EPD IV

6,400,000

$172.9 million

0.4325

Dec. 2023

$26.7 million

$23.1 million

EPCO II

1,600,000

$43.2 million

0.4325

Dec. 2023

$6.7 million

$0.5 million

(1)Represents fair market value of the Enterprise common units contributed to each Employee Partnership at the applicable contribution date.

(3)Represents the total grant date fair value of the profits interest awards irrespective of how such costs will be allocated between us and EPCO and its privately held affiliates.

	Expected	Risk-Free	Expected	Expected Unit
Employee	Life	Interest	Distribution	Price
Partnership	of Award	Rate	Yield	Volatility
PubCo I	4.0 years	0.9% to 2.7%	5.9% to 7.0%	19% to 40%
PubCo II	5.0 years	1.1% to 3.0%	5.9% to 7.0%	19% to 40%
PubCo III	4.0 years	1.0% to 2.2%	6.1% to 6.8%	27% to 40%
PrivCo I	5.0 years	1.2% to 1.6%	6.1% to 6.7%	28% to 40%
EPD IV	5.0 years	2.8%	6.5%	27%
EPCO II	5.0 years	2.8%	6.5%	27%

Supplemental Information Regarding Phantom Unit Awards

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

	For the Year Ended December 31,
	2018		2017		2016
Cash payments made in connection with DERs	$	17.7	$	15.1	$	11.7
Total intrinsic value of phantom unit awards that vested during period	$	90.7	$	69.8	$	40.9

Restricted Common Unit Awards

The following table presents restricted common unit award activity for the years indicated:

	Number of Units			Weighted- Average Grant Date Fair Value per Unit (1)
Restricted common units at January 1, 2016		1,960,520		$	27.88
Vested		(1,234,502	)	$	27.45
Forfeited		(43,724	)	$	28.48
Restricted common units at December 31, 2016		682,294		$	28.61
Vested		(681,044	)	$	28.60
Forfeited		(1,250	)	$	31.07
Restricted common units at December 31, 2017		--		$	N/A

(1)Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued.

Supplemental Information Regarding Restricted Common Unit Awards

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

	For the Year Ended December 31,
	2017		2016
Cash distributions paid to restricted common unitholders	$	0.3	$	1.6
Total intrinsic value of restricted common unit awards that vested during period	$	18.9	$	28.5

Derivative Instruments, Hedging Activities and Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2018

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 commodity derivative instruments outstanding at December 31, 2018 (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)		4.9		n/a	Cash flow hedge
Forecasted sales of NGLs (MMBbls)		1.0		n/a	Cash flow hedge
Octane enhancement:
Forecasted purchase of NGLs (MMBbls)		1.8		n/a	Cash flow hedge
Forecasted sales of octane enhancement products (MMBbls)		3.1		0.1	Cash flow hedge
Natural gas marketing:
Natural gas storage inventory management activities (Bcf)		3.3		n/a	Fair value hedge
NGL marketing:
Forecasted purchases of NGLs and related hydrocarbon products (MMBbls)		33.6		4.3	Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products (MMBbls)		45.0		1.7	Cash flow hedge
NGLs inventory management activities (MMBbls)		0.3		n/a	Fair value hedge
Refined products marketing:
Forecasted purchases of refined products (MMBbls)		1.0		n/a	Cash flow hedge
Forecasted sales of refined products (MMBbls)		2.0		n/a	Cash flow hedge
Refined products inventory management activities (MMBbls)		0.5		n/a	Fair value hedge
Crude oil marketing:
Forecasted purchases of crude oil (MMBbls)		18.4		1.9	Cash flow hedge
Forecasted sales of crude oil (MMBbls)		28.5		1.9	Cash flow hedge
Derivatives not designated as hedging instruments:
Natural gas risk management activities (Bcf) (3,4)		77.5		0.9	Mark-to-market
NGL risk management activities (MMBbls) (4)		3.3		n/a	Mark-to-market
Refined products risk management activities (MMBbls) (4)		2.6		n/a	Mark-to-market
Crude oil risk management activities (MMBbls) (4)		26.3		3.2	Mark-to-market

(1) Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes. (2) The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is December 2020, June 2019 and December 2020, respectively. (3) Current volume includes 29.8 Bcf of physical derivative instruments that are predominantly priced at a marked-based index plus a premium or minus a discount related to location differences. (4) Reflects the use of derivative instruments to manage risks associated with transportation, processing and storage assets.

Derivative Assets and Liabilities Balance Sheet

The following table provides a balance sheet overview of our derivative assets and liabilities at the dates indicated:

	Asset Derivatives						Liability Derivatives
	December 31, 2018			December 31, 2017			December 31, 2018			December 31, 2017
	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	$	--	Current liabilities	$	1.5
Interest rate derivatives	Other assets		--	Other assets		0.1	Other liabilities		--	Other liabilities		0.2
Total interest rate derivatives			--			0.1			--			1.7
Commodity derivatives	Current assets		138.5	Current assets		109.5	Current liabilities		115.0	Current liabilities		104.4
Commodity derivatives	Other assets		5.6	Other assets		6.4	Other liabilities		11.1	Other liabilities		6.8
Total commodity derivatives			144.1			115.9			126.1			111.2
Total derivatives designated as hedging instruments		$	144.1		$	116.0		$	126.1		$	112.9

Derivatives not designated as hedging instruments
Commodity derivatives	Current assets	$	15.9	Current assets	$	43.9	Current liabilities	$	33.2	Current liabilities	$	62.3
Commodity derivatives	Other assets		1.9	Other assets		1.9	Other liabilities		3.1	Other liabilities		3.4
Total commodity derivatives			17.8			45.8			36.3			65.7
Total derivatives not designated as hedging instruments		$	17.8		$	45.8		$	36.3		$	65.7

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, 2018:
Commodity derivatives		$	161.9		$	--		$	161.9		$	(158.6	)	$	--	$	--		$	3.3
As of December 31, 2017:
Interest rate derivatives		$	0.1		$	--		$	0.1		$	(0.1	)	$	--	$	--		$	--
Commodity derivatives			161.7			--			161.7			(157.8	)		--		--			3.9

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, 2018:
Commodity derivatives		$	162.4		$	--		$	162.4		$	(158.6	)		$	(2.3	)		$	1.5
As of December 31, 2017:
Interest rate derivatives		$	1.7		$	--		$	1.7		$	(0.1	)		$	--			$	1.6
Commodity derivatives			176.9			--			176.9			(157.8	)			(17.3	)			1.8

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,
		2018		2017			2016
Interest rate derivatives	Interest expense	$	1.3	$	(0.2	)	$	0.3
Commodity derivatives	Revenue		9.9		1.1			(90.5	)
Total		$	11.2	$	0.9		$	(90.2	)

Derivatives in Fair Value Hedging Relationships	Location	Gain (Loss) Recognized in Income on Hedged Item
		For the Year Ended December 31,
		2018			2017		2016
Interest rate derivatives	Interest expense	$	(1.4	)	$	0.4	$	(0.4	)
Commodity derivatives	Revenue		(6.9	)		27.4		125.0
Total		$	(8.3	)	$	27.8	$	124.6

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,
	2018		2017			2016
Interest rate derivatives	$	22.2	$	(5.7	)	$	42.3
Commodity derivatives – Revenue (1)		293.0		(33.7	)		(197.4	)
Commodity derivatives – Operating costs and expenses (1)		0.2		(4.8	)		3.6
Total	$	315.4	$	(44.2	)	$	(151.5	)

(1)The fair value of these derivative instruments will be reclassified to their respective locations on the Statement of Consolidated Operations upon settlement of the underlying derivative transactions, as appropriate.

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

Derivatives in Cash Flow Hedging Relationships	Location	Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income
		For the Year Ended December 31,
		2018			2017			2016
Interest rate derivatives	Interest expense	$	(38.1	)	$	(40.4	)	$	(37.4	)
Commodity derivatives	Revenue		131.7			(111.6	)		(53.6	)
Commodity derivatives	Operating costs and expenses		(1.3	)		(0.6	)		0.2
Total		$	92.3		$	(152.6	)	$	(90.8	)

Gain/(Loss) Recognized in Income on Derivative

The following table presents the effect of our derivative instruments not designated as hedging instruments on our Statements of Consolidated Operations for the years indicated:

Derivatives Not Designated as Hedging Instruments	Location	Gain (Loss) Recognized in Income on Derivative
		For the Year Ended December 31,
		2018			2017			2016
Commodity derivatives	Revenue	$	(462.9	)	$	(42.7	)	$	(38.4	)
Commodity derivatives	Operating costs and expenses		8.2			0.1			(0.4	)
Total		$	(454.7	)	$	(42.6	)	$	(38.8	)

Unrealized mark-to-market gains (losses)

Unrealized mark-to-market gains (losses) by segment:
NGL Pipelines & Services	$	18.0
Crude Oil Pipelines & Services		(44.1	)
Natural Gas Pipelines & Services		5.3
Petrochemical & Refined Products Services		1.7
Total	$	(19.1	)

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

	At December 31, 2018 Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total
Financial assets:
Commodity derivatives:
Value before application of CME Rule 814	$	172.3		$	282.4		$	2.2		$	456.9
Impact of CME Rule 814 change		(134.8	)		(159.3	)		(0.9	)		(295.0	)
Total commodity derivatives		37.5			123.1			1.3			161.9
Total	$	37.5		$	123.1		$	1.3		$	161.9

Financial liabilities:
Liquidity Option Agreement (see Note 17)	$	--		$	--		$	390.0		$	390.0
Commodity derivatives:
Value before application of CME Rule 814		85.5			291.2			21.4			398.1
Impact of CME Rule 814 change		(48.6	)		(172.9	)		(14.2	)		(235.7	)
Total commodity derivatives		36.9			118.3			7.2			162.4
Total	$	36.9		$	118.3		$	397.2		$	552.4

	At December 31, 2017 Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total
Financial assets:
Interest rate derivatives	$	--		$	0.1		$	--	$	0.1
Commodity derivatives:
Value before application of CME Rule 814		47.1			184.9			2.9		234.9
Impact of CME Rule 814 change		(47.1	)		(26.1	)		--		(73.2	)
Total commodity derivatives		--			158.8			2.9		161.7
Total	$	--		$	158.9		$	2.9	$	161.8

Financial liabilities:
Liquidity Option Agreement (see Note 17)	$	--		$	--		$	333.9	$	333.9
Interest rate derivatives		--			1.7			--		1.7
Commodity derivatives:
Value before application of CME Rule 814		118.4			270.6			1.7		390.7
Impact of CME Rule 814 change		(118.4	)		(95.4	)		--		(213.8	)
Total commodity derivatives		--			175.2			1.7		176.9
Total	$	--		$	176.9		$	335.6	$	512.5

Fair Value Measurements, Valuation Techniques

The following tables provide quantitative information regarding our recurring Level 3 fair value measurements for commodity derivatives at the dates indicated:

	Fair Value At December 31, 2018
	Financial Assets		Financial Liabilities		Valuation Techniques	Unobservable Input	Range
Commodity derivatives – Crude oil	$	0.9	$	0.8	Discounted cash flow	Forward commodity prices	$37.59-$51.99/barrel
Commodity derivatives – Ethane		0.4		0.6	Discounted cash flow	Forward commodity prices	$0.28-$0.31/gallon
Commodity derivatives – Propane		--		1.0	Discounted cash flow	Forward commodity prices	$0.61-$0.66/gallon
Commodity derivatives – Normal butane		--		0.7	Discounted cash flow	Forward commodity prices	$0.66-$0.72/gallon
Commodity derivatives – Natural gasoline		--		4.1	Discounted cash flow	Forward commodity prices	$0.99-$1.01/gallon
Total	$	1.3	$	7.2

	Fair Value At December 31, 2017
	Financial Assets		Financial Liabilities		Valuation Techniques	Unobservable Input	Range
Commodity derivatives – Crude oil	$	2.9	$	1.7	Discounted cash flow	Forward commodity prices	$60.21-$66.05/barrel
Total	$	2.9	$	1.7

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:

		For the Year Ended December 31,
	Location	2018			2017
Financial asset (liability) balance, net, January 1		$	(332.7	)	$	(268.2	)
Total gains (losses) included in:
Net income (1)	Revenue		0.7			2.3
Net income	Other expense, net – Liquidity Option Agreement		(56.1	)		(64.3	)
Other comprehensive income (loss)	Commodity derivative instruments – changes in fair value of cash flow hedges		(3.2	)		0.1
Settlements (1)	Revenue		(1.9	)		(2.4	)
Transfers out of Level 3 (2)			(2.7	)		(0.2	)
Financial liability balance, net, December 31 (2)		$	(395.9	)	$	(332.7	)

(1)There were $1.2 million and $0.1 million of unrealized losses included in these amounts for the years ended December 31, 2018 and 2017, respectively. (2)Transfers out of Level 3 into Level 2 were due to shorter remaining transaction maturities falling inside of the Level 2 range at December 31, 2018 and 2017.

Asset Impairment Charges by Segment

The following table summarizes our non-cash asset impairment charges by segment during the years indicated:

	For the Year Ended December 31,
	2018		2017		2016
NGL Pipelines & Services	$	18.6	$	11.5	$	21.0
Crude Oil Pipelines & Services		11.2		10.2		2.3
Natural Gas Pipelines & Services		13.9		14.3		12.3
Petrochemical & Refined Products Services		3.1		1.8		9.6
Total	$	46.8	$	37.8	$	45.2

Nonrecurring Fair Value Measurements

				Fair Value Measurements at the End of the Reporting Period Using
	Carrying Value at December 31, 2018			Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total Non-Cash Impairment Loss
Long-lived assets disposed of other than by sale		$	--		$	--		$	--		$	--		$	43.7
Long-lived assets held and used			--			--			--			--			3.1
Total														$	46.8

			Fair Value Measurements at the End of the Reporting Period Using
	Carrying Value at December 31, 2017		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Non-Cash Impairment Loss
Long-lived assets disposed of other than by sale	$	--	$	--	$	--	$	--	$	16.7
Long-lived assets held and used		1.5		--		--		1.5		15.4
Long-lived assets held for sale		2.5		--		--		2.5		2.5
Long-lived assets disposed of by sale		--		--		--		--		3.2
Total									$	37.8

The following table presents categories of long-lived assets that were subject to non-recurring fair value measurements during the year ended December 31, 2016:

			Fair Value Measurements at the End of the Reporting Period Using
	Carrying Value at December 31, 2016		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Non-Cash Impairment Loss
Long-lived assets disposed of other than by sale	$	--	$	--	$	--	$	--	$	29.9
Long-lived assets held and used		8.0		8.0		--		--		2.2
Long-lived assets disposed of by sale		--		--		--		--		13.1
Total									$	45.2

Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2018

Related Party Transactions

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

	For the Year Ended December 31,
	2018		2017		2016
Revenues – related parties:
Unconsolidated affiliates	$	107.7	$	45.0	$	56.7
Costs and expenses – related parties:
EPCO and its privately held affiliates	$	1,089.6	$	1,010.9	$	963.2
Unconsolidated affiliates		447.4		223.4		253.9
Total	$	1,537.0	$	1,234.3	$	1,217.1

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

	December 31,
	2018		2017
Accounts receivable - related parties:
Unconsolidated affiliates	$	3.5	$	1.8

Accounts payable - related parties:
EPCO and its privately held affiliates	$	116.3	$	99.3
Unconsolidated affiliates		23.9		28.0
Total	$	140.2	$	127.3

At December 31, 2018, EPCO and its privately held affiliates (including Dan Duncan LLC and certain Duncan family trusts) beneficially owned the following limited partner interests in us:

Total Number of Units	Percentage of Total Units Outstanding
697,529,483	31.9%

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,
	2018		2017		2016
Operating costs and expenses	$	948.8	$	882.1	$	840.7
General and administrative expenses		124.2		110.4		105.3
Total costs and expenses	$	1,073.0	$	992.5	$	946.0

Provision for Income Taxes (Tables)

12 Months Ended

Dec. 31, 2018

Provision for Income Taxes [Abstract]

Federal and State Income Tax Provision

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

	For the Year Ended December 31,
	2018			2017			2016
Current:
Federal	$	5.3		$	0.1		$	(0.5	)
State		33.1			18.5			16.7
Foreign		0.5			1.0			0.6
Total current		38.9			19.6			16.8
Deferred:
Federal		(0.3	)		(1.8	)		1.1
State		21.7			7.9			5.2
Foreign		--			--			0.3
Total deferred		21.4			6.1			6.6
Total provision for income taxes	$	60.3		$	25.7		$	23.4

Reconciliation of Provision for Income Taxes

A reconciliation of the provision for income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows:

	For the Year Ended December 31,
	2018		2017			2016
Pre-Tax Net Book Income (“NBI”)	$	4,298.8	$	2,881.3		$	2,576.4

Texas Margin Tax (1)	$	54.8	$	26.4		$	22.1
State income taxes (net of federal benefit)		0.2		0.5			0.2
Federal income taxes computed by applying the federal statutory rate to NBI of corporate entities		2.1		0.1			0.8
Other permanent differences		3.2		(1.3	)		0.3
Provision for income taxes	$	60.3	$	25.7		$	23.4

Effective income tax rate		1.4%		0.9%			0.9%

(1)Although the Texas Margin Tax is not considered a state income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers our Texas-sourced revenues and expenses.

Components of Deferred Tax Assets and Liabilities

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

	December 31,
	2018		2017
Deferred tax assets:
Net operating loss carryovers (1)	$	0.1	$	0.2
Accruals		2.6		1.4
Total deferred tax assets		2.7		1.6
Less: Deferred tax liabilities:
Property, plant and equipment		80.8		58.0
Equity investment in partnerships		2.3		2.1
Total deferred tax liabilities		83.1		60.1
Total net deferred tax liabilities	$	80.4	$	58.5

(1)These losses expire in various years between 2019 and 2033 and are subject to limitations on their utilization.

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2018

Commitments and Contingencies [Abstract]

Summary of Contractual Obligations

The following table summarizes our various contractual obligations at December 31, 2018. A description of each type of contractual obligation follows:

	Payment or Settlement due by Period
Contractual Obligations	Total		2019		2020		2021		2022		2023		Thereafter
Scheduled maturities of debt obligations	$	26,420.6	$	1,500.0	$	1,500.0	$	1,325.0	$	1,400.0	$	1,250.0	$	19,445.6
Estimated cash interest payments	$	25,520.2	$	1,190.4	$	1,132.5	$	1,062.9	$	1,010.1	$	969.9	$	20,154.4
Operating lease obligations	$	324.8	$	50.5	$	45.6	$	38.7	$	30.8	$	20.9	$	138.3
Purchase obligations:
Product purchase commitments:
Estimated payment obligations:
Natural gas	$	1,631.2	$	572.0	$	599.4	$	459.8	$	--	$	--	$	--
NGLs	$	3,437.2	$	760.6	$	739.4	$	620.3	$	527.7	$	310.3	$	478.9
Crude oil	$	4,778.2	$	1,038.6	$	771.3	$	557.1	$	543.1	$	438.1	$	1,430.0
Petrochemicals & refined products	$	399.7	$	179.0	$	178.3	$	42.4	$	--	$	--	$	--
Other	$	27.4	$	8.2	$	8.3	$	4.3	$	2.3	$	2.4	$	1.9
Service payment commitments	$	403.8	$	75.1	$	72.2	$	55.3	$	53.7	$	38.9	$	108.6
Capital expenditure commitments	$	171.8	$	171.8	$	--	$	--	$	--	$	--	$	--

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,
	2018		2017
Noncurrent portion of AROs (see Note 4)	$	121.4	$	81.1
Deferred revenues – non-current portion (see Note 9)		210.3		135.5
Liquidity Option Agreement		390.0		333.9
Derivative liabilities		14.2		10.4
Centennial guarantees		3.6		4.5
Other		12.1		13.0
Total	$	751.6	$	578.4

Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2018

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,
	2018			2017			2016
Decrease (increase) in:
Accounts receivable – trade	$	730.2		$	(1,076.2	)	$	(679.0	)
Accounts receivable – related parties		(2.3	)		(0.7	)		0.4
Inventories		121.4			194.6			(871.8	)
Prepaid and other current assets		214.4			226.0			(49.3	)
Other assets		(9.7	)		(111.0	)		(2.0	)
Increase (decrease) in:
Accounts payable – trade		18.3			66.6			(21.5	)
Accounts payable – related parties		51.4			56.0			21.0
Accrued product payables		(1,132.0	)		952.3			1,193.3
Accrued interest		37.6			17.3			(11.4	)
Other current liabilities		(70.9	)		(291.4	)		189.9
Other liabilities		57.8			(1.3	)		49.5
Net effect of changes in operating accounts	$	16.2		$	32.2		$	(180.9	)

Cash payments for interest, net of $147.9, $192.1 and $168.2 capitalized in 2018, 2017 and 2016, respectively	$	1,017.9		$	912.1		$	947.9

Cash payments for federal and state income taxes	$	15.5		$	20.9		$	18.7

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,
	2018		2017		2016
Cash proceeds from sale of Red River System	$	134.9	$	--	$	--
Cash proceeds from other asset sales		26.3		40.1		46.5
Total	$	161.2	$	40.1	$	46.5

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

	For the Year Ended December 31,
	2018		2017		2016
Gains attributable to sale of Red River System	$	20.6	$	--	$	--
Net gains attributable to other asset sales		8.1		10.7		2.5
Total	$	28.7	$	10.7	$	2.5

Quarterly Financial Information (Unaudited) [Abstract]

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
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Reference 6: http://fasb.org/us-gaap/role/ref/legacyRef
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Reference 8: http://fasb.org/us-gaap/role/ref/legacyRef
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Reference 9: http://fasb.org/us-gaap/role/ref/legacyRef
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+ Details

Quarterly Financial Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2018

Quarterly Financial Information (Unaudited)

The following table presents selected quarterly financial data for the periods indicated:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
For the Year Ended December 31, 2018:
Revenues	$	9,298.5	$	8,467.5	$	9,585.9	$	9,182.3
Operating income		1,138.5		986.4		1,643.3		1,640.4
Net income		911.5		687.2		1,334.6		1,305.2
Net income attributable to limited partners		900.7		673.8		1,313.2		1,284.7

Earnings per unit:
Basic	$	0.41	$	0.31	$	0.60	$	0.59
Diluted	$	0.41	$	0.31	$	0.60	$	0.59

For the Year Ended December 31, 2017:
Revenues	$	7,320.4	$	6,607.6	$	6,886.9	$	8,426.6
Operating income		1,031.6		938.7		879.2		1,079.4
Net income		771.0		666.0		621.3		797.3
Net income attributable to limited partners		760.7		653.7		610.9		774.0

Earnings per unit:
Basic	$	0.36	$	0.30	$	0.28	$	0.36
Diluted	$	0.36	$	0.30	$	0.28	$	0.36

Condensed Consolidating Financial Information (Tables)

12 Months Ended

Dec. 31, 2018

Condensed Consolidating Financial Information [Abstract]

Condensed Consolidating Balance Sheet

Enterprise Products Partners L.P.

Condensed Consolidating Balance Sheet

December 31, 2018

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non- guarantor)		EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries		Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
ASSETS
Current assets:
Cash and cash equivalents and restricted cash	$	393.4	$	50.3	$	(33.6	)	$	410.1	$	--	$	--		$	410.1
Accounts receivable – trade, net		1,303.1		2,356.8		(0.8	)		3,659.1		--		--			3,659.1
Accounts receivable – related parties		141.8		1,423.7		(1,530.1	)		35.4		0.8		(32.7	)		3.5
Inventories		889.3		633.2		(0.4	)		1,522.1		--		--			1,522.1
Derivative assets		105.0		49.1		0.3			154.4		--		--			154.4
Prepaid and other current assets		166.0		155.1		(10.2	)		310.9		--		0.6			311.5
Total current assets		2,998.6		4,668.2		(1,574.8	)		6,092.0		0.8		(32.1	)		6,060.7
Property, plant and equipment, net		6,112.7		32,628.7		(3.8	)		38,737.6		--		--			38,737.6
Investments in unconsolidated affiliates		43,962.6		4,170.6		(45,518.1	)		2,615.1		24,273.6		(24,273.6	)		2,615.1
Intangible assets, net		659.2		2,963.0		(13.8	)		3,608.4		--		--			3,608.4
Goodwill		459.5		5,285.7		--			5,745.2		--		--			5,745.2
Other assets		292.1		131.9		(222.1	)		201.9		0.9		--			202.8
Total assets	$	54,484.7	$	49,848.1	$	(47,332.6	)	$	57,000.2	$	24,275.3	$	(24,305.7	)	$	56,969.8

LIABILITIES AND EQUITY
Current liabilities:
Current maturities of debt	$	1,500.0	$	0.1	$	--		$	1,500.1	$	--	$	--		$	1,500.1
Accounts payable – trade		404.0		734.3		(35.5	)		1,102.8		--		--			1,102.8
Accounts payable – related parties		1,557.3		127.5		(1,543.9	)		140.9		31.9		(32.6	)		140.2
Accrued product payables		1,574.7		1,902.3		(1.2	)		3,475.8		--		--			3,475.8
Accrued interest		395.5		0.9		(0.8	)		395.6		--		--			395.6
Derivative liabilities		86.2		61.7		0.3			148.2		--		--			148.2
Other current liabilities		87.9		326.3		(9.4	)		404.8		--		--			404.8
Total current liabilities		5,605.6		3,153.1		(1,590.5	)		7,168.2		31.9		(32.6	)		7,167.5
Long-term debt		24,663.4		14.7		--			24,678.1		--		--			24,678.1
Deferred tax liabilities		17.0		62.0		(0.9	)		78.1		--		2.3			80.4
Other long-term liabilities		65.2		518.4		(221.9	)		361.7		389.9		--			751.6
Commitments and contingencies
Equity:
Partners’ and other owners’ equity		24,133.5		46,031.8		(45,917.9	)		24,247.4		23,853.5		(24,247.4	)		23,853.5
Noncontrolling interests		--		68.1		398.6			466.7		--		(28.0	)		438.7
Total equity		24,133.5		46,099.9		(45,519.3	)		24,714.1		23,853.5		(24,275.4	)		24,292.2
Total liabilities and equity	$	54,484.7	$	49,848.1	$	(47,332.6	)	$	57,000.2	$	24,275.3	$	(24,305.7	)	$	56,969.8

Enterprise Products Partners L.P.

Condensed Consolidating Balance Sheet

December 31, 2017

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non- guarantor)		EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries		Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
ASSETS
Current assets:
Cash and cash equivalents and restricted cash	$	65.2	$	31.5	$	(26.4	)	$	70.3	$	--	$	--		$	70.3
Accounts receivable – trade, net		1,382.3		2,976.6		(0.5	)		4,358.4		--		--			4,358.4
Accounts receivable – related parties		110.3		1,182.1		(1,289.3	)		3.1		--		(1.3	)		1.8
Inventories		1,038.9		572.3		(1.4	)		1,609.8		--		--			1,609.8
Derivative assets		110.0		43.4		--			153.4		--		--			153.4
Prepaid and other current assets		136.3		189.0		(12.6	)		312.7		--		--			312.7
Total current assets		2,843.0		4,994.9		(1,330.2	)		6,507.7		--		(1.3	)		6,506.4
Property, plant and equipment, net		5,622.6		29,996.3		1.5			35,620.4		--		--			35,620.4
Investments in unconsolidated affiliates		41,616.6		4,298.0		(43,255.2	)		2,659.4		22,881.5		(22,881.5	)		2,659.4
Intangible assets, net		675.5		3,028.6		(13.8	)		3,690.3		--		--			3,690.3
Goodwill		459.5		5,285.7		--			5,745.2		--		--			5,745.2
Other assets		296.4		110.0		(211.0	)		195.4		1.0		--			196.4
Total assets	$	51,513.6	$	47,713.5	$	(44,808.7	)	$	54,418.4	$	22,882.5	$	(22,882.8	)	$	54,418.1

LIABILITIES AND EQUITY
Current liabilities:
Current maturities of debt	$	2,854.6	$	0.4	$	--		$	2,855.0	$	--	$	--		$	2,855.0
Accounts payable – trade		290.2		537.8		(26.4	)		801.6		0.1		--			801.7
Accounts payable – related parties		1,320.3		112.0		(1,305.0	)		127.3		1.3		(1.3	)		127.3
Accrued product payables		1,825.9		2,741.7		(1.3	)		4,566.3		--		--			4,566.3
Accrued interest		358.0		--		--			358.0		--		--			358.0
Derivative liabilities		115.2		53.0		--			168.2		--		--			168.2
Other current liabilities		108.9		320.1		(10.8	)		418.2		--		0.4			418.6
Total current liabilities		6,873.1		3,765.0		(1,343.5	)		9,294.6		1.4		(0.9	)		9,295.1
Long-term debt		21,699.0		14.7		--			21,713.7		--		--			21,713.7
Deferred tax liabilities		6.7		50.2		(0.5	)		56.4		--		2.1			58.5
Other long-term liabilities		60.4		396.5		(212.4	)		244.5		333.9		--			578.4
Commitments and contingencies
Equity:
Partners’ and other owners’ equity		22,874.4		43,412.0		(43,433.3	)		22,853.1		22,547.2		(22,853.1	)		22,547.2
Noncontrolling interests		--		75.1		181.0			256.1		--		(30.9	)		225.2
Total equity		22,874.4		43,487.1		(43,252.3	)		23,109.2		22,547.2		(22,884.0	)		22,772.4
Total liabilities and equity	$	51,513.6	$	47,713.5	$	(44,808.7	)	$	54,418.4	$	22,882.5	$	(22,882.8	)	$	54,418.1

Condensed Consolidating Statement of Operations

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Operations

For the Year Ended December 31, 2018

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments			Consolidated Total
Revenues	$	42,946.4		$	23,756.4		$	(30,168.6	)	$	36,534.2		$	--		$	--		$	36,534.2
Costs and expenses:
Operating costs and expenses		41,718.2			19,845.2			(30,166.1	)		31,397.3			--			--			31,397.3
General and administrative costs		31.8			172.0			2.1			205.9			2.3			0.1			208.3
Total costs and expenses		41,750.0			20,017.2			(30,164.0	)		31,603.2			2.3			0.1			31,605.6
Equity in income of unconsolidated affiliates		4,148.3			587.2			(4,255.5	)		480.0			4,230.8			(4,230.8	)		480.0
Operating income		5,344.7			4,326.4			(4,260.1	)		5,411.0			4,228.5			(4,230.9	)		5,408.6
Other income (expense):
Interest expense		(1,097.1	)		(10.5	)		10.9			(1,096.7	)		--			--			(1,096.7	)
Other, net		12.1			41.8			(10.9	)		43.0			(56.1	)		--			(13.1	)
Total other expense, net		(1,085.0	)		31.3			--			(1,053.7	)		(56.1	)		--			(1,109.8	)
Income before income taxes		4,259.7			4,357.7			(4,260.1	)		4,357.3			4,172.4			(4,230.9	)		4,298.8
Provision for income taxes		(29.2	)		(29.6	)		--			(58.8	)		--			(1.5	)		(60.3	)
Net income		4,230.5			4,328.1			(4,260.1	)		4,298.5			4,172.4			(4,232.4	)		4,238.5
Net loss (income) attributable to noncontrolling interests		--			(7.6	)		(63.8	)		(71.4	)		--			5.3			(66.1	)
Net income attributable to entity	$	4,230.5		$	4,320.5		$	(4,323.9	)	$	4,227.1		$	4,172.4		$	(4,227.1	)	$	4,172.4

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Operations

For the Year Ended December 31, 2017

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments			Consolidated Total
Revenues	$	40,696.8		$	18,451.2		$	(29,906.5	)	$	29,241.5		$	--		$	--		$	29,241.5
Costs and expenses:
Operating costs and expenses		39,809.6			15,654.9			(29,907.0	)		25,557.5			--			--			25,557.5
General and administrative costs		31.4			148.0			(0.1	)		179.3			1.8			--			181.1
Total costs and expenses		39,841.0			15,802.9			(29,907.1	)		25,736.8			1.8			--			25,738.6
Equity in income of unconsolidated affiliates		2,990.1			566.8			(3,130.9	)		426.0			2,865.4			(2,865.4	)		426.0
Operating income		3,845.9			3,215.1			(3,130.3	)		3,930.7			2,863.6			(2,865.4	)		3,928.9
Other income (expense):
Interest expense		(982.5	)		(11.8	)		9.7			(984.6	)		--			--			(984.6	)
Other, net		9.2			1.8			(9.7	)		1.3			(64.3	)		--			(63.0	)
Total other expense, net		(973.3	)		(10.0	)		--			(983.3	)		(64.3	)		--			(1,047.6	)
Income before income taxes		2,872.6			3,205.1			(3,130.3	)		2,947.4			2,799.3			(2,865.4	)		2,881.3
Provision for income taxes		(12.0	)		(13.7	)		--			(25.7	)		--			--			(25.7	)
Net income		2,860.6			3,191.4			(3,130.3	)		2,921.7			2,799.3			(2,865.4	)		2,855.6
Net loss (income) attributable to noncontrolling interests		--			(6.5	)		(55.1	)		(61.6	)		--			5.3			(56.3	)
Net income attributable to entity	$	2,860.6		$	3,184.9		$	(3,185.4	)	$	2,860.1		$	2,799.3		$	(2,860.1	)	$	2,799.3

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Operations

For the Year Ended December 31, 2016

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments			Consolidated Total
Revenues	$	28,958.7		$	15,296.8		$	(21,233.2	)	$	23,022.3		$	--		$	--		$	23,022.3
Costs and expenses:
Operating costs and expenses		28,108.2			12,768.9			(21,233.6	)		19,643.5			--			--			19,643.5
General and administrative costs		22.5			135.3			--			157.8			2.3			--			160.1
Total costs and expenses		28,130.7			12,904.2			(21,233.6	)		19,801.3			2.3			--			19,803.6
Equity in income of unconsolidated affiliates		2,686.1			521.7			(2,845.8	)		362.0			2,539.9			(2,539.9	)		362.0
Operating income		3,514.1			2,914.3			(2,845.4	)		3,583.0			2,537.6			(2,539.9	)		3,580.7
Other income (expense):
Interest expense		(973.1	)		(17.3	)		7.8			(982.6	)		--			--			(982.6	)
Other, net		8.3			2.3			(7.8	)		2.8			(24.5	)		--			(21.7	)
Total other expense, net		(964.8	)		(15.0	)		--			(979.8	)		(24.5	)		--			(1,004.3	)
Income before income taxes		2,549.3			2,899.3			(2,845.4	)		2,603.2			2,513.1			(2,539.9	)		2,576.4
Provision for income taxes		(13.1	)		(8.2	)		--			(21.3	)		--			(2.1	)		(23.4	)
Net income		2,536.2			2,891.1			(2,845.4	)		2,581.9			2,513.1			(2,542.0	)		2,553.0
Net loss (income) attributable to noncontrolling interests		--			(7.4	)		(37.8	)		(45.2	)		--			5.3			(39.9	)
Net income attributable to entity	$	2,536.2		$	2,883.7		$	(2,883.2	)	$	2,536.7		$	2,513.1		$	(2,536.7	)	$	2,513.1

Condensed Consolidating Statement of Comprehensive Income

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Comprehensive Income

For the Year Ended December 31, 2018

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
Comprehensive income	$	4,312.6	$	4,468.5		$	(4,260.1	)	$	4,521.0		$	4,395.0	$	(4,454.9	)	$	4,461.1
Comprehensive loss (income) attributable to noncontrolling interests		--		(7.6	)		(63.8	)		(71.4	)		--		5.3			(66.1	)
Comprehensive income attributable to entity	$	4,312.6	$	4,460.9		$	(4,323.9	)	$	4,449.6		$	4,395.0	$	(4,449.6	)	$	4,395.0

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Comprehensive Income

For the Year Ended December 31, 2017

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
Comprehensive income	$	2,951.7	$	3,208.6		$	(3,130.2	)	$	3,030.1		$	2,907.6	$	(2,973.8	)	$	2,963.9
Comprehensive loss (income) attributable to noncontrolling interests		--		(6.5	)		(55.1	)		(61.6	)		--		5.3			(56.3	)
Comprehensive income attributable to entity	$	2,951.7	$	3,202.1		$	(3,185.3	)	$	2,968.5		$	2,907.6	$	(2,968.5	)	$	2,907.6

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Comprehensive Income

For the Year Ended December 31, 2016

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
Comprehensive income	$	2,544.3	$	2,822.1		$	(2,845.3	)	$	2,521.1		$	2,452.2	$	(2,481.1	)	$	2,492.2
Comprehensive loss (income) attributable to noncontrolling interests		--		(7.4	)		(37.8	)		(45.2	)		--		5.3			(39.9	)
Comprehensive income attributable to entity	$	2,544.3	$	2,814.7		$	(2,883.1	)	$	2,475.9		$	2,452.2	$	(2,475.8	)	$	2,452.3

Condensed Consolidating Statement of Cash Flows

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2018

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments			Consolidated Total
Operating activities:
Net income	$	4,230.5		$	4,328.1		$	(4,260.1	)	$	4,298.5		$	4,172.4		$	(4,232.4	)	$	4,238.5
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		279.9			1,512.1			(0.4	)		1,791.6			--			--			1,791.6
Equity in income of unconsolidated affiliates		(4,148.3	)		(587.2	)		4,255.5			(480.0	)		(4,230.8	)		4,230.8			(480.0	)
Distributions received on earnings from unconsolidated affiliates		1,248.9			263.0			(1,032.5	)		479.4			3,780.0			(3,780.0	)		479.4
Net effect of changes in operating accounts and other operating activities		3,221.5			(3,244.2	)		(2.3	)		(25.0	)		121.2			0.6			96.8
Net cash flows provided by operating activities		4,832.5			2,271.8			(1,039.8	)		6,064.5			3,842.8			(3,781.0	)		6,126.3
Investing activities:
Capital expenditures		(692.0	)		(3,476.0	)		--			(4,168.0	)		(55.2	)		--			(4,223.2	)
Cash used for business combinations, net of cash received		--			(150.6	)		--			(150.6	)		--			--			(150.6	)
Proceeds from asset sales		129.3			31.9			--			161.2			--			--			161.2
Other investing activities		(2,288.2	)		196.2			2,023.0			(69.0	)		(523.3	)		523.3			(69.0	)
Cash used in investing activities		(2,850.9	)		(3,398.5	)		2,023.0			(4,226.4	)		(578.5	)		523.3			(4,281.6	)
Financing activities:
Borrowings under debt agreements		79,588.7			11.5			(11.5	)		79,588.7			--			--			79,588.7
Repayments of debt		(77,956.7	)		(0.4	)		--			(77,957.1	)		--			--			(77,957.1	)
Cash distributions paid to partners		(3,780.0	)		(1,333.1	)		1,333.1			(3,780.0	)		(3,726.9	)		3,780.0			(3,726.9	)
Cash payments made in connection with DERs		--			--			--			--			(17.7	)		--			(17.7	)
Cash distributions paid to noncontrolling interests		--			(9.2	)		(73.4	)		(82.6	)		--			1.0			(81.6	)
Cash contributions from noncontrolling interests		--			--			238.1			238.1			--			--			238.1
Net cash proceeds from issuance of common units		--			--			--			--			538.4			--			538.4
Common units acquired in connection with buyback program		--			--			--			--			(30.8	)		--			(30.8	)
Cash contributions from owners		523.3			2,476.7			(2,476.7	)		523.3			--			(523.3	)		--
Other financing activities		(28.7	)		--			--			(28.7	)		(27.3	)		--			(56.0	)
Cash provided by (used in) financing activities		(1,653.4	)		1,145.5			(990.4	)		(1,498.3	)		(3,264.3	)		3,257.7			(1,504.9	)
Net change in cash and cash equivalents, including restricted cash		328.2			18.8			(7.2	)		339.8			--			--			339.8
Cash and cash equivalents, including restricted cash, January 1		65.2			31.5			(26.4	)		70.3			--			--			70.3
Cash and cash equivalents, including restricted cash, December 31	$	393.4		$	50.3		$	(33.6	)	$	410.1		$	--		$	--		$	410.1

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2017

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments			Consolidated Total
Operating activities:
Net income	$	2,860.6		$	3,191.4		$	(3,130.3	)	$	2,921.7		$	2,799.3		$	(2,865.4	)	$	2,855.6
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		216.6			1,427.8			(0.4	)		1,644.0			--			--			1,644.0
Equity in income of unconsolidated affiliates		(2,990.1	)		(566.8	)		3,130.9			(426.0	)		(2,865.4	)		2,865.4			(426.0	)
Distributions received on earnings from unconsolidated affiliates		1,162.8			272.7			(1,001.8	)		433.7			3,574.6			(3,574.6	)		433.7
Net effect of changes in operating accounts and other operating activities		2,812.2			(2,726.3	)		(19.1	)		66.8			93.2			(1.0	)		159.0
Net cash flows provided by operating activities		4,062.1			1,598.8			(1,020.7	)		4,640.2			3,601.7			(3,575.6	)		4,666.3
Investing activities:
Capital expenditures		(846.8	)		(2,255.0	)		--			(3,101.8	)		--			--			(3,101.8	)
Cash used for business combinations, net of cash received		(7.3	)		(191.4	)		--			(198.7	)		--			--			(198.7	)
Proceeds from asset sales		17.0			23.1			--			40.1			--			--			40.1
Other investing activities		(1,908.5	)		(28.0	)		1,910.8			(25.7	)		(1,060.5	)		1,060.5			(25.7	)
Cash used in investing activities		(2,745.6	)		(2,451.3	)		1,910.8			(3,286.1	)		(1,060.5	)		1,060.5			(3,286.1	)
Financing activities:
Borrowings under debt agreements		69,349.3			--			(34.0	)		69,315.3			--			--			69,315.3
Repayments of debt		(68,459.5	)		(0.1	)		--			(68,459.6	)		--			--			(68,459.6	)
Cash distributions paid to partners		(3,574.6	)		(1,065.3	)		1,065.3			(3,574.6	)		(3,569.9	)		3,574.6			(3,569.9	)
Cash payments made in connection with DERs		--			--			--			--			(15.1	)		--			(15.1	)
Cash distributions paid to noncontrolling interests		--			(9.6	)		(40.6	)		(50.2	)		--			1.0			(49.2	)
Cash contributions from noncontrolling interests		--			0.1			0.3			0.4			--			--			0.4
Net cash proceeds from issuance of common units		--			--			--			--			1,073.4			--			1,073.4
Cash contributions from owners		1,060.5			1,900.0			(1,900.0	)		1,060.5			--			(1,060.5	)		--
Other financing activities		6.8			--			--			6.8			(29.6	)		--			(22.8	)
Cash provided by (used in) financing activities		(1,617.5	)		825.1			(909.0	)		(1,701.4	)		(2,541.2	)		2,515.1			(1,727.5	)
Net change in cash and cash equivalents, including restricted cash		(301.0	)		(27.4	)		(18.9	)		(347.3	)		--			--			(347.3	)
Cash and cash equivalents, including restricted cash, January 1		366.2			58.9			(7.5	)		417.6			--			--			417.6
Cash and cash equivalents, including restricted cash, December 31	$	65.2		$	31.5		$	(26.4	)	$	70.3		$	--		$	--		$	70.3

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2016

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments			Consolidated Total
Operating activities:
Net income	$	2,536.2		$	2,891.1		$	(2,845.4	)	$	2,581.9		$	2,513.1		$	(2,542.0	)	$	2,553.0
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		185.4			1,367.0			(0.4	)		1,552.0			--			--			1,552.0
Equity in income of unconsolidated affiliates		(2,686.1	)		(521.7	)		2,845.8			(362.0	)		(2,539.9	)		2,539.9			(362.0	)
Distributions received on earnings from unconsolidated affiliates		1,127.3			265.9			(1,012.7	)		380.5			3,331.2			(3,331.2	)		380.5
Net effect of changes in operating accounts and other operating activities		2,448.6			(2,568.5	)		43.1			(76.8	)		18.9			1.2			(56.7	)
Net cash flows provided by operating activities		3,611.4			1,433.8			(969.6	)		4,075.6			3,323.3			(3,332.1	)		4,066.8
Investing activities:
Capital expenditures		(1,327.4	)		(1,656.7	)		--			(2,984.1	)		--			--			(2,984.1	)
Cash used for business combinations, net of cash received		--			(1,000.0	)		--			(1,000.0	)		--			--			(1,000.0	)
Proceeds from asset sales		28.8			17.7			--			46.5			--			--			46.5
Other investing activities		(2,301.9	)		(63.2	)		2,296.9			(68.2	)		(2,530.9	)		2,530.9			(68.2	)
Cash used in investing activities		(3,600.5	)		(2,702.2	)		2,296.9			(4,005.8	)		(2,530.9	)		2,530.9			(4,005.8	)
Financing activities:
Borrowings under debt agreements		62,813.9			41.8			(41.8	)		62,813.9			--			--			62,813.9
Repayments of debt		(61,672.5	)		(0.1	)		--			(61,672.6	)		--			--			(61,672.6	)
Cash distributions paid to partners		(3,331.2	)		(1,089.6	)		1,089.6			(3,331.2	)		(3,300.5	)		3,331.2			(3,300.5	)
Cash payments made in connection with DERs		--			--			--			--			(11.7	)		--			(11.7	)
Cash distributions paid to noncontrolling interests		--			(8.5	)		(39.8	)		(48.3	)		--			0.9			(47.4	)
Cash contributions from noncontrolling interests		--			20.4			--			20.4			--			--			20.4
Net cash proceeds from issuance of common units		--			--			--			--			2,542.8			--			2,542.8
Cash contributions from owners		2,530.9			2,292.2			(2,292.2	)		2,530.9			--			(2,530.9	)		--
Other financing activities		(0.2	)		--			--			(0.2	)		(23.0	)		--			(23.2	)
Cash provided by (used in) financing activities		340.9			1,256.2			(1,284.2	)		312.9			(792.4	)		801.2			321.7
Net change in cash and cash equivalents, including restricted cash		351.8			(12.2	)		43.1			382.7			--			--			382.7
Cash and cash equivalents, including restricted cash, January 1		14.4			71.1			(50.6	)		34.9			--			--			34.9
Cash and cash equivalents, including restricted cash, December 31	$	366.2		$	58.9		$	(7.5	)	$	417.6		$	--		$	--		$	417.6

Partnership Operations, Organization and Basis of Presentation (Details) bbl in Millions	12 Months Ended
	Dec. 31, 2018 Segment mi bbl Bcf
Related Party Transaction [Line Items]
Number of miles of pipelines \| mi	49,200
Number of barrels of storage capacity \| bbl	260
Number of cubic feet of storage capacity \| Bcf	14
Number of reportable segments \| Segment	4
Enterprise Products Partners L.P. [Member]
Related Party Transaction [Line Items]
Limited partners ownership interest	100.00%
EPCO and its privately held affiliates [Member]
Related Party Transaction [Line Items]
Percentage of Total Units Outstanding	31.90%

Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash, Cash Equivalents and Restricted Cash:
Cash and cash equivalents	$ 344.8	$ 5.1
Restricted cash	65.3	65.2
Total cash, cash equivalents and restricted cash shown in the Statements of Consolidated Cash Flows	410.1	70.3	$ 417.6	$ 34.9
Allowance for Doubtful Accounts [Member]
Movement in valuation allowances and reserves [Roll Forward]
Balance at beginning of period	12.1	11.3	12.1
Charged to costs and expenses	0.7	2.7	2.3
Deductions	(1.3)	(1.9)	(3.1)
Balance at end of period	$ 11.5	$ 12.1	$ 11.3
Minor Investment [Member] \| Minimum [Member]
Consolidation Policy [Abstract]
Equity method of ownership interest	3.00%
Minor Investment [Member] \| Maximum [Member]
Consolidation Policy [Abstract]
Equity method of ownership interest	50.00%
Major Investment [Member] \| Minimum [Member]
Consolidation Policy [Abstract]
Equity method of ownership interest	20.00%
Major Investment [Member] \| Maximum [Member]
Consolidation Policy [Abstract]
Equity method of ownership interest	50.00%
Initial Margin Requirement [Member]
Cash, Cash Equivalents and Restricted Cash:
Restricted cash	$ 69.6
Variation Margin Requirement [Member]
Cash, Cash Equivalents and Restricted Cash:
Restricted cash	$ (4.3)

Summary of Significant Accounting Policies, Part 2 (Details)	12 Months Ended
	Dec. 31, 2018
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, 2018	Dec. 31, 2017	Dec. 31, 2016	Jan. 02, 2019
Environmental Costs [Abstract]
Environmental reserves - current portion	$ 3.2	$ 5.6
Forecast [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating Lease, Right-of-Use Asset				$ 250.0
Operating Lease, Liability				$ 250.0
Environmental Reserves [Member]
Movement in valuation allowances and reserves [Roll Forward]
Balance at beginning of period	11.6	11.9	$ 13.0
Charged to costs and expenses	8.2	12.1	7.0
Acquisition-related additions and other	1.7	1.7	0.5
Deductions	(14.6)	(14.1)	(8.6)
Balance at end of period	$ 6.9	$ 11.6	$ 11.9
Minimum [Member]
Impairment Testing for Goodwill [Abstract]
Reporting unit, percentage of fair value in excess of carrying amount	10.00%
Accounting Standards Update 2016-02 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New accounting pronouncement or change in accounting principle, description of financial statement line items	less than 1% of our total consolidated assets and liabilities

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Inventory by Product Type [Abstract]

NGLs

$ 647.7

$ 917.4

Petrochemicals and refined products

264.7

161.5

Crude oil

593.4

516.3

Natural gas

16.3

14.6

Total

1,522.1

1,609.8

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

Cost of sales

^[1]

26,789.8

21,487.0

$ 15,710.9

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

$ 11.5

$ 9.1

$ 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, 2018

Dec. 31, 2017

Dec. 31, 2016

Property, plant and equipment and accumulated depreciation [Abstract]

Less accumulated depreciation

$ 50,897.2

$ 46,545.2

12,159.6

10,924.8

Summary of depreciation expense and capitalized interest [Abstract]

38,737.6

35,620.4

$ 33,292.5

Depreciation expense

^[1]

1,436.2

1,296.1

1,215.7

Capitalized interest

^[2]

147.9

192.1

168.2

Asset Retirement Obligations [Roll Forward]

ARO liability beginning balance

86.7

85.4

58.5

Liabilities incurred

24.4

4.7

4.2

Liabilities settled

(2.5)

(2.2)

(5.7)

Revisions in estimated cash flows

11.5

(6.7)

24.6

Accretion expense

6.2

5.5

3.8

ARO liability ending balance

126.3

86.7

$ 85.4

Capitalized costs, asset retirement costs

72.5

39.9

Forecasted accretion expense [Abstract]

8.1

8.6

9.0

9.6

10.3

Plants, pipelines and facilities [Member]

Property, plant and equipment and accumulated depreciation [Abstract]

Plants, pipelines and facilities [Member] | Minimum [Member]

^[3]

$ 42,371.0

37,132.2

Property, plant and equipment and accumulated depreciation [Abstract]

Plants, pipelines and facilities [Member] | Maximum [Member]

^[3],[4]

3 years

Property, plant and equipment and accumulated depreciation [Abstract]

Underground and other storage facilities [Member]

^[3],[4]

45 years

Property, plant and equipment and accumulated depreciation [Abstract]

Underground and other storage facilities [Member] | Minimum [Member]

^[5]

$ 3,624.2

3,460.9

Property, plant and equipment and accumulated depreciation [Abstract]

Underground and other storage facilities [Member] | Maximum [Member]

^[5],[6]

5 years

Property, plant and equipment and accumulated depreciation [Abstract]

Transportation equipment [Member]

^[5],[6]

40 years

Property, plant and equipment and accumulated depreciation [Abstract]

Transportation equipment [Member] | Minimum [Member]

^[7]

$ 187.1

177.1

Property, plant and equipment and accumulated depreciation [Abstract]

Transportation equipment [Member] | Maximum [Member]

^[7]

3 years

Property, plant and equipment and accumulated depreciation [Abstract]

Property, plant and equipment and accumulated depreciation [Abstract]

^[7]

10 years

Marine vessels [Member]

Marine vessels [Member] | Minimum [Member]

^[8]

$ 828.6

803.8

Property, plant and equipment and accumulated depreciation [Abstract]

Marine vessels [Member] | Maximum [Member]

^[8]

15 years

Property, plant and equipment and accumulated depreciation [Abstract]

Property, plant and equipment and accumulated depreciation [Abstract]

^[8]

30 years

Land [Member]

Construction in progress [Member]

$ 359.5

273.1

Property, plant and equipment and accumulated depreciation [Abstract]

Processing plants [Member] | Minimum [Member]

$ 3,526.8

$ 4,698.1

Property, plant and equipment and accumulated depreciation [Abstract]

Processing plants [Member] | Maximum [Member]

20 years

Property, plant and equipment and accumulated depreciation [Abstract]

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

35 years

Property, plant and equipment and accumulated depreciation [Abstract]

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

5 years

Property, plant and equipment and accumulated depreciation [Abstract]

Terminal facilities [Member] | Minimum [Member]

45 years

Property, plant and equipment and accumulated depreciation [Abstract]

Terminal facilities [Member] | Maximum [Member]

10 years

Property, plant and equipment and accumulated depreciation [Abstract]

Buildings [Member] | Minimum [Member]

35 years

Property, plant and equipment and accumulated depreciation [Abstract]

Buildings [Member] | Maximum [Member]

20 years

Property, plant and equipment and accumulated depreciation [Abstract]

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

40 years

Property, plant and equipment and accumulated depreciation [Abstract]

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

3 years

Property, plant and equipment and accumulated depreciation [Abstract]

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

20 years

Property, plant and equipment and accumulated depreciation [Abstract]

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

5 years

Property, plant and equipment and accumulated depreciation [Abstract]

Underground storage facilities [Member] | Minimum [Member]

35 years

Property, plant and equipment and accumulated depreciation [Abstract]

Underground storage facilities [Member] | Maximum [Member]

5 years

Property, plant and equipment and accumulated depreciation [Abstract]

Storage tanks [Member] | Minimum [Member]

35 years

Property, plant and equipment and accumulated depreciation [Abstract]

Storage tanks [Member] | Maximum [Member]

10 years

Property, plant and equipment and accumulated depreciation [Abstract]

Water wells [Member] | Minimum [Member]

40 years

Property, plant and equipment and accumulated depreciation [Abstract]

Water wells [Member] | Maximum [Member]

5 years

Property, plant and equipment and accumulated depreciation [Abstract]

Schedule of Equity Method Investments [Line Items]

35 years

[1]	Depreciation expense is a component of "Costs and expenses" as presented on our Statements of Consolidated Operations.
[2]	Capitalized interest is a component of "Interest expense" as presented on our Statements of Consolidated Operations.
[3]	Plants, pipelines and facilities include processing plants; NGL, natural gas, crude oil and petrochemical and refined products pipelines; terminal loading and unloading facilities; buildings; office furniture and equipment; laboratory and shop equipment and related assets. We placed a number of growth projects into service since December 31, 2017 including a propane dehydrogenation facility at our Mont Belvieu complex, the first two processing trains at our Orla natural gas processing facility, and a ninth NGL fractionator in Chambers County, Texas at our Mont Belvieu NGL fractionation complex.
[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, Other (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Mar. 29, 2018
Assets acquired:
Capital expenditures	$ 4,223.2	$ 3,101.8	$ 2,984.1
Common units issued in connection with land acquisition (in units)	1,223,242
Sale of Assets:
Proceeds from asset sales	$ 161.2	40.1	46.5
Gains attributable to asset sales	28.7	10.7	2.5
Land [Member]
Assets acquired:
Property, plant and equipment, additions	85.2
Capital expenditures	55.2
Red River System [Member]
Sale of Assets:
Proceeds from asset sales	134.9	0.0	0.0
Gains attributable to asset sales	$ 20.6	$ 0.0	$ 0.0
Delaware Basin Gas Processing LLC [Member]
Business Acquisition [Line Items]
Remaining membership interest acquired				50.00%
Assets acquired:
Property, plant, and equipment				$ 200.0

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Mar. 29, 2018

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

$ 2,615.1

$ 2,659.4

$ 2,677.3

Equity in income (loss) of unconsolidated affiliates

480.0

426.0

362.0

Unamortized excess cost amounts by business segment:

Equity method investment amortization of excess cost

40.8

42.9

2.1

Forecasted amortization of excess cost amounts - 2019

2.1

Forecasted amortization of excess cost amounts - 2020

2.1

Forecasted amortization of excess cost amounts - 2021

2.1

Forecasted amortization of excess cost amounts - 2022

2.1

Forecasted amortization of excess cost amounts - 2023

2.1

Balance Sheet Data:

Current assets

350.2

288.8

Total liabilities and combined equity

5,359.1

5,509.7

Other assets

80.4

71.2

Total assets

5,789.7

5,869.7

Current liabilities

220.6

233.5

Other liabilities

77.9

84.8

Combined equity

5,491.2

5,551.4

5,789.7

5,869.7

Income Statement Data:

1,721.3

1,509.0

1,342.0

1,074.6

925.9

786.7

NGL Pipelines & Services [Member]

1,069.1

929.5

781.7

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

Equity in income (loss) of unconsolidated affiliates

117.0

73.4

61.4

Unamortized excess cost amounts by business segment:

NGL Pipelines & Services [Member] | Venice Energy Service Company, L.L.C. [Member]

$ 21.7

22.9

Schedule of Equity Method Investments [Line Items]

13.10%

NGL Pipelines & Services [Member] | K/D/S Promix, L.L.C. [Member]

$ 24.1

25.7

Schedule of Equity Method Investments [Line Items]

50.00%

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

$ 28.9

30.9

Schedule of Equity Method Investments [Line Items]

32.20%

NGL Pipelines & Services [Member] | Skelly-Belvieu Pipeline Company, L.L.C. [Member]

$ 16.3

17.0

Schedule of Equity Method Investments [Line Items]

50.00%

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

$ 35.6

37.0

Schedule of Equity Method Investments [Line Items]

35.00%

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

$ 337.6

314.4

Schedule of Equity Method Investments [Line Items]

45.00%

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

$ 43.6

35.9

Schedule of Equity Method Investments [Line Items]

33.30%

NGL Pipelines & Services [Member] | Delaware Basin Gas Processing LLC [Member]

$ 175.9

165.7

Schedule of Equity Method Investments [Line Items]

100.00%

Remaining membership interest acquired

^[1]

$ 0.0

107.3

50.00%

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

Equity in income (loss) of unconsolidated affiliates

365.4

358.4

311.9

Unamortized excess cost amounts by business segment:

Crude Oil Pipelines & Services [Member] | Seaway Crude Pipeline Company LLC [Member]

$ 17.4

18.2

Schedule of Equity Method Investments [Line Items]

50.00%

Crude Oil Pipelines & Services [Member] | Eagle Ford Pipeline LLC [Member]

$ 1,369.7

1,378.9

Schedule of Equity Method Investments [Line Items]

50.00%

Crude Oil Pipelines & Services [Member] | Eagle Ford Terminals Corpus Christi LLC [Member]

$ 388.7

385.2

Schedule of Equity Method Investments [Line Items]

50.00%

$ 109.1

75.1

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

Equity in income (loss) of unconsolidated affiliates

$ 6.8

3.8

Natural Gas Pipelines & Services [Member] | White River Hub, LLC [Member]

Schedule of Equity Method Investments [Line Items]

50.00%

Natural Gas Pipelines & Services [Member] | Old Ocean Pipeline, LLC [Member]

$ 20.1

20.8

Schedule of Equity Method Investments [Line Items]

50.00%

$ 2.7

0.0

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

Equity in income (loss) of unconsolidated affiliates

^[2]

(9.2)

(9.6)

$ (15.1)

Unamortized excess cost amounts by business segment:

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

$ 1.7

1.8

Schedule of Equity Method Investments [Line Items]

50.00%

Petrochemical & Refined Products Services [Member] | Baton Rouge Propylene Concentrator, LLC [Member]

$ 59.1

60.8

Schedule of Equity Method Investments [Line Items]

30.00%

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

$ 3.2

4.1

Schedule of Equity Method Investments [Line Items]

25.00%

$ 0.5

$ 0.6

[1]	In March 2018, we acquired the remaining 50% membership interest in our Delaware Processing joint venture. See Note 12 for information regarding this acquisition.
[2]	Losses are primarily attributable to our investment in Centennial. As a result of a trend in declining earnings, we estimated the fair value of this equity-method investment during each of the last three fiscal years. Our estimates, based on a combination of market and income approaches, indicate that the fair value of this investment remains in excess of its carrying value.

Investments in Unconsolidated Affiliates, Descriptions (Details)	12 Months Ended
	Dec. 31, 2018
NGL Pipelines & Services [Member] \| Venice Energy Service Company, L.L.C. [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Description of Principal Activities	VESCO owns a natural gas processing facility in south Louisiana and a related gathering system that gathers natural gas from certain offshore developments for delivery to its natural gas processing facility.
NGL Pipelines & Services [Member] \| K/D/S Promix, L.L.C. [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Description of Principal Activities	Promix owns an NGL fractionation facility located in south Louisiana. The facility receives mixed NGLs via pipeline from natural gas processing plants located in southern Louisiana and along the Mississippi Gulf Coast. In addition, Promix owns an NGL gathering system that gathers mixed NGLs from processing plants in southern Louisiana for its fractionator.
NGL Pipelines & Services [Member] \| Baton Rouge Fractionators LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Description of Principal Activities	BRF owns an NGL fractionation facility located in south Louisiana that receives mixed NGLs from natural gas processing plants located in Alabama, Mississippi and southern Louisiana. In addition, BRF leases an NGL storage cavern.
NGL Pipelines & Services [Member] \| Skelly-Belvieu Pipeline Company, L.L.C. [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Description of Principal Activities	Skelly-Belvieu owns a pipeline that transports mixed NGLs from Skellytown, Texas to Mont Belvieu, Texas. The Skelly-Belvieu Pipeline receives NGLs through a pipeline interconnect with our Mid-America Pipeline System in Skellytown.
NGL Pipelines & Services [Member] \| Texas Express Pipeline LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Description of Principal Activities	Texas Express owns an NGL pipeline that extends from Skellytown to our NGL fractionation and storage complex in Mont Belvieu. Mixed NGLs from the Rocky Mountains, Permian Basin and Mid-Continent regions are delivered to the Texas Express Pipeline via an interconnect with our Mid-America Pipeline System near Skellytown. The pipeline also transports mixed NGLs from two gathering systems owned by TEG to Mont Belvieu. In addition, mixed NGLs from the Denver-Julesburg Basin in Colorado are transported to the Texas Express Pipeline using the Front Range Pipeline.
NGL Pipelines & Services [Member] \| Texas Express Gathering LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Description of Principal Activities	TEG owns two NGL gathering systems that deliver mixed NGLs to the Texas Express Pipeline. The Elk City gathering system gathers mixed NGLs from natural gas processing plants in the Anadarko/Granite Wash production area located in the Texas Panhandle and western Oklahoma. The North Texas gathering system gathers mixed NGLs from natural gas processing plants in the Barnett Shale production area in North Texas.
NGL Pipelines & Services [Member] \| Front Range Pipeline LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Description of Principal Activities	Front Range owns an NGL pipeline that transports mixed NGLs from natural gas processing plants located in the Denver-Julesburg Basin to an interconnect with our Texas Express Pipeline and Mid-America Pipeline System and other third party facilities in Skellytown.
Crude Oil Pipelines & Services [Member] \| Seaway Crude Pipeline Company LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Description of Principal Activities	Seaway owns a pipeline system that connects the Cushing, Oklahoma crude oil hub with markets in Southeast Texas. The Seaway Pipeline is comprised of the Longhaul System, the Freeport System and the Texas City System. The Cushing hub is a major industry trading hub and price settlement point for West Texas Intermediate on the NYMEX. The Longhaul System, which consists of two pipelines, provides north-to-south transportation of crude oil from the Cushing hub to Seaway’s Jones Creek terminal near Freeport, Texas and a terminal that we own located near Katy, Texas. The Freeport System consists of a marine import and export dock, three pipelines and other related facilities that transport crude oil to and from Freeport and the Jones Creek terminal. The Texas City System consists of a marine import and export dock, storage tanks, various pipelines and other related facilities that transport crude oil to refineries in the Texas City, Texas area and to and from terminals in the Galena Park area, our Enterprise Crude Houston (“ECHO”) terminal and locations along the Houston Ship Channel. The Texas City System also receives production from certain offshore Gulf of Mexico developments.
Crude Oil Pipelines & Services [Member] \| Eagle Ford Pipeline LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Description of Principal Activities	Eagle Ford Crude Oil Pipeline owns a crude oil pipeline that transports crude oil and condensate for producers in South Texas. The system consists of a crude oil and condensate pipeline system originating in Gardendale, Texas in LaSalle County to Three Rivers, Texas in Live Oak County and extending to Corpus Christi, Texas. The system also includes a pipeline segment that interconnects with our South Texas Crude Oil Pipeline System in Wilson County. This system includes a marine terminal facility in Corpus Christi and storage capacity across the system.
Crude Oil Pipelines & Services [Member] \| Eagle Ford Terminals Corpus Christi LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Description of Principal Activities	Eagle Ford Corpus Christi is a joint venture formed in March 2015 to construct and operate a new deep-water marine crude oil terminal that is designed to handle a variety of ocean-going vessels. The new terminal is expected to be placed into service during the second quarter of 2019.
Natural Gas Pipelines & Services [Member] \| White River Hub, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Description of Principal Activities	White River Hub owns a natural gas hub facility serving producers in the Piceance Basin of northwest Colorado. The facility enables producers to access six interstate natural gas pipelines.
Natural Gas Pipelines & Services [Member] \| Old Ocean Pipeline, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Description of Principal Activities	Old Ocean was formed in May 2018 with Energy Transfer Partners, L.P. (“ETP”) to facilitate the resumption of full service on the Old Ocean natural gas pipeline owned by ETP. The 24-inch diameter Old Ocean Pipeline originates in Maypearl, Texas in Ellis County and extends south approximately 240 miles to Sweeny, Texas in Brazoria County. ETP serves as operator of the pipeline.
Petrochemical & Refined Products Services [Member] \| Centennial Pipeline LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Description of Principal Activities	Centennial owns an interstate refined products pipeline that extends from Beaumont, Texas, to Bourbon, Illinois. Centennial also owns a refined products storage terminal located near Creal Springs, Illinois.
Petrochemical & Refined Products Services [Member] \| Baton Rouge Propylene Concentrator, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Description of Principal Activities	BRPC owns a propylene fractionation facility located in south Louisiana that fractionates refinery grade propylene into chemical grade propylene.
Petrochemical & Refined Products Services [Member] \| Transport 4, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Description of Principal Activities	Transport 4 provides pipeline and terminal logistics services used by our refined products pipelines.

Intangible Assets and Goodwill, Intangible Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Identifiable intangible assets [Abstract]
Gross Value	$ 5,343.5	$ 5,255.1
Accumulated Amortization	(1,735.1)	(1,564.8)
Carrying Value	3,608.4	3,690.3	$ 3,864.1
Amortization expense	170.3	166.9	171.3
Forecasted amortization expense [Abstract]
2019	167.1
2020	159.8
2021	162.1
2022	167.6
2023	167.8
Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Carrying Value	3,320.0
Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Carrying Value	291.5
NGL Pipelines & Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	820.7	728.2
Accumulated Amortization	(440.6)	(405.9)
Carrying Value	380.1	322.3
Amortization expense	34.7	28.9	30.6
NGL Pipelines & Services [Member] \| Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	457.3	447.4
Accumulated Amortization	(201.9)	(187.5)
Carrying Value	255.4	259.9
NGL Pipelines & Services [Member] \| Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	363.4	280.8
Accumulated Amortization	(238.7)	(218.4)
Carrying Value	124.7	62.4
Crude Oil Pipelines & Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	2,480.4	2,484.5
Accumulated Amortization	(385.8)	(298.0)
Carrying Value	2,094.6	2,186.5
Amortization expense	87.8	92.5	98.4
Crude Oil Pipelines & Services [Member] \| Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	2,203.5	2,203.5
Accumulated Amortization	(174.1)	(127.0)
Carrying Value	2,029.4	2,076.5
Crude Oil Pipelines & Services [Member] \| Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	276.9	281.0
Accumulated Amortization	(211.7)	(171.0)
Carrying Value	65.2	110.0
Natural Gas Pipelines & Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	1,815.0	1,815.0
Accumulated Amortization	(835.7)	(796.6)
Carrying Value	979.3	1,018.4
Amortization expense	39.1	36.2	33.2
Natural Gas Pipelines & Services [Member] \| Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	1,350.3	1,350.3
Accumulated Amortization	(447.8)	(417.1)
Carrying Value	902.5	933.2
Natural Gas Pipelines & Services [Member] \| Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	464.7	464.7
Accumulated Amortization	(387.9)	(379.5)
Carrying Value	76.8	85.2
Petrochemical & Refined Products Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	227.4	227.4
Accumulated Amortization	(73.0)	(64.3)
Carrying Value	154.4	163.1
Amortization expense	8.7	9.3	$ 9.1
Petrochemical & Refined Products Services [Member] \| Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	181.4	181.4
Accumulated Amortization	(51.8)	(45.9)
Carrying Value	129.6	135.5
Petrochemical & Refined Products Services [Member] \| Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	46.0	46.0
Accumulated Amortization	(21.2)	(18.4)
Carrying Value	$ 24.8	$ 27.6

Intangible Assets and Goodwill, Significant Intangible Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Identifiable intangible assets [Abstract]
Gross Value	$ 5,343.5	$ 5,255.1
Accumulated Amortization	(1,735.1)	(1,564.8)
Carrying Value	3,608.4	$ 3,690.3	$ 3,864.1
Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Carrying Value	3,320.0
Customer relationship intangibles [Member] \| EFS Midstream [Member]
Identifiable intangible assets [Abstract]
Gross Value	1,409.8
Accumulated Amortization	(117.0)
Carrying Value	$ 1,292.8
Weighted Average Remaining Amortization Period	23 years 4 months 24 days
Customer relationship intangibles [Member] \| State Line and Fairplay [Member]
Identifiable intangible assets [Abstract]
Gross Value	$ 895.0
Accumulated Amortization	(183.2)
Carrying Value	$ 711.8
Weighted Average Remaining Amortization Period	28 years 2 months 12 days
Customer relationship intangibles [Member] \| San Juan Gathering [Member]
Identifiable intangible assets [Abstract]
Gross Value	$ 331.3
Accumulated Amortization	(227.7)
Carrying Value	$ 103.6
Weighted Average Remaining Amortization Period	20 years 9 months 18 days
Customer relationship intangibles [Member] \| Encinal [Member]
Identifiable intangible assets [Abstract]
Gross Value	$ 132.9
Accumulated Amortization	(103.5)
Carrying Value	$ 29.4
Weighted Average Remaining Amortization Period	8 years
Customer relationship intangibles [Member] \| Oiltanking Partners L.P. [Member]
Identifiable intangible assets [Abstract]
Gross Value	$ 1,192.5
Accumulated Amortization	(86.1)
Carrying Value	$ 1,106.4
Weighted Average Remaining Amortization Period	25 years
Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Carrying Value	$ 291.5
Contract-based intangibles [Member] \| Oiltanking Partners L.P. [Member]
Identifiable intangible assets [Abstract]
Gross Value	293.3
Accumulated Amortization	(221.1)
Carrying Value	$ 72.2
Weighted Average Remaining Amortization Period	4 years
Contract-based intangibles [Member] \| Jonah Gas Gathering [Member]
Identifiable intangible assets [Abstract]
Gross Value	$ 224.4
Accumulated Amortization	(166.3)
Carrying Value	$ 58.1
Weighted Average Remaining Amortization Period	23 years
Contract-based intangibles [Member] \| Delaware Basin Gas Processing LLC [Member]
Identifiable intangible assets [Abstract]
Gross Value	$ 82.6
Accumulated Amortization	(6.4)
Carrying Value	$ 76.2
Weighted Average Remaining Amortization Period	8 years

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Other, non-principal amounts

$ 26,420,600

$ 24,780,100

(242,400)

(211,400)

Less current maturities of debt

(1,500,100)

(2,855,000)

Total long-term debt

24,678,100

21,713,700

Repayment of debt obligations

77,957,100

68,459,600

$ 61,672,600

Letters of credit outstanding for facilities and motor fuel tax obligations

101,400

Senior Debt Obligations [Member]

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

23,750,000

21,605,700

$ 0

1,755,700

Maximum borrowing capacity

variable

$ 3,000,000

2,500,000

Information regarding variable interest rates paid:

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

2.24%

Information regarding variable interest rates paid:

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

1.50%

Information regarding variable interest rates paid:

Senior Debt Obligations [Member] | EPO Senior Notes V [Member]

2.50%

$ 0

349,700

fixed

6.65%

Senior Debt Obligations [Member] | EPO Senior Notes OO [Member]

Apr. 15, 2018

$ 0

750,000

fixed

1.65%

Senior Debt Obligations [Member] | EPO Senior Notes N [Member]

May 07, 2018

$ 700,000

700,000

fixed

6.50%

Senior Debt Obligations [Member] | EPO 364-Day Revolving Credit Agreement [Member]

Jan. 31, 2019

$ 0

variable

Maximum borrowing capacity

Sep. 11, 2019

$ 2,000,000

Maximum bank commitments increase

200,000

Total maximum borrowing capacity

2,200,000

Senior Debt Obligations [Member] | EPO Senior Notes LL [Member]

$ 800,000

800,000

fixed

2.55%

Senior Debt Obligations [Member] | EPO Senior Notes Q [Member]

Oct. 15, 2019

$ 500,000

500,000

fixed

5.25%

Senior Debt Obligations [Member] | EPO Senior Notes Y [Member]

Jan. 31, 2020

$ 1,000,000

1,000,000

fixed

5.20%

Senior Debt Obligations [Member] | EPO Senior Notes TT [Member]

Sep. 01, 2020

$ 750,000

fixed

2.80%

Feb. 15, 2021

$ 750,000

Senior Debt Obligations [Member] | EPO Senior Notes RR [Member]

99.946%

$ 575,000

575,000

fixed

2.85%

Senior Debt Obligations [Member] | EPO Senior Notes VV [Member]

Apr. 15, 2021

$ 750,000

fixed

3.50%

Feb. 01, 2022

$ 750,000

Senior Debt Obligations [Member] | EPO Senior Notes CC [Member]

99.985%

$ 650,000

650,000

fixed

4.05%

Senior Debt Obligations [Member] | EPO Multi-Year Revolving Credit Facility [Member]

Feb. 15, 2022

$ 0

variable

Maximum borrowing capacity

Sep. 13, 2022

$ 4,000,000

Maximum bank commitments increase

500,000

Total maximum borrowing capacity

$ 4,500,000

Information regarding variable interest rates paid:

Senior Debt Obligations [Member] | EPO Multi-Year Revolving Credit Facility [Member] | Minimum [Member]

3.37%

Information regarding variable interest rates paid:

Senior Debt Obligations [Member] | EPO Multi-Year Revolving Credit Facility [Member] | Maximum [Member]

2.58%

Information regarding variable interest rates paid:

Senior Debt Obligations [Member] | EPO Senior Notes HH [Member]

5.00%

$ 1,250,000

1,250,000

fixed

3.35%

Senior Debt Obligations [Member] | EPO Senior Notes JJ [Member]

Mar. 15, 2023

$ 850,000

850,000

fixed

3.90%

Senior Debt Obligations [Member] | EPO Senior Notes MM [Member]

Feb. 15, 2024

$ 1,150,000

1,150,000

fixed

3.75%

Senior Debt Obligations [Member] | EPO Senior Notes PP [Member]

Feb. 15, 2025

$ 875,000

875,000

fixed

3.70%

Senior Debt Obligations [Member] | EPO Senior Notes SS [Member]

Feb. 15, 2026

$ 575,000

575,000

fixed

3.95%

Senior Debt Obligations [Member] | EPO Senior Notes WW [Member]

Feb. 15, 2027

$ 1,000,000

fixed

4.15%

Oct. 16, 2028

$ 1,000,000

Senior Debt Obligations [Member] | EPO Senior Notes D [Member]

99.764%

$ 500,000

500,000

fixed

6.875%

Senior Debt Obligations [Member] | EPO Senior Notes H [Member]

Mar. 01, 2033

$ 350,000

350,000

fixed

6.65%

Senior Debt Obligations [Member] | EPO Senior Notes J [Member]

Oct. 15, 2034

$ 250,000

250,000

fixed

5.75%

Senior Debt Obligations [Member] | EPO Senior Notes W [Member]

Mar. 01, 2035

$ 399,600

399,600

fixed

7.55%

Senior Debt Obligations [Member] | EPO Senior Notes R [Member]

Apr. 15, 2038

$ 600,000

600,000

fixed

6.125%

Senior Debt Obligations [Member] | EPO Senior Notes Z [Member]

Oct. 15, 2039

$ 600,000

600,000

fixed

6.45%

Senior Debt Obligations [Member] | EPO Senior Notes BB [Member]

Sep. 01, 2040

$ 750,000

750,000

fixed

5.95%

Senior Debt Obligations [Member] | EPO Senior Notes DD [Member]

Feb. 01, 2041

$ 600,000

600,000

fixed

5.70%

Senior Debt Obligations [Member] | EPO Senior Notes EE [Member]

Feb. 15, 2042

$ 750,000

750,000

fixed

4.85%

Senior Debt Obligations [Member] | EPO Senior Notes GG [Member]

Aug. 15, 2042

$ 1,100,000

1,100,000

fixed

4.45%

Senior Debt Obligations [Member] | EPO Senior Notes II [Member]

Feb. 15, 2043

$ 1,400,000

1,400,000

fixed

4.85%

Senior Debt Obligations [Member] | EPO Senior Notes KK [Member]

Mar. 15, 2044

$ 1,150,000

1,150,000

fixed

5.10%

Senior Debt Obligations [Member] | EPO Senior Notes QQ [Member]

Feb. 15, 2045

$ 975,000

975,000

fixed

4.90%

Senior Debt Obligations [Member] | EPO Senior Notes UU [Member]

May 15, 2046

$ 1,250,000

fixed

4.25%

Feb. 15, 2048

$ 1,250,000

Senior Debt Obligations [Member] | EPO Senior Notes XX [Member]

99.865%

$ 1,250,000

fixed

4.80%

Feb. 01, 2049

$ 1,250,000

Senior Debt Obligations [Member] | EPO Senior Notes NN [Member]

99.39%

$ 400,000

400,000

fixed

4.95%

Senior Debt Obligations [Member] | TEPPCO Senior Notes 4 [Member]

Oct. 15, 2054

$ 0

300

fixed

6.65%

Senior Debt Obligations [Member] | TEPPCO Senior Notes 5 [Member]

Apr. 15, 2018

$ 400

400

fixed

7.55%

Junior Debt Obligations [Member]

Apr. 15, 2038

Junior Debt Obligations [Member] | EPO Junior Subordinated Notes A [Member]

$ 700,000

1,700,000

$ 0

521,100

Repayment of debt obligations

variable

$ 521,100

Information regarding variable interest rates paid:

Junior Debt Obligations [Member] | EPO Junior Subordinated Notes A [Member] | Minimum [Member]

5.71%

Information regarding variable interest rates paid:

Junior Debt Obligations [Member] | EPO Junior Subordinated Notes A [Member] | Maximum [Member]

5.08%

Information regarding variable interest rates paid:

Junior Debt Obligations [Member] | EPO Junior Subordinated Notes C [Member]

6.07%

^[1]

$ 256,400

256,400

variable

7.00%

Variable annual interest rate thereafter, variable rate basis

Jun. 01, 2067

3-month LIBOR

Information regarding variable interest rates paid:

2.778%

Junior Debt Obligations [Member] | EPO Junior Subordinated Notes C [Member] | Minimum [Member]

4.91%

Information regarding variable interest rates paid:

Junior Debt Obligations [Member] | EPO Junior Subordinated Notes C [Member] | Maximum [Member]

4.26%

Information regarding variable interest rates paid:

Junior Debt Obligations [Member] | EPO Junior Subordinated Notes B [Member]

5.52%

$ 0

682,700

Repayment of debt obligations

fixed/variable

$ 682,700

Information regarding variable interest rates paid:

Junior Debt Obligations [Member] | EPO Junior Subordinated Notes B [Member] | Minimum [Member]

7.03%

Information regarding variable interest rates paid:

Junior Debt Obligations [Member] | EPO Junior Subordinated Notes B [Member] | Maximum [Member]

7.03%

Information regarding variable interest rates paid:

Junior Debt Obligations [Member] | EPO Junior Subordinated Notes D [Member]

7.03%

^[2]

$ 700,000

700,000

fixed/variable

4.875%

Variable annual interest rate thereafter, variable rate basis

Aug. 16, 2077

3-month LIBOR

Junior Debt Obligations [Member] | EPO Junior Subordinated Notes E [Member]

2.986%

^[3]

$ 1,000,000

1,000,000

fixed/variable

5.25%

Variable annual interest rate thereafter, variable rate basis

Aug. 16, 2077

3-month LIBOR

Junior Debt Obligations [Member] | EPO Junior Subordinated Notes F [Member]

3.033%

^[4]

$ 700,000

fixed/variable

5.375%

Feb. 15, 2078

$ 700,000

Variable annual interest rate thereafter, variable rate basis

100.00%

3-month LIBOR

Junior Debt Obligations [Member] | TEPPCO Junior Subordinated Notes [Member]

2.57%

$ 14,200

variable

Jun. 01, 2067

Senior Notes [Member]

$ 23,750,000

Accumulated Other Comprehensive Income (Loss) [Abstract]

$ 5,000,000

$ 1,250,000

[1]	Variable rate is reset quarterly and based on 3-month 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, 2018	Dec. 31, 2017
Scheduled Maturities of Debt [Abstract]
2019	$ 1,500.0
2020	1,500.0
2021	1,325.0
2022	1,400.0
2023	1,250.0
Thereafter	19,445.6
Total	26,420.6	$ 24,780.1
Senior Notes [Member]
Scheduled Maturities of Debt [Abstract]
2019	1,500.0
2020	1,500.0
2021	1,325.0
2022	1,400.0
2023	1,250.0
Thereafter	16,775.0
Total	23,750.0
Junior Subordinated Notes [Member]
Scheduled Maturities of Debt [Abstract]
2019	0.0
2020	0.0
2021	0.0
2022	0.0
2023	0.0
Thereafter	2,670.6
Total	$ 2,670.6

Equity and Distributions, Summary of Changes in Outstanding Units (Details) - shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Summary of changes in outstanding units [Roll Forward]
Beginning Balance (in units)	2,161,089,479	2,117,588,414	2,012,553,024
Common units issued in connection with ATM program (in units)		21,807,726	87,867,037
Common units issued in connection with DRIP and EUPP (in units)	19,861,951	19,046,019	16,316,534
Common units issued in connection with the vesting of phantom unit awards (in units)	3,479,958	2,485,580	1,761,455
Common units issues in connection with the vesting of restricted common unit awards (in units)		0	0
Forfeiture of restricted common unit awards (in units)		(1,250)	(43,724)
Cancellation of treasury units acquired in connection with the vesting of equity-based awards (in units)	(1,037,522)	(1,027,798)	(1,000,619)
Common units issued in connection with employee compensation (in units)	1,443,586	1,176,103
Common units issued in connection with land acquisition (in units)	1,223,242
Cancellation of treasury units acquired in connection with buyback program (in units)	(1,236,800)
Other (in units)	45,135	14,685	134,707
Ending Balance (in units)	2,184,869,029	2,161,089,479	2,117,588,414
Common Units (Unrestricted) [Member]
Summary of changes in outstanding units [Roll Forward]
Beginning Balance (in units)	2,161,089,479	2,116,906,120	2,010,592,504
Common units issued in connection with ATM program (in units)		21,807,726	87,867,037
Common units issued in connection with DRIP and EUPP (in units)	19,861,951	19,046,019	16,316,534
Common units issued in connection with the vesting of phantom unit awards (in units)	3,479,958	2,485,580	1,761,455
Common units issues in connection with the vesting of restricted common unit awards (in units)		681,044	1,234,502
Forfeiture of restricted common unit awards (in units)		0	0
Cancellation of treasury units acquired in connection with the vesting of equity-based awards (in units)	(1,037,522)	(1,027,798)	(1,000,619)
Common units issued in connection with employee compensation (in units)	1,443,586	1,176,103
Common units issued in connection with land acquisition (in units)	1,223,242
Cancellation of treasury units acquired in connection with buyback program (in units)	(1,236,800)
Other (in units)	45,135	14,685	134,707
Ending Balance (in units)	2,184,869,029	2,161,089,479	2,116,906,120
Restricted Common Units [Member]
Summary of changes in outstanding units [Roll Forward]
Beginning Balance (in units)	0	682,294	1,960,520
Common units issued in connection with ATM program (in units)		0	0
Common units issued in connection with DRIP and EUPP (in units)	0	0	0
Common units issued in connection with the vesting of phantom unit awards (in units)	0	0	0
Common units issues in connection with the vesting of restricted common unit awards (in units)		(681,044)	(1,234,502)
Forfeiture of restricted common unit awards (in units)		(1,250)	(43,724)
Cancellation of treasury units acquired in connection with the vesting of equity-based awards (in units)	0	0	0
Common units issued in connection with employee compensation (in units)	0	0
Common units issued in connection with land acquisition (in units)	0
Cancellation of treasury units acquired in connection with buyback program (in units)	0
Other (in units)	0	0	0
Ending Balance (in units)	0	0	682,294

Equity and Distributions, Issuances of Equity (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2014	Jan. 31, 2019
Registration Statements and Equity Offerings [Line Items]
Common units issued in connection with acquisition of Oiltanking (in units)					54,807,352
Limited partner interests of Oiltanking acquired					65.90%
Net Cash Proceeds from Sale of Common Units [Abstract]
Net cash proceeds from the issuance of common units		$ 538.4	$ 1,073.4	$ 2,542.8
Common units issued in connection with employee compensation (in units)		1,443,586	1,176,103
Common units issued in connection with employee compensation		$ 39.1	$ 33.7
Treasury Units:
Total of common units repurchased under a buyback program (in units)		1,236,800
Common units acquired in connection with buyback program		$ 30.8
Acquisition of treasury units in connection with vesting of equity-based awards (in units)		1,037,522	1,027,798	1,000,619
Phantom Unit Awards [Member]
Treasury Units:
Phantom units vesting during the period (in units)		3,479,958	2,490,081	1,761,455
Treasury Units [Member]
Treasury Units:
Maximum common units authorized for repurchase under a buyback program (in units)		4,000,000
Total of common units repurchased under a buyback program (in units)		1,236,800
Common units acquired in connection with buyback program		$ 30.8
Average price of treasury units acquired under buyback program (dollars per unit)		$ 24.92
Acquisition of treasury units in connection with vesting of equity-based awards (in units)		1,037,522
Common units acquired in connection with phantom unit awards		$ 27.3
Treasury Units [Member] \| Subsequent Event [Member]
Treasury Units:
Amount authorized under buyback program						$ 2,000.0
Junior Debt Obligations [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Debt issued under universal shelf registration		700.0	$ 1,700.0
Universal Shelf Registration [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Debt issued under universal shelf registration		5,700.0
Universal Shelf Registration [Member] \| Senior Debt Obligations [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Debt issued under universal shelf registration				$ 1,250.0
Universal Shelf Registration [Member] \| Junior Debt Obligations [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Debt issued under universal shelf registration			$ 1,700.0
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]
Number of common units issued (in units)			21,807,726	87,867,037
Gross proceeds from the sale of common units			$ 603.1	$ 2,170.0
Net cash proceeds from the issuance of common units			$ 597.0	$ 2,160.0
Remaining units available for issuance		$ 2,540.0
At-the-Market Registration [Member] \| EPCO and its privately held affiliates [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Number of common units issued (in units)				3,830,256
Gross proceeds from the sale of common units				$ 100.0
Distribution Reinvestment Plan [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Number of common units issued (in units)		19,316,781	18,541,355	15,809,503
Net cash proceeds from the issuance of common units		$ 523.3	$ 462.9	$ 374.0
Distribution reinvestment plan discount rate		2.50%
Remaining units available for issuance (in units)		61,400,359
Distribution Reinvestment Plan [Member] \| Forecast [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Distribution reinvestment plan discount rate	0.00%
Distribution Reinvestment Plan [Member] \| Minimum [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Distribution reinvestment plan discount rate range		0.00%
Distribution Reinvestment Plan [Member] \| Maximum [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Distribution reinvestment plan discount rate range		5.00%
Distribution Reinvestment Plan [Member] \| EPCO and its privately held affiliates [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Gross proceeds from the sale of common units		$ 213.0	100.0	100.0
Net cash proceeds from the issuance of common units		$ 213.0	$ 100.0	$ 100.0
Employee Unit Purchase Plan [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Number of common units issued (in units)		545,170	504,664	507,031
Net cash proceeds from the issuance of common units		$ 15.1	$ 13.5	$ 12.7
Remaining units available for issuance (in units)		5,215,641

Equity and Distributions, Accumulated Other Comprehensive Income (Loss) (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Accumulated Other Comprehensive Income (Loss), Beginning Balance

$ (171.7)

$ (280.0)

$ (171.7)

$ (280.0)

Other comprehensive income (loss) for period, before reclassifications

314.9

(44.3)

Reclassification of losses (gains) to net income during period

(92.3)

152.6

Accumulated Other Comprehensive Income (Loss), Ending balance

222.6

108.3

$ (60.8)

$ 50.9

$ (171.7)

50.9

(171.7)

(280.0)

1,096.7

984.6

982.6

Revenue

(9,182.3)

$ (9,585.9)

$ (8,467.5)

(9,298.5)

(8,426.6)

$ (6,886.9)

$ (6,607.6)

(7,320.4)

(36,534.2)

^[1]

(29,241.5)

^[2]

(23,022.3)

^[2]

Cash Flow Hedges [Member] | Commodity Derivatives [Member]

31,397.3

25,557.5

19,643.5

Total

(1,305.2)

$ (1,334.6)

$ (687.2)

(911.5)

(797.3)

$ (621.3)

$ (666.0)

(771.0)

(4,238.5)

(2,855.6)

(2,553.0)

Accumulated Other Comprehensive Income (Loss) [Abstract]

Accumulated Other Comprehensive Income (Loss), Beginning Balance

(10.1)

(83.8)

(10.1)

(83.8)

Other comprehensive income (loss) for period, before reclassifications

293.2

(38.5)

Reclassification of losses (gains) to net income during period

(130.4)

112.2

Accumulated Other Comprehensive Income (Loss), Ending balance

162.8

73.7

152.7

(10.1)

152.7

(10.1)

(83.8)

Cash Flow Hedges [Member] | Interest Rate Derivatives [Member]

Accumulated Other Comprehensive Income (Loss) [Abstract]

Accumulated Other Comprehensive Income (Loss), Beginning Balance

(165.1)

(199.8)

(165.1)

(199.8)

Other comprehensive income (loss) for period, before reclassifications

22.2

(5.7)

Reclassification of losses (gains) to net income during period

38.1

40.4

Accumulated Other Comprehensive Income (Loss), Ending balance

60.3

34.7

(104.8)

(165.1)

(104.8)

(165.1)

(199.8)

Other [Member]

Accumulated Other Comprehensive Income (Loss) [Abstract]

Accumulated Other Comprehensive Income (Loss), Beginning Balance

$ 3.5

$ 3.6

3.5

3.6

Other comprehensive income (loss) for period, before reclassifications

(0.5)

(0.1)

Reclassification of losses (gains) to net income during period

0.0

Accumulated Other Comprehensive Income (Loss), Ending balance

(0.5)

(0.1)

$ 3.0

$ 3.5

3.0

3.5

$ 3.6

Reclassification out of Accumulated Other Comprehensive Income (Loss) [Member] | Cash Flow Hedges [Member]

Accumulated Other Comprehensive Income (Loss) [Abstract]

Total

(92.3)

152.6

Reclassification out of Accumulated Other Comprehensive Income (Loss) [Member] | Cash Flow Hedges [Member] | Commodity Derivatives [Member]

Accumulated Other Comprehensive Income (Loss) [Abstract]

Revenue

(131.7)

111.6

Reclassification out of Accumulated Other Comprehensive Income (Loss) [Member] | Cash Flow Hedges [Member] | Interest Rate Derivatives [Member]

1.3

0.6

Accumulated Other Comprehensive Income (Loss) [Abstract]

$ 38.1

$ 40.4

[1]	Revenues are accounted for under ASC 606 upon implementation at January 1, 2018.
[2]	Revenues are accounted for under ASC 605 for historical periods prior to January 1, 2018.

Equity and Distributions, Noncontrolling Interests (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($)
Whitehorn Pipeline Company LLC [Member]
Noncontrolling Interest
Noncontrolling Interest, Increase from Sale of Parent Equity Interest	$ 189.6
Western Gas Partners, LP [Member] \| Whitehorn Pipeline Company LLC [Member]
Noncontrolling Interest
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners	20.00%
Navigator Holdings Ltd. [Member] \| Enterprise Navigator Ethylene Terminal LLC [Member]
Noncontrolling Interest
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners	50.00%
Apache Corporation [Member] \| Shin Oak NGL Pipeline [Member] \| Maximum [Member]
Noncontrolling Interest
Percentage Of Option To Purchase Equity Interest	33.00%

Equity and Distributions, Distributions (Details) - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Distributions to Partners [Abstract]
Number of days after quarter end to distribute available cash		45 days
Cash Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)		$ 1.7250
Cash Distribution [Member] \| First Quarter 2016 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)				$ 0.3950
Record Date				Apr. 29, 2016
Payment Date				May 06, 2016
Cash Distribution [Member] \| Second Quarter 2016 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)				$ 0.4000
Record Date				Jul. 29, 2016
Payment Date				Aug. 05, 2016
Cash Distribution [Member] \| Third Quarter 2016 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)				$ 0.4050
Record Date				Oct. 31, 2016
Payment Date				Nov. 07, 2016
Cash Distribution [Member] \| Fourth Quarter 2016 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)				$ 0.4100
Record Date				Jan. 31, 2017
Payment Date				Feb. 07, 2017
Cash Distribution [Member] \| First Quarter 2017 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)			$ 0.4150
Record Date			Apr. 28, 2017
Payment Date			May 08, 2017
Cash Distribution [Member] \| Second Quarter 2017 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)			$ 0.4200
Record Date			Jul. 31, 2017
Payment Date			Aug. 07, 2017
Cash Distribution [Member] \| Third Quarter 2017 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)			$ 0.4225
Record Date			Oct. 31, 2017
Payment Date			Nov. 07, 2017
Cash Distribution [Member] \| Fourth Quarter 2017 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)			$ 0.4250
Record Date			Jan. 31, 2018
Payment Date			Feb. 07, 2018
Cash Distribution [Member] \| First Quarter 2018 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)		$ 0.4275
Record Date		Apr. 30, 2018
Payment Date		May 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] \| Forecast [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)	$ 1.7650
Quarterly increase in cash distribution per unit (in dollars per unit)	$ 0.0025
Forecasted rate of annual increase of distributions per unit	2.30%

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

3 Months Ended

12 Months Ended

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

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

$ 9,182.3

$ 9,585.9

$ 8,467.5

$ 9,298.5

$ 8,426.6

$ 6,886.9

$ 6,607.6

$ 7,320.4

$ 36,534.2

^[1]

$ 29,241.5

^[2]

$ 23,022.3

^[2]

2.00%

Sales of Products [Member] | Revenues [Member]

Concentration risk percentage

84.00%

85.00%

81.00%

Midstream Services [Member] | Revenues [Member]

Concentration risk percentage

16.00%

15.00%

19.00%

NGL Pipelines & Services [Member]

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

$ 15,648.9

^[1]

$ 12,468.0

^[2]

$ 10,242.5

^[2]

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

12,920.9

^[1]

10,521.3

^[2]

8,380.5

^[2]

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

2,728.0

^[1]

1,946.7

^[2]

1,862.0

^[2]

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

1,341.0

^[1]

719.1

^[2]

714.6

^[2]

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

1,007.0

^[1]

891.7

^[2]

885.6

^[2]

380.0

^[1]

335.9

^[2]

261.8

^[2]

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

11,042.6

^[1]

8,156.8

^[2]

6,515.0

^[2]

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

10,001.2

^[1]

7,365.2

^[2]

5,802.5

^[2]

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

1,041.4

^[1]

791.6

^[2]

712.5

^[2]

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

676.5

^[1]

473.9

^[2]

411.1

^[2]

364.9

^[1]

317.7

^[2]

301.4

^[2]

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

3,454.4

^[1]

3,145.6

^[2]

2,543.0

^[2]

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

2,411.7

^[1]

2,238.5

^[2]

1,591.9

^[2]

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

1,042.7

^[1]

907.1

^[2]

951.1

^[2]

1,042.7

^[1]

907.1

^[2]

951.1

^[2]

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

6,388.3

^[1]

5,471.1

^[2]

3,721.8

^[2]

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

5,535.4

^[1]

4,696.3

^[2]

2,921.9

^[2]

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

852.9

^[1]

774.8

^[2]

799.9

^[2]

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

188.3

^[1]

156.3

^[2]

142.6

^[2]

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

481.8

^[1]

430.7

^[2]

456.2

^[2]

Significant Changes in Unbilled Revenue [Roll Forward]

$ 182.8

^[1]

$ 187.8

^[2]

$ 201.1

^[2]

[1]	Revenues are accounted for under ASC 606 upon implementation at January 1, 2018.
[2]	Revenues are accounted for under ASC 605 for historical periods prior to January 1, 2018.

Revenues, Remaining Performance Obligations (Details) - Midstream Services [Member] $ in Millions	Dec. 31, 2018 USD ($)
Remaining Performance Obligation to be Recognized in the Future [Abstract]
Remaining performance obligation	$ 20,592.9
Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Remaining Performance Obligation to be Recognized in the Future [Abstract]
Remaining performance obligation	$ 3,530.6
Expected timing of satisfaction, period	1 year
Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Remaining Performance Obligation to be Recognized in the Future [Abstract]
Remaining performance obligation	$ 3,187.3
Expected timing of satisfaction, period	1 year
Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Remaining Performance Obligation to be Recognized in the Future [Abstract]
Remaining performance obligation	$ 2,641.4
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	$ 2,145.0
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	$ 1,798.7
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	$ 7,289.9
Expected timing of satisfaction, period

Revenues, Unbilled Revenue and Deferred Revenue (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Contracts with Customers, Assets and Liabilities [Abstract]
Unbilled revenue	$ 13.3	$ 0.0
Deferred revenue	291.2	$ 224.7
Other Current Assets [Member]
Contracts with Customers, Assets and Liabilities [Abstract]
Unbilled revenue (current amount)	13.3
Other Current Liabilities [Member]
Contracts with Customers, Assets and Liabilities [Abstract]
Deferred revenue (current amount)	80.9
Other Liabilities [Member]
Contracts with Customers, Assets and Liabilities [Abstract]
Deferred revenue (noncurrent)	$ 210.3

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

12 Months Ended

Dec. 31, 2018

USD ($)

Balance at beginning of period (upon adoption of ASC 606)

$ 0.0

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

0.0

^[1]

Unbilled revenue recorded during period

321.7

Unbilled revenue recorded during period transferred to other accounts

(310.6)

^[1]

Unbilled revenue recorded in connection with business combination

2.2

Other changes

0.0

Balance at end of period

$ 13.3

[1]	Unbilled revenues are transferred to accounts receivable once we have an unconditional right to consideration from the customer. Deferred revenues are recognized as revenue upon satisfaction of our performance obligation to the customer.

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

12 Months Ended

Dec. 31, 2018

USD ($)

Significant Changes in Deferred Revenue [Roll Forward]

Balance at beginning of period (upon adoption of ASC 606)

$ 224.7

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

(90.8)

^[1]

Deferred revenue recorded during period

432.5

Deferred revenue recorded during period transferred to other accounts

(274.8)

^[1]

Deferred revenue recorded in connection with business combination

0.0

Other changes

(0.4)

Balance at end of period

$ 291.2

[1]	Unbilled revenues are transferred to accounts receivable once we have an unconditional right to consideration from the customer. Deferred revenues are recognized as revenue upon satisfaction of our performance obligation to the customer.

Revenues, Impact of Change in Accounting Policy (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Assets [Abstract]

Accounts receivable - trade, net

$ 3,659.1

$ 4,358.4

$ 3,659.1

$ 4,358.4

311.5

312.7

311.5

312.7

38,737.6

35,620.4

38,737.6

35,620.4

$ 33,292.5

Liabilities and Equity

Other long-term liabilities

404.8

418.6

404.8

418.6

751.6

578.4

751.6

578.4

Partners' equity

23,853.5

22,547.2

23,853.5

22,547.2

Condensed Consolidated Statement of Operations Information [Abstract]

9,182.3

$ 9,585.9

$ 8,467.5

$ 9,298.5

8,426.6

$ 6,886.9

$ 6,607.6

$ 7,320.4

36,534.2

^[1]

29,241.5

^[2]

23,022.3

^[2]

Costs and Expenses [Abstract]

31,397.3

25,557.5

19,643.5

Operating Activities [Abstract]

1,305.2

$ 1,334.6

$ 687.2

$ 911.5

$ 797.3

$ 621.3

$ 666.0

$ 771.0

4,238.5

2,855.6

2,553.0

16.2

32.2

(180.9)

Investing Activities [Abstract]

Balances Without Adoption [Member]

0.0

$ 46.1

$ 41.0

Assets [Abstract]

Accounts receivable - trade, net

3,672.4

298.2

38,639.3

Liabilities and Equity

Other long-term liabilities

404.3

664.8

Partners' equity

23,842.5

Condensed Consolidated Statement of Operations Information [Abstract]

35,901.5

Costs and Expenses [Abstract]

30,775.6

Operating Activities [Abstract]

4,227.5

(71.1)

Investing Activities [Abstract]

Impact of Adoption [Member]

87.3

Assets [Abstract]

Accounts receivable - trade, net

(13.3)

13.3

98.3

Liabilities and Equity

Other long-term liabilities

0.5

86.8

Partners' equity

$ 11.0

11.0

Condensed Consolidated Statement of Operations Information [Abstract]

632.7

Costs and Expenses [Abstract]

621.7

Operating Activities [Abstract]

11.0

87.3

Investing Activities [Abstract]

Impact of Adoption [Member] | ASC 606 [Member] | Equity NGL Revenue [Member]

(87.3)

Condensed Consolidated Statement of Operations Information [Abstract]

Impact of Adoption [Member] | ASC 606 [Member] | CIAC Revenue [Member]

621.7

Condensed Consolidated Statement of Operations Information [Abstract]

$ 11.0

[1]	Revenues are accounted for under ASC 606 upon implementation at January 1, 2018.
[2]	Revenues are accounted for under ASC 605 for historical periods prior to January 1, 2018.

Business Segments (Details)	12 Months Ended
Business Segments (Details)	Dec. 31, 2018 Segment Fractionator mi
Segment Reporting Information [Line Items]
Number of reportable segments \| Segment	4
Number of miles of pipelines	49,200
NGL Pipelines and Services [Member]
Segment Reporting Information [Line Items]
Number of miles of pipelines	19,200
Number of fractionators \| Fractionator	16
Crude Oil Pipelines & Services [Member]
Segment Reporting Information [Line Items]
Number of miles of pipelines	5,300
Natural Gas Pipelines & Services [Member]
Segment Reporting Information [Line Items]
Number of miles of pipelines	19,700
Petrochemical and Refined Products Services [Member] \| Propylene Operations [Member]
Segment Reporting Information [Line Items]
Number of miles of pipelines	800
Petrochemical and Refined Products Services [Member] \| Refined Products Operations [Member]
Segment Reporting Information [Line Items]
Number of miles of pipelines	4,100

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

3 Months Ended

12 Months Ended

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Business Segments [Abstract]

Adjustments to reconcile operating income to total gross operating margin:

$ 1,640.4

$ 1,643.3

$ 986.4

$ 1,138.5

$ 1,079.4

$ 879.2

$ 938.7

$ 1,031.6

$ 5,408.6

$ 3,928.9

$ 3,580.7

Add depreciation, amortization and accretion expense in operating costs and expenses

1,687.0

1,531.3

1,456.7

Add asset impairment and related charges in operating costs and expenses

50.5

49.8

52.8

Subtract net gains attributable to asset sales in operating costs and expenses

(28.7)

(10.7)

(2.5)

Add general and administrative costs

208.3

181.1

160.1

Adjustments for make-up rights on certain new pipeline projects:

Add non-refundable payments received from shippers attributable to make-up rights

^[1]

21.5

24.1

17.5

Subtract the subsequent recognition of revenues attributable to make-up rights

^[2]

(56.2)

(29.9)

(34.6)

Total segment gross operating margin

$ 7,291.0

$ 5,674.6

$ 5,230.7

[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

3 Months Ended

12 Months Ended

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

$ 7,291.0

$ 5,674.6

$ 5,230.7

36,426.5

29,196.5

22,965.6

107.7

45.0

56.7

0.0

Equity in income (loss) of unconsolidated affiliates

$ 9,182.3

$ 9,585.9

$ 8,467.5

$ 9,298.5

$ 8,426.6

$ 6,886.9

$ 6,607.6

$ 7,320.4

36,534.2

^[1]

29,241.5

^[2]

23,022.3

^[2]

480.0

426.0

362.0

38,737.6

35,620.4

38,737.6

35,620.4

33,292.5

2,615.1

2,659.4

2,615.1

2,659.4

2,677.3

3,608.4

3,690.3

3,608.4

3,690.3

3,864.1

5,745.2

NGL Pipelines and Services [Member]

50,706.3

47,715.3

50,706.3

47,715.3

45,579.1

Equity in income (loss) of unconsolidated affiliates

15,648.9

^[1]

12,468.0

^[2]

10,242.5

^[2]

117.0

73.4

61.4

380.1

322.3

380.1

322.3

Equity in income (loss) of unconsolidated affiliates

11,042.6

^[1]

8,156.8

^[2]

6,515.0

^[2]

365.4

358.4

311.9

2,094.6

2,186.5

2,094.6

2,186.5

Equity in income (loss) of unconsolidated affiliates

3,454.4

^[1]

3,145.6

^[2]

2,543.0

^[2]

6.8

3.8

979.3

1,018.4

979.3

1,018.4

Equity in income (loss) of unconsolidated affiliates

6,388.3

^[1]

5,471.1

^[2]

3,721.8

^[2]

^[3]

(9.2)

(9.6)

(15.1)

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

154.4

163.1

154.4

163.1

3,830.7

3,258.3

2,990.6

15,630.5

12,455.7

10,232.7

18.4

12.3

9.8

26,453.6

27,278.6

19,150.0

Equity in income (loss) of unconsolidated affiliates

42,102.5

39,746.6

29,392.5

117.0

73.4

61.4

14,845.4

13,831.2

14,845.4

13,831.2

14,091.5

662.0

733.9

662.0

733.9

750.4

380.1

322.3

380.1

322.3

350.2

2,651.7

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

18,539.2

17,539.1

18,539.2

17,539.1

17,843.8

1,511.3

987.2

854.6

10,968.2

8,137.2

6,478.7

74.4

19.6

36.3

35,490.4

15,943.0

9,052.0

Equity in income (loss) of unconsolidated affiliates

46,533.0

24,099.8

15,567.0

365.4

358.4

311.9

5,847.7

5,208.4

5,847.7

5,208.4

4,216.1

1,867.5

1,839.2

1,867.5

1,839.2

1,824.6

2,094.6

2,186.5

2,094.6

2,186.5

2,279.0

1,841.0

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

11,650.8

11,075.1

11,650.8

11,075.1

10,160.7

891.2

714.5

734.9

3,439.5

3,132.5

2,532.4

14.9

13.1

10.6

721.9

850.8

668.5

Equity in income (loss) of unconsolidated affiliates

4,176.3

3,996.4

3,211.5

6.8

3.8

8,303.8

8,375.0

8,303.8

8,375.0

8,403.0

22.8

20.8

22.8

20.8

21.7

979.3

1,018.4

979.3

1,018.4

1,054.5

296.3

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

9,602.2

9,710.5

9,602.2

9,710.5

9,775.5

1,057.8

714.6

650.6

6,388.3

5,471.1

3,721.8

0.0

2,917.5

1,766.9

1,234.8

Equity in income (loss) of unconsolidated affiliates

9,305.8

7,238.0

4,956.6

(9.2)

(9.6)

(15.1)

6,213.9

3,507.7

6,213.9

3,507.7

3,261.2

62.8

65.5

62.8

65.5

80.6

154.4

163.1

154.4

163.1

180.4

956.2

7,387.3

4,692.5

7,387.3

4,692.5

4,478.4

Eliminations [Member]

0.0

0.0

(65,583.4)

(45,839.3)

(30,105.3)

Equity in income (loss) of unconsolidated affiliates

(65,583.4)

(45,839.3)

(30,105.3)

0.0

Adjustments [Member]

3,526.8

4,698.1

3,526.8

4,698.1

3,320.7

0.0

0.0

0.0

$ 3,526.8

$ 4,698.1

$ 3,526.8

$ 4,698.1

$ 3,320.7

[1]	Revenues are accounted for under ASC 606 upon implementation at January 1, 2018.
[2]	Revenues are accounted for under ASC 605 for historical periods prior to January 1, 2018.
[3]	Losses are primarily attributable to our investment in Centennial. As a result of a trend in declining earnings, we estimated the fair value of this equity-method investment during each of the last three fiscal years. Our estimates, based on a combination of market and income approaches, indicate that the fair value of this investment remains in excess of its carrying value.

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

3 Months Ended

12 Months Ended

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Other operating costs and expenses

$ 9,182.3

$ 9,585.9

$ 8,467.5

$ 9,298.5

$ 8,426.6

$ 6,886.9

$ 6,607.6

$ 7,320.4

$ 36,534.2

^[1]

$ 29,241.5

^[2]

$ 23,022.3

^[2]

Operating costs and expenses:

Cost of sales

^[3]

26,789.8

21,487.0

15,710.9

^[4]

2,898.7

2,500.1

2,425.6

Depreciation, amortization and accretion

1,687.0

1,531.3

1,456.7

Asset impairment and related charges

50.5

49.8

52.8

(28.7)

(10.7)

(2.5)

208.3

181.1

160.1

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

$ 31,605.6

$ 25,738.6

$ 19,803.6

Largest non-affiliated customer percentage

7.80%

11.20%

9.90%

NGL Pipelines and Services [Member]

$ 15,648.9

^[1]

$ 12,468.0

^[2]

$ 10,242.5

^[2]

11,042.6

^[1]

8,156.8

^[2]

6,515.0

^[2]

Petrochemical and Refined Products Services [Member]

3,454.4

^[1]

3,145.6

^[2]

2,543.0

^[2]

$ 6,388.3

^[1]

$ 5,471.1

^[2]

$ 3,721.8

^[2]

[1]	Revenues are accounted for under ASC 606 upon implementation at January 1, 2018.
[2]	Revenues are accounted for under ASC 605 for historical periods prior to January 1, 2018.
[3]	Cost of sales is a component of "Operating costs and expenses," as presented on our Statements of Consolidated Operations. Fluctuations in these amounts are primarily due to changes in energy commodity prices and sales volumes associated with our marketing activities.
[4]	Represents the cost of operating our plants, pipelines and other fixed assets excluding: depreciation, amortization and accretion charges; asset impairment and related charges; and net losses (or gains) attributable to asset sales and insurance recoveries.

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

3 Months Ended

12 Months Ended

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

BASIC EARNINGS PER UNIT

Undistributed earnings allocated and cash payments on phantom unit awards

$ 1,284.7

$ 1,313.2

$ 673.8

$ 900.7

$ 774.0

$ 610.9

$ 653.7

$ 760.7

$ 4,172.4

$ 2,799.3

$ 2,513.1

^[1]

(21.5)

(15.9)

(12.9)

Net income available to common unitholders

$ 4,150.9

$ 2,783.4

$ 2,500.2

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

2,176.5

2,145.0

2,081.4

Basic earnings per unit (in dollars per unit)

$ 0.59

$ 0.60

$ 0.31

$ 0.41

$ 0.36

$ 0.28

$ 0.30

$ 0.36

$ 1.91

$ 1.30

$ 1.20

DILUTED EARNINGS PER UNIT

Diluted weighted-average number of units outstanding:

$ 1,284.7

$ 1,313.2

$ 673.8

$ 900.7

$ 774.0

$ 610.9

$ 653.7

$ 760.7

$ 4,172.4

$ 2,799.3

$ 2,513.1

Distribution-bearing common units (in units)

2,176.5

2,145.0

2,081.4

Phantom units (in units)

^[1]

10.5

9.3

7.7

Total (in units)

2,187.0

2,154.3

2,089.1

Diluted earnings per unit (in dollars per unit)

$ 0.59

$ 0.60

$ 0.31

$ 0.41

$ 0.36

$ 0.28

$ 0.30

$ 0.36

$ 1.91

$ 1.30

$ 1.20

[1]

Each phantom unit award includes a DER, which entitles the recipient to receive cash payments equal to the product of the number of phantom unit awards and the cash distribution per unit paid to our common unitholders. Cash payments made in connection with DERs are nonforfeitable. As a result, the phantom units are considered participating securities for purposes of computing basic earnings per unit.

Business Combinations (Details) - USD ($) $ in Millions	12 Months Ended
Business Combinations (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Mar. 29, 2018
Business Combination
Investments in unconsolidated affiliates	$ 2,615.1	$ 2,659.4	$ 2,677.3
Gain on step acquisition of Delaware Processing	39.4	0.0	0.0
Cash used for business combinations, net of cash received	$ 150.6	198.7	$ 1,000.0
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 is located in Reeves County, Texas and entered service in August 2016. The acquired business serves growing production of NGL-rich natural gas from 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	$ 150.6
Azure Midstream Partners, L.P. [Member]
Business Combination
Business acquisition, description	The acquired business assets, which are located primarily in East Texas, include over 750 miles of natural gas gathering pipelines and two natural gas processing facilities (Panola and Fairway) with an aggregate processing capacity of 130 MMcf/d. The acquired business primarily serves production from the Haynesville Shale and Bossier, Cotton Valley and Travis Peak formations.
Cash used for business combinations, net of cash received		$ 191.4

Business Combinations, Purchase Price Allocation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Mar. 29, 2018	Dec. 31, 2017	Apr. 30, 2017	Dec. 31, 2016
Liabilities assumed in business combination:
Goodwill	$ 5,745.2		$ 5,745.2		$ 5,745.2
Delaware Basin Gas Processing LLC [Member]
Consideration:
Purchase price for remaining 50% equity interest in Delaware Processing	154.5
Fair value of our 50% equity interest in Delaware Processing held before the acquisition	146.4
Total consideration	$ 300.9
Assets acquired in business combination:
Current assets, including cash		$ 10.8
Property, plant, and equipment		200.0
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
Azure Midstream Partners, L.P. [Member]
Assets acquired in business combination:
Current assets, including cash				$ 3.1
Property, plant, and equipment				193.1
Total assets acquired				196.2
Liabilities assumed in business combination:
Current liabilities				(1.4)
Long-term liabilities				(3.4)
Total liabilities assumed				(4.8)
Total identifiable net assets				$ 191.4

Equity-Based Awards (Details) - USD ($) $ in Millions	12 Months Ended
Equity-Based Awards (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Equity-based compensation expense [Abstract]
Total compensation expense	$ 106.1	$ 99.7	$ 89.2
Phantom Unit Awards [Member]
Equity-based compensation expense [Abstract]
Total compensation expense	99.7	92.8	78.6
Restricted Common Unit Awards [Member]
Equity-based compensation expense [Abstract]
Total compensation expense	0.0	0.5	4.7
Profits Interest Awards [Member]
Equity-based compensation expense [Abstract]
Total compensation expense	6.1	6.0	5.4
Liability-classified awards [Member]
Equity-based compensation expense [Abstract]
Total compensation expense	$ 0.3	$ 0.4	$ 0.5
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)	45,000,000
Remaining number of common units available to be issued as awards (in units)	19,116,132

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

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

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

3,479,958

2,485,580

1,761,455

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

Cash payments made in connection with DERs

$ 17.7

$ 15.1

$ 11.7

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)

9,289,501

7,767,501

5,426,949

Granted (in units)

5,006,181

^[1]

4,268,920

^[2]

4,508,310

^[3]

Vested (in units)

(3,479,958)

(2,490,081)

(1,761,455)

Forfeited (in units)

(482,447)

(256,839)

(406,303)

End of period (in units)

10,333,277

9,289,501

7,767,501

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

2,442,436

1,687,692

1,170,600

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]

$ 27.65

$ 27.20

$ 33.63

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

^[4]

26.82

^[1]

28.83

^[2]

21.90

^[3]

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

^[4]

28.57

28.30

33.10

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

^[4]

26.88

27.60

28.52

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

^[4]

$ 26.97

$ 27.65

$ 27.20

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

Aggregate grant date fair value

$ 134.3

$ 123.1

$ 98.7

Estimated forfeiture rate

3.20%

3.80%

3.90%

Cash payments made in connection with DERs

$ 17.7

$ 15.1

$ 11.7

Total intrinsic value of phantom unit awards that vested during period

90.7

$ 69.8

$ 40.9

Recognition period for total unrecognized compensation cost

$ 104.2

2 years 1 month 6 days

Phantom Unit Awards [Member] | Minimum [Member]

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

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

$ 25.40

$ 24.55

$ 21.86

Phantom Unit Awards [Member] | Maximum [Member]

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

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

$ 29.22

$ 28.87

$ 27.39

Phantom Unit Awards [Member] | Enterprise [Member]

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

$ 84.6

[1]	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 our common units ranging from $25.40 to $29.22 per unit. An estimated annual forfeiture rate of 3.2% was applied to these awards.
[2]	The aggregate grant date fair value of phantom unit awards issued during 2017 was $123.1 million based on a grant date market price of our common units ranging from $24.55 to $28.87 per unit. An estimated annual forfeiture rate of 3.8% was applied to these awards.
[3]	The aggregate grant date fair value of phantom unit awards issued during 2016 was $98.7 million based on a grant date market price of our common units ranging from $21.86 to $27.39 per unit. An estimated annual forfeiture rate of 3.9% 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, 2018

USD ($)

$ / shares

EPD PubCo I [Member]

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

30 days

2,723,052

$ 63.7

^[1]

$ 0.39

^[2]

Estimated grant date fair value of profits interest awards

Feb. 01, 2020

$ 13.0

^[3]

Recognition period for total unrecognized compensation cost

$ 4.3

^[4]

1 year 1 month 6 days

Estimated Grant Date Fair Value Assumptions [Abstract]

EPD PubCo I [Member] | Minimum [Member]

4 years

Estimated Grant Date Fair Value Assumptions [Abstract]

0.90%

5.90%

EPD PubCo I [Member] | Maximum [Member]

19.00%

Estimated Grant Date Fair Value Assumptions [Abstract]

2.70%

7.00%

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

40.00%

EPD PubCo II [Member]

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

30 days

2,834,198

$ 66.3

^[1]

$ 0.39

^[2]

Estimated grant date fair value of profits interest awards

Feb. 01, 2021

$ 14.9

^[3]

Recognition period for total unrecognized compensation cost

$ 7.3

^[4]

2 years 1 month 6 days

Estimated Grant Date Fair Value Assumptions [Abstract]

EPD PubCo II [Member] | Minimum [Member]

5 years

Estimated Grant Date Fair Value Assumptions [Abstract]

1.10%

5.90%

EPD PubCo II [Member] | Maximum [Member]

19.00%

Estimated Grant Date Fair Value Assumptions [Abstract]

3.00%

7.00%

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

40.00%

EPD PubCo III [Member]

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

30 days

105,000

$ 2.5

^[1]

$ 0.39

^[2]

Estimated grant date fair value of profits interest awards

Apr. 01, 2020

$ 0.5

^[3]

Recognition period for total unrecognized compensation cost

$ 0.2

^[4]

1 year 3 months 18 days

Estimated Grant Date Fair Value Assumptions [Abstract]

EPD PubCo III [Member] | Minimum [Member]

4 years

Estimated Grant Date Fair Value Assumptions [Abstract]

1.00%

6.10%

EPD PubCo III [Member] | Maximum [Member]

27.00%

Estimated Grant Date Fair Value Assumptions [Abstract]

2.20%

6.80%

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

40.00%

EPD PrivCo I [Member]

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

30 days

1,111,438

$ 26.0

^[1]

$ 0.39

^[2]

Estimated grant date fair value of profits interest awards

Feb. 01, 2021

$ 5.8

^[3]

Recognition period for total unrecognized compensation cost

$ 0.5

^[4]

2 years 1 month 6 days

Estimated Grant Date Fair Value Assumptions [Abstract]

EPD PrivCo I [Member] | Minimum [Member]

5 years

Estimated Grant Date Fair Value Assumptions [Abstract]

1.20%

6.10%

EPD PrivCo I [Member] | Maximum [Member]

28.00%

Estimated Grant Date Fair Value Assumptions [Abstract]

1.60%

6.70%

EPD 2018 Unit IV [Member]

40.00%

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

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

30 days

6,400,000

$ 172.9

^[1]

$ 0.4325

^[2]

Estimated grant date fair value of profits interest awards

Dec. 01, 2023

$ 26.7

^[3]

Recognition period for total unrecognized compensation cost

$ 23.1

^[4]

4 years 10 months 24 days

EPD 2018 Unit IV [Member] | Minimum [Member]

Estimated Grant Date Fair Value Assumptions [Abstract]

2.80%

6.50%

EPD 2018 Unit IV [Member] | Maximum [Member]

27.00%

Estimated Grant Date Fair Value Assumptions [Abstract]

2.80%

6.50%

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

27.00%

EPCO Unit II [Member]

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

30 days

1,600,000

$ 43.2

^[1]

$ 0.4325

^[2]

Estimated grant date fair value of profits interest awards

Dec. 01, 2023

$ 6.7

^[3]

Recognition period for total unrecognized compensation cost

$ 0.5

^[4]

4 years 10 months 24 days

Estimated Grant Date Fair Value Assumptions [Abstract]

EPCO Unit II [Member] | Minimum [Member]

5 years

Estimated Grant Date Fair Value Assumptions [Abstract]

2.80%

6.50%

EPCO Unit II [Member] | Maximum [Member]

27.00%

Estimated Grant Date Fair Value Assumptions [Abstract]

2.80%

6.50%

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

27.00%

[1]	Represents fair market value of the Enterprise common units contributed to each Employee Partnership at the applicable contribution date.
[2]	Each quarter, the Class A limited partner in each Employee Partnership is paid a cash distribution equal to the product of (i) the number of common units owned by the Employee Partnership and (ii) the Class A Preference Return (subject to equitable adjustment in order to reflect any equity split, equity distribution or dividend, reverse split, combination, reclassification, recapitalization or other similar event affecting such common units). To the extent that the Employee Partnership has cash remaining after making this quarterly payment to the Class A limited partner, the residual cash is distributed to the Class B limited partners on a quarterly basis.
[3]	Represents the total grant date fair value of the profits interest awards irrespective of how such costs will be allocated between us and EPCO and its privately held affiliates.
[4]	Represents our expected share of the unrecognized compensation cost at December 31, 2018. We expect to recognize our share of the unrecognized compensation cost for PubCo I, PubCo II, PubCo III, PrivCo I, EPD IV and EPCO II over a weighted-average period of 1.1 years, 2.1 years, 1.3 years, 2.1 years, 4.9 years and 4.9 years, respectively.

Equity-Based Awards, Restricted Unit Awards (Details) - Restricted Common Unit Awards [Member] - USD ($)
$ / shares in Units, $ in Millions

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Vesting rate of restricted common unit awards

25.00%

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

Beginning of period (in units)

682,294

1,960,520

Vested (in units)

(681,044)

(1,234,502)

Forfeited (in units)

(1,250)

(43,724)

End of period (in units)

682,294

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

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

^[1]

$ 28.61

$ 27.88

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

^[1]

28.60

27.45

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

^[1]

$ 31.07

28.48

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

^[1]

$ 28.61

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

Cash distributions paid to restricted common unitholders

$ 0.3

$ 1.6

Total intrinsic value of restricted common unit awards that vested during period

$ 18.9

$ 28.5

[1]	Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued.

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

12 Months Ended

Dec. 31, 2018

USD ($)

bbl

ft³

Dec. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

Proceeds from the settlement of interest rate derivative instruments | $

$ 22.1

$ 30.6

$ 6.1

Gain on the sale of swaption | $

29.4

Carrying amount of hedged asset | $

50.2

84.0

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

Notional amount of settled derivative instruments | $

275.0

250.0

Proceeds from the settlement of interest rate derivative instruments | $

$ 22.1

$ 30.6

$ 6.1

Designated as Hedging Instrument [Member] | Natural gas processing: Forecasted natural gas purchases for plant thermal reduction (PTR) [Member] | Derivatives in cash flow hedging relationships [Member]

Derivative instruments, current volume | ft³

^[1],[2]

4.9

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

Designated as Hedging Instrument [Member] | Octane enhancement: Forecasted purchases of NGLs [Member] | Derivatives in cash flow hedging relationships [Member]

^[1],[2]

1.0

Designated as Hedging Instrument [Member] | Octane enhancement: Forecasted sales of octane enhancement products [Member] | Derivatives in cash flow hedging relationships [Member]

^[1],[2]

1.8

^[1],[2]

3.1

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

^[1],[2]

0.1

Derivative instruments, current volume | ft³

^[1],[2]

3.3

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

^[1],[2]

33.6

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

^[1],[2]

4.3

^[1],[2]

45.0

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

^[1],[2]

1.7

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

^[1],[2]

0.3

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

^[1],[2]

1.0

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

^[1],[2]

2.0

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

^[1],[2]

0.5

^[1],[2]

18.4

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

^[1],[2]

1.9

^[1],[2]

28.5

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

^[1],[2]

1.9

Derivative instruments, current volume | ft³

^{[1],[2],[3],[4]}

77.5

Derivative instruments, long-term volume | ft³

^{[1],[2],[3],[4]}

0.9

Current natural gas hedging volumes designated as an index plus or minus a discount | ft³

29.8

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

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

^[1],[2],[4]

3.3

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

^[1],[2],[4]

2.6

^[1],[2],[4]

26.3

Derivative Instruments, Gain (Loss) [Line Items]

^[1],[2],[4]

3.2

[1]	The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is December 2020, June 2019 and December 2020, respectively.
[2]	Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes.
[3]	Current volumes include 29.8 Bcf of physical derivative instruments that are predominantly priced at a marked-based index plus a premium or minus a discount related to location differences.
[4]	Reflects the use of derivative instruments to manage risks associated with transportation, processing and storage assets.

Derivative Instruments, Hedging Activities and Fair Value Measurements, Derivative Fair Value Amounts (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Interest rate derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives		$ 0.1
Liability Derivatives		1.7
Commodity derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	$ 161.9	161.7
Liability Derivatives	162.4	176.9
Derivatives designated as hedging instruments [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	144.1	116.0
Liability Derivatives	126.1	112.9
Derivatives designated as hedging instruments [Member] \| Interest rate derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	0.0	0.1
Liability Derivatives	0.0	1.7
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	0.0	0.1
Derivatives designated as hedging instruments [Member] \| Interest rate derivatives [Member] \| Current liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	0.0	1.5
Derivatives designated as hedging instruments [Member] \| Interest rate derivatives [Member] \| Other liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	0.0	0.2
Derivatives designated as hedging instruments [Member] \| Commodity derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	144.1	115.9
Liability Derivatives	126.1	111.2
Derivatives designated as hedging instruments [Member] \| Commodity derivatives [Member] \| Current assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	138.5	109.5
Derivatives designated as hedging instruments [Member] \| Commodity derivatives [Member] \| Other assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	5.6	6.4
Derivatives designated as hedging instruments [Member] \| Commodity derivatives [Member] \| Current liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	115.0	104.4
Derivatives designated as hedging instruments [Member] \| Commodity derivatives [Member] \| Other liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	11.1	6.8
Derivatives not designated as hedging instruments [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	17.8	45.8
Liability Derivatives	36.3	65.7
Derivatives not designated as hedging instruments [Member] \| Commodity derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	17.8	45.8
Liability Derivatives	36.3	65.7
Derivatives not designated as hedging instruments [Member] \| Commodity derivatives [Member] \| Current assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	15.9	43.9
Derivatives not designated as hedging instruments [Member] \| Commodity derivatives [Member] \| Other assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	1.9	1.9
Derivatives not designated as hedging instruments [Member] \| Commodity derivatives [Member] \| Current liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	33.2	62.3
Derivatives not designated as hedging instruments [Member] \| Commodity derivatives [Member] \| Other liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	$ 3.1	$ 3.4

Derivative Instruments, Hedging Activities and Fair Value Measurements, Asset Balance Sheet Offsetting (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Interest rate derivatives [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets		$ 0.1
Gross Amounts Offset in the Balance Sheet		0.0
Amounts of Assets Presented in the Balance Sheet		0.1
Financial Instruments		(0.1)
Cash Collateral Paid		0.0
Cash Collateral Received		0.0
Amounts That Would Have Been Presented On Net Basis		0.0
Commodity Derivatives [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	$ 161.9	161.7
Gross Amounts Offset in the Balance Sheet	0.0	0.0
Amounts of Assets Presented in the Balance Sheet	161.9	161.7
Financial Instruments	(158.6)	(157.8)
Cash Collateral Paid	0.0	0.0
Cash Collateral Received	0.0	0.0
Amounts That Would Have Been Presented On Net Basis	$ 3.3	$ 3.9

Derivative Instruments, Hedging Activities and Fair Value Measurements, Liability Balance Sheet Offsetting (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Interest rate derivatives [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities		$ 1.7
Gross Amounts Offset in the Balance Sheet		0.0
Amounts of Liabilities Presented in the Balance Sheet		1.7
Financial Instruments		(0.1)
Cash Collateral Paid		0.0
Amounts That Would Have Been Presented On Net Basis		1.6
Commodity Derivatives [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	$ 162.4	176.9
Gross Amounts Offset in the Balance Sheet	0.0	0.0
Amounts of Liabilities Presented in the Balance Sheet	162.4	176.9
Financial Instruments	(158.6)	(157.8)
Cash Collateral Paid	(2.3)	(17.3)
Amounts That Would Have Been Presented On Net Basis	$ 1.5	$ 1.8

Derivative Instruments, Hedging Activities and Fair Value Measurements, Gains and Losses on Derivative Instruments and Related Hedged Items (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

NGL Pipelines & Services [Member]

$ (19.1)

Derivative Instruments, Gain (Loss) [Line Items]

18.0

Derivative Instruments, Gain (Loss) [Line Items]

(44.1)

Derivative Instruments, Gain (Loss) [Line Items]

5.3

Derivative Instruments, Gain (Loss) [Line Items]

Derivatives in fair value hedging relationships [Member]

1.7

Derivative Instruments, Gain (Loss) [Line Items]

Gain (Loss) Recognized in Income on Hedged Item

11.2

$ 0.9

$ (90.2)

(8.3)

27.8

124.6

Derivatives in fair value hedging relationships [Member] | Interest rate derivatives [Member] | Interest expense [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Gain (Loss) Recognized in Income on Hedged Item

1.3

(0.2)

0.3

(1.4)

0.4

(0.4)

Derivatives in fair value hedging relationships [Member] | Commodity derivatives [Member] | Revenue [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Gain (Loss) Recognized in Income on Hedged Item

9.9

1.1

(90.5)

(6.9)

27.4

125.0

Derivatives in cash flow hedging relationships [Member]

Derivative Instruments, Gain (Loss) [Line Items]

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

315.4

(44.2)

(151.5)

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

92.3

(152.6)

(90.8)

Derivatives in cash flow hedging relationships [Member] | Interest rate derivatives [Member]

Derivative Instruments, Gain (Loss) [Line Items]

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

22.2

(5.7)

42.3

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

(38.0)

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

(38.1)

(40.4)

(37.4)

Derivatives in cash flow hedging relationships [Member] | Commodity derivatives [Member]

Derivative Instruments, Gain (Loss) [Line Items]

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

168.1

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

166.9

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

1.2

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]

293.0

(33.7)

(197.4)

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

131.7

(111.6)

(53.6)

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

Derivative Instruments, Gain (Loss) [Line Items]

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

^[1]

0.2

(4.8)

3.6

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

(1.3)

(0.6)

0.2

Derivatives not designated as hedging instruments [Member]

Derivative Instruments, Gain (Loss) [Line Items]

(454.7)

(42.6)

(38.8)

Realized gains (losses)

(443.8)

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

(10.9)

Derivative Instruments, Gain (Loss) [Line Items]

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

(462.9)

(42.7)

(38.4)

Derivative Instruments, Gain (Loss) [Line Items]

$ 8.2

$ 0.1

$ (0.4)

[1]	The fair value of these derivative instruments will be reclassified to their respective locations on the Statement of Consolidated Operations upon settlement of the underlying derivative transactions, as appropriate.

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

$ 390.0

$ 333.9

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

(17.8)

(22.8)

$ (45.0)

Fair Value, Measurements, Recurring [Member]

0.1

456.9

234.9

(295.0)

(73.2)

161.9

161.7

161.9

161.8

390.0

333.9

1.7

398.1

390.7

(235.7)

(213.8)

162.4

176.9

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

552.4

512.5

0.0

172.3

47.1

(134.8)

(47.1)

37.5

0.0

37.5

0.0

0.0

0.0

85.5

118.4

(48.6)

(118.4)

36.9

0.0

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

36.9

0.0

0.1

282.4

184.9

(159.3)

(26.1)

123.1

158.8

123.1

158.9

0.0

1.7

291.2

270.6

(172.9)

(95.4)

118.3

175.2

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

118.3

176.9

0.0

2.2

2.9

(0.9)

0.0

1.3

2.9

1.3

2.9

390.0

333.9

0.0

21.4

1.7

(14.2)

0.0

7.2

1.7

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

397.2

335.6

Financial liability balance, net, beginning of period

(332.7)

^[1]

(268.2)

Financial liability balance, net, end of period

Transfers out of Level 3

^[1]

(2.7)

(0.2)

(395.9)

^[1]

(332.7)

^[1]

$ (268.2)

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

(1.2)

(0.1)

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

Other comprehensive income (loss)

(3.2)

0.1

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

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

^[2]

0.7

2.3

Settlements

^[2]

(1.9)

(2.4)

Total provision for (benefit from) income taxes

$ (56.1)

$ (64.3)

[1]	Transfers out of Level 3 into Level 2 were due to shorter remaining transaction maturities falling inside of the Level 2 range at December 31, 2018 and 2017.
[2]	There were $1.2 million and $0.1 million of unrealized losses included in these amounts for the years ended December 31, 2018 and 2017, respectively.

Derivative Instruments, Hedging Activities and Fair Value Measurements, Nonrecurring Fair Value Measurements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Asset Impairment Charges [Abstract]
Asset impairment and related charges	$ 50.5	$ 49.8	$ 53.5
Impairment of other current assets	3.7	12.0	1.2
Loss due to Pascagoula fire			7.1
Impairment of long-lived assets disposed of other than by sale	43.7	16.7	29.9
Impairment of long-lived assets held and used	3.1	15.4	2.2
Impairment of long-lived assets held for sale		2.5
Impairment of long-lived assets disposed of by sale		3.2	13.1
Impairment of long-lived assets	46.8	37.8	45.2
Certain storage and pipeline assets in Texas [Member]
Asset Impairment Charges [Abstract]
Impairment of long-lived assets		12.4
Natural gas pipeline laterals and other pipelines in Texas [Member]
Asset Impairment Charges [Abstract]
Impairment of long-lived assets		13.0
NGL Pipelines and Services [Member]
Asset Impairment Charges [Abstract]
Impairment of long-lived assets	18.6	11.5	21.0
Crude Oil Pipelines & Services [Member]
Asset Impairment Charges [Abstract]
Impairment of long-lived assets	11.2	10.2	2.3
Natural Gas Pipelines & Services [Member]
Asset Impairment Charges [Abstract]
Impairment of long-lived assets	13.9	14.3	12.3
Petrochemical and Refined Products Services [Member]
Asset Impairment Charges [Abstract]
Impairment of long-lived assets	3.1	1.8	9.6
Fair Value, Measurements, Nonrecurring [Member] \| Long-lived Assets Disposed of Other Than By Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value	0.0	0.0	0.0
Fair Value, Measurements, Nonrecurring [Member] \| Long-lived Assets Held and Used [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value	0.0	1.5	8.0
Fair Value, Measurements, Nonrecurring [Member] \| Long-lived Assets Held For Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value		2.5
Fair Value, Measurements, Nonrecurring [Member] \| Long-lived Assets Disposed of By Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value		0.0	0.0
Fair Value, Measurements, Nonrecurring [Member] \| Level 1 [Member] \| Long-lived Assets Disposed of Other Than By Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value	0.0	0.0	0.0
Fair Value, Measurements, Nonrecurring [Member] \| Level 1 [Member] \| Long-lived Assets Held and Used [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value	0.0	0.0	8.0
Fair Value, Measurements, Nonrecurring [Member] \| Level 1 [Member] \| Long-lived Assets Held For Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value		0.0
Fair Value, Measurements, Nonrecurring [Member] \| Level 1 [Member] \| Long-lived Assets Disposed of By Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value		0.0	0.0
Fair Value, Measurements, Nonrecurring [Member] \| Level 2 [Member] \| Long-lived Assets Disposed of Other Than By Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value	0.0	0.0	0.0
Fair Value, Measurements, Nonrecurring [Member] \| Level 2 [Member] \| Long-lived Assets Held and Used [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value	0.0	0.0	0.0
Fair Value, Measurements, Nonrecurring [Member] \| Level 2 [Member] \| Long-lived Assets Held For Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value		0.0
Fair Value, Measurements, Nonrecurring [Member] \| Level 2 [Member] \| Long-lived Assets Disposed of By Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value		0.0	0.0
Fair Value, Measurements, Nonrecurring [Member] \| Level 3 [Member] \| Long-lived Assets Disposed of Other Than By Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value	0.0	0.0	0.0
Fair Value, Measurements, Nonrecurring [Member] \| Level 3 [Member] \| Long-lived Assets Held and Used [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value	$ 0.0	1.5	0.0
Fair Value, Measurements, Nonrecurring [Member] \| Level 3 [Member] \| Long-lived Assets Held For Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value		2.5
Fair Value, Measurements, Nonrecurring [Member] \| Level 3 [Member] \| Long-lived Assets Disposed of By Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value		$ 0.0	$ 0.0

Derivative Instruments, Hedging Activities and Fair Value Measurements, Other Fair Value Measurements (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Carrying Value [Member]
Financial Liabilities: [Abstract]
Fixed-rate debt obligations	$ 26,150	$ 21,480
Level 2 [Member] \| Fair Value [Member]
Financial Liabilities: [Abstract]
Fixed-rate debt obligations	$ 25,970	$ 23,470

Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues - related parties:
Total revenue - related parties	$ 107.7	$ 45.0	$ 56.7
Costs and expenses - related parties:
Operating costs and expenses	1,406.1	1,112.8	1,104.0
General and administrative expenses	130.9	121.5	113.1
Total costs and expenses - related parties	1,537.0	1,234.3	1,217.1
Accounts receivable - related parties:
Total accounts receivable - related parties	3.5	1.8
Accounts payable - related parties:
Total accounts payable - related parties	140.2	127.3
At-the-Market Registration [Member]
Relationship with Affiliates [Abstract]
Gross proceeds from the sale of common units		603.1	2,170.0
EPCO and its privately held affiliates [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	1,089.6	1,010.9	963.2
Accounts payable - related parties:
Total accounts payable - related parties	116.3	99.3
Distributions:
Total cash distributions	$ 1,160.0	1,120.0	1,070.0
Relationship with Affiliates [Abstract]
Number of Units (in units)	697,529,483
Percentage of Total Units Outstanding	31.90%
Enterprise common units pledged as security (in units)	108,222,618
EPCO and its privately held affiliates [Member] \| At-the-Market Registration [Member]
Relationship with Affiliates [Abstract]
Gross proceeds from the sale of common units			100.0
EPCO and its privately held affiliates [Member] \| Distribution Reinvestment Plan [Member]
Relationship with Affiliates [Abstract]
Gross proceeds from the sale of common units	$ 213.0	100.0	100.0
EPCO and its privately held affiliates [Member] \| Administrative Services Agreement [Member]
Costs and expenses - related parties:
Operating costs and expenses	948.8	882.1	840.7
General and administrative expenses	124.2	110.4	105.3
Total costs and expenses - related parties	1,073.0	992.5	946.0
Unconsolidated affiliates [Member]
Revenues - related parties:
Total revenue - related parties	107.7	45.0	56.7
Costs and expenses - related parties:
Total costs and expenses - related parties	447.4	223.4	253.9
Accounts receivable - related parties:
Total accounts receivable - related parties	3.5	1.8
Accounts payable - related parties:
Total accounts payable - related parties	23.9	28.0
Unconsolidated affiliates [Member] \| Seaway Crude Pipeline Company [Member]
Revenues - related parties:
Total revenue - related parties	74.4	19.6	36.3
Costs and expenses - related parties:
Total costs and expenses - related parties	163.2	98.8	161.2
Unconsolidated affiliates [Member] \| Venice Energy Service Company, L.L.C. [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	157.9
Unconsolidated affiliates [Member] \| K/D/S Promix, L.L.C. [Member]
Revenues - related parties:
Total revenue - related parties	9.5	7.8	7.0
Costs and expenses - related parties:
Total costs and expenses - related parties	31.9	27.8	27.1
Unconsolidated affiliates [Member] \| Texas Express Pipeline LLC [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	57.6	29.5	22.8
Unconsolidated affiliates [Member] \| Eagle Ford Pipeline LLC [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	18.5	42.8	36.2
Unconsolidated affiliates [Member] \| Management/Operator Fees [Member] \| Other investments in unconsolidated subsidiaries [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	$ (11.6)	$ (10.6)	$ (10.7)

Provision for Income Taxes (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Current:

Federal

$ 5.3

$ 0.1

$ (0.5)

State

33.1

18.5

16.7

Foreign

0.5

1.0

0.6

Total current

38.9

19.6

16.8

Deferred:

Federal

(0.3)

(1.8)

1.1

State

21.7

7.9

5.2

Foreign

0.0

0.3

Total deferred

21.4

6.1

6.6

60.3

25.7

23.4

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

Pre-Tax Net Book Income ("NBI")

4,298.8

2,881.3

2,576.4

Texas Margin Tax

^[1]

54.8

26.4

22.1

State income taxes (net of federal benefit)

0.2

0.5

0.2

Federal income taxes computed by applying the federal statutory rate to NBI of corporate entities

2.1

0.1

0.8

Other permanent differences

3.2

(1.3)

0.3

Total provision for (benefit from) income taxes

$ 60.3

$ 25.7

$ 23.4

Effective income tax rate

1.40%

0.90%

Deferred tax assets:

Net operating loss carryovers

^[2]

$ 0.1

$ 0.2

Accruals

2.6

1.4

Total deferred tax assets

2.7

1.6

Less: Deferred tax liabilities:

Property, plant and equipment

80.8

58.0

Equity investment in partnerships

2.3

2.1

Total deferred tax liabilities

83.1

60.1

Total net deferred tax liabilities

$ 80.4

$ 58.5

[1]	Although the Texas Margin Tax is not considered a state income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers our Texas-sourced revenues and expenses.
[2]	These losses expire in various years between 2019 and 2033 and are subject to limitations on their utilization.

Commitments and Contingencies (Details) bbl in Millions, $ in Millions, BTU in Trillions	12 Months Ended
	Dec. 31, 2018 USD ($) BTU bbl	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2014 USD ($)
Redelivery commitments:
Redelivery commitments of natural gas \| BTU	7.7
Redelivery commitments of crude oil \| bbl	18.4
Redelivery commitments of NGL and petrochemical products \| bbl	38.5
Operating lease obligations:
Renewal option years for certain leases	20 years
Lease and rental expense included in costs and expenses	$ 86.4	$ 103.6	$ 110.1
Liabilities, Other than Long-term Debt, Noncurrent [Abstract]
Noncurrent portion of AROs	121.4	81.1
Deferred revenues - non-current portion	210.3	135.5
Liquidity option agreement	390.0	333.9
Derivative liabilities	14.2	10.4
Centennial guarantees	3.6	4.5
Other	12.1	13.0
Total	751.6	578.4
Junior Subordinated Note [Member]
Debt Instrument [Line Items]
Debt obligations	2,670.0
Centennial Pipeline LLC [Member]
Debt Instrument [Line Items]
Debt obligations	$ 41.8
Minimum [Member]
Operating lease obligations:
Term of material lease agreements	5 years
Maximum [Member]
Operating lease obligations:
Term of material lease agreements	30 years
Litigation matters [Member]
Loss Contingencies [Line Items]
Litigation accruals on an undiscounted basis	$ 0.5	$ 4.5
Litigation matters [Member] \| ETP Lawsuit [Member]
Loss Contingencies [Line Items]
Loss contingency, total damages sought				$ 535.8
Loss contingency, damages awarded				319.4
Loss contingency, disgorgement damages sought				150.0
Prejudgment interest				$ 66.4
Post-judgment interest rate				5.00%
Centennial debt guarantee [Member]
Guarantor Obligations [Line Items]
Percentage of debt obligations guaranteed	50.00%
Guarantee of debt obligations	$ 20.9
Fair value of debt guarantee	3.1
Centennial cash call guarantee [Member]
Guarantor Obligations [Line Items]
Cash call guarantee	50.0
Fair value of cash call guarantee	$ 1.3

Commitments and Contingencies, Contractual Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Scheduled maturities of debt obligations [Abstract]
2019	$ 1,500.0
2020	1,500.0
2021	1,325.0
2022	1,400.0
2023	1,250.0
Thereafter	19,445.6
Total	26,420.6	$ 24,780.1
Estimated cash interest payments [Abstract]
2019	1,190.4
2020	1,132.5
2021	1,062.9
2022	1,010.1
2023	969.9
Thereafter	20,154.4
Total	25,520.2
Operating lease obligations [Abstract]
2019	50.5
2020	45.6
2021	38.7
2022	30.8
2023	20.9
Thereafter	138.3
Total	324.8
Natural Gas [Member]
Estimated payment obligations:
2019	572.0
2020	599.4
2021	459.8
2022	0.0
2023	0.0
Thereafter	0.0
Total	1,631.2
NGLs [Member]
Estimated payment obligations:
2019	760.6
2020	739.4
2021	620.3
2022	527.7
2023	310.3
Thereafter	478.9
Total	3,437.2
Crude Oil [Member]
Estimated payment obligations:
2019	1,038.6
2020	771.3
2021	557.1
2022	543.1
2023	438.1
Thereafter	1,430.0
Total	4,778.2
Petrochemicals And Refined Products [Member]
Estimated payment obligations:
2019	179.0
2020	178.3
2021	42.4
2022	0.0
2023	0.0
Thereafter	0.0
Total	399.7
Estimated Payment Obligations Other [Member]
Estimated payment obligations:
2019	8.2
2020	8.3
2021	4.3
2022	2.3
2023	2.4
Thereafter	1.9
Total	27.4
Service Payment Commitments [Member]
Estimated payment obligations:
2019	75.1
2020	72.2
2021	55.3
2022	53.7
2023	38.9
Thereafter	108.6
Total	403.8
Capital Expenditure Commitments [Member]
Estimated payment obligations:
2019	171.8
2020	0.0
2021	0.0
2022	0.0
2023	0.0
Thereafter	0.0
Total	171.8
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 Contingencies, Liquidity Option Agreement (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($) shares	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Liquidity Option Agreement [Abstract]
Change in fair value of Liquidity Option Agreement	$ 56.1	$ 64.3	$ 24.5
Percentage of capital stock agreed to purchase under liquidity option agreement	100.00%
Liquidity Option exercise period	90 days
Percentage of fair market value of Enterprise units to be paid as consideration	100.00%
Trigger Event exercise period	135 days
Number of units held by limited partner (in units) \| shares	54,807,352
Liquidity Option Agreement [Member]
Liquidity Option Agreement [Abstract]
Increase in fair value of liquidity option agreement assuming retention of all units	$ 23.1
Level 3 [Member]
Liquidity Option Agreement [Abstract]
Derivative Liability	$ 390.0	$ 333.9
Level 3 [Member] \| Liquidity Option Agreement [Member]
Liquidity Option Agreement [Abstract]
Fair value inputs, Life of debt assumed after Liquidity option is exercised	30 years
Fair value inputs, weighted-average expected ownership percentage of contributed units at beginning of option period	94.00%
Level 3 [Member] \| Liquidity Option Agreement [Member] \| Minimum [Member]
Liquidity Option Agreement [Abstract]
Fair value inputs, Expected life of OTA following option exercise	1 year
Fair value inputs, Estimated growth rates in Enterprise earnings before interest, taxes, depreciation and amortization	1.90%
Fair value inputs, OTA ownership interest in Enterprise common units	2.30%
Level 3 [Member] \| Liquidity Option Agreement [Member] \| Maximum [Member]
Liquidity Option Agreement [Abstract]
Fair value inputs, Expected life of OTA following option exercise	30 years
Fair value inputs, Estimated growth rates in Enterprise earnings before interest, taxes, depreciation and amortization	5.60%
Fair value inputs, OTA ownership interest in Enterprise common units	2.50%
Level 3 [Member] \| Liquidity Option Agreement [Member] \| Measurement Input, Aggregate Tax Rate [Member]
Liquidity Option Agreement [Abstract]
Derivative Liability, Measurement Input	0.24
Level 3 [Member] \| Liquidity Option Agreement [Member] \| Measurement Input, Discount Rate [Member]
Liquidity Option Agreement [Abstract]
Derivative Liability, Measurement Input	0.079

Significant Risks and Uncertainties (Details) $ in Millions	12 Months Ended
Significant Risks and Uncertainties (Details) $ in Millions	Dec. 31, 2018 USD ($)
Insurance Matters [Abstract]
Insurance deductible per incident	$ 30.0
Minimum business interruption period	60 days
Named windstorm insurance coverage	$ 200.0

Supplemental Cash Flow Information (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Decrease (increase) in:

Accounts receivable - trade

$ 730.2

$ (1,076.2)

$ (679.0)

Accounts receivable - related parties

(2.3)

(0.7)

0.4

Inventories

121.4

194.6

(871.8)

Accounts payable - related parties

214.4

226.0

(49.3)

Other assets

(9.7)

(111.0)

(2.0)

Increase (decrease) in:

Accounts payable - trade

18.3

66.6

(21.5)

51.4

56.0

21.0

Accrued product payables

(1,132.0)

952.3

1,193.3

Accrued interest

37.6

17.3

(11.4)

(70.9)

(291.4)

189.9

Other liabilities

57.8

(1.3)

49.5

Cash payments for interest, net of $147.9, $192.1 and $168.2 capitalized in 2018, 2017 and 2016, respectively

16.2

32.2

(180.9)

1,017.9

912.1

947.9

Capitalized interest

^[1]

147.9

192.1

168.2

Cash payments for federal and state income taxes

15.5

20.9

18.7

Liability for construction in progress expenditures

567.6

373.0

124.3

Proceeds from asset sales

0.0

46.1

41.0

Sale of Assets:

161.2

40.1

46.5

Cash paid to acquire business

28.7

10.7

2.5

Business Acquisition [Line Items]

150.6

198.7

1,000.0

Red River System [Member]

Sale of Assets:

Proceeds from asset sales

134.9

0.0

Other Disposal of Assets [Member]

20.6

0.0

Sale of Assets:

Proceeds from asset sales

26.3

40.1

46.5

Eagle Ford Midstream Assets [Member]

$ 8.1

$ 10.7

2.5

Business Acquisition [Line Items]

Total consideration for acquisition

$ 2,100.0

Cash paid to acquire business

$ 1,000.0

[1]	Capitalized interest is a component of "Interest expense" as presented on our Statements of Consolidated Operations.

Quarterly Financial Information (Unaudited) (Details) - USD ($)
$ / shares in Units, $ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Quarterly Financial Information (Unaudited) [Abstract]

$ 9,182.3

$ 9,585.9

$ 8,467.5

$ 9,298.5

$ 8,426.6

$ 6,886.9

$ 6,607.6

$ 7,320.4

$ 36,534.2

^[1]

$ 29,241.5

^[2]

$ 23,022.3

^[2]

1,640.4

1,643.3

986.4

1,138.5

1,079.4

879.2

938.7

1,031.6

5,408.6

3,928.9

3,580.7

1,305.2

1,334.6

687.2

911.5

797.3

621.3

666.0

771.0

4,238.5

2,855.6

2,553.0

Basic earnings per unit (in dollars per unit)

$ 1,284.7

$ 1,313.2

$ 673.8

$ 900.7

$ 774.0

$ 610.9

$ 653.7

$ 760.7

$ 4,172.4

$ 2,799.3

$ 2,513.1

Earnings per unit:

$ 0.59

$ 0.60

$ 0.31

$ 0.41

$ 0.36

$ 0.28

$ 0.30

$ 0.36

$ 1.91

$ 1.30

$ 1.20

Diluted earnings per unit (in dollars per unit)

$ 0.59

$ 0.60

$ 0.31

$ 0.41

$ 0.36

$ 0.28

$ 0.30

$ 0.36

$ 1.91

$ 1.30

$ 1.20

[1]	Revenues are accounted for under ASC 606 upon implementation at January 1, 2018.
[2]	Revenues are accounted for under ASC 605 for historical periods prior to January 1, 2018.

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References + Details

Condensed Consolidated Statement of Operations Information [Abstract]

The consolidated profit or loss for the period, net of income taxes, including the portion attributable to the noncontrolling interest.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 1A
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=114867106&loc=SL7669619-108580

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 50
-Paragraph 1A
-Subparagraph (a)(1)
-URI http://asc.fasb.org/extlink&oid=109239629&loc=SL4573702-111684

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 1B
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=114867106&loc=SL7669625-108580

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 50
-Paragraph 1A
-Subparagraph (c)(1)
-URI http://asc.fasb.org/extlink&oid=109239629&loc=SL4573702-111684

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=115929826&loc=d3e8736-108599

Reference 6: http://www.xbrl.org/2003/role/exampleRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 55
-Paragraph 4J
-URI http://asc.fasb.org/extlink&oid=84234705&loc=SL4591551-111686

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 230
-SubTopic 10
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=109223946&loc=d3e3000-108585

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 45
-Paragraph 19
-URI http://asc.fasb.org/extlink&oid=108774443&loc=SL4569616-111683

Reference 9: 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=115929826&loc=d3e8933-108599

Reference 10: http://www.xbrl.org/2003/role/exampleRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 55
-Paragraph 4K
-URI http://asc.fasb.org/extlink&oid=84234705&loc=SL4591552-111686

+ Details

Condensed Consolidating Financial Information, Balance Sheets (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents and restricted cash	$ 410.1	$ 70.3	$ 417.6	$ 34.9
Accounts receivable - trade, net	3,659.1	4,358.4
Accounts receivable - related parties	3.5	1.8
Inventories	1,522.1	1,609.8
Derivative assets	154.4	153.4
Prepaid and other current assets	311.5	312.7
Total current assets	6,060.7	6,506.4
Property, plant and equipment, net	38,737.6	35,620.4	33,292.5
Investments in unconsolidated affiliates	2,615.1	2,659.4	2,677.3
Intangible assets, net	3,608.4	3,690.3	3,864.1
Goodwill	5,745.2	5,745.2	5,745.2
Other assets	202.8	196.4
Total assets	56,969.8	54,418.1
Current liabilities:
Current maturities of debt	1,500.1	2,855.0
Accounts payable - trade	1,102.8	801.7
Accounts payable - related parties	140.2	127.3
Accrued product payables	3,475.8	4,566.3
Accrued interest	395.6	358.0
Derivative liabilities	148.2	168.2
Other current liabilities	404.8	418.6
Total current liabilities	7,167.5	9,295.1
Long-term debt	24,678.1	21,713.7
Deferred tax liabilities	80.4	58.5
Other long-term liabilities	751.6	578.4
Commitments and contingencies
Equity:
Partners' and other owners' equity	23,853.5	22,547.2
Noncontrolling interests	438.7	225.2
Total equity	24,292.2	22,772.4	22,266.0	20,501.1
Total liabilities and equity	56,969.8	54,418.1
Eliminations and Adjustments [Member]
Current assets:
Cash and cash equivalents and restricted cash	0.0	0.0	0.0	0.0
Accounts receivable - trade, net	0.0	0.0
Accounts receivable - related parties	(32.7)	(1.3)
Inventories	0.0	0.0
Derivative assets	0.0	0.0
Prepaid and other current assets	0.6	0.0
Total current assets	(32.1)	(1.3)
Property, plant and equipment, net	0.0	0.0
Investments in unconsolidated affiliates	(24,273.6)	(22,881.5)
Intangible assets, net	0.0	0.0
Goodwill	0.0	0.0
Other assets	0.0	0.0
Total assets	(24,305.7)	(22,882.8)
Current liabilities:
Current maturities of debt	0.0	0.0
Accounts payable - trade	0.0	0.0
Accounts payable - related parties	(32.6)	(1.3)
Accrued product payables	0.0	0.0
Accrued interest	0.0	0.0
Derivative liabilities	0.0	0.0
Other current liabilities	0.0	0.4
Total current liabilities	(32.6)	(0.9)
Long-term debt	0.0	0.0
Deferred tax liabilities	2.3	2.1
Other long-term liabilities	0.0	0.0
Commitments and contingencies
Equity:
Partners' and other owners' equity	(24,247.4)	(22,853.1)
Noncontrolling interests	(28.0)	(30.9)
Total equity	(24,275.4)	(22,884.0)
Total liabilities and equity	(24,305.7)	(22,882.8)
Subsidiary Issuer (EPO) [Member]
Current assets:
Cash and cash equivalents and restricted cash	393.4	65.2	366.2	14.4
Accounts receivable - trade, net	1,303.1	1,382.3
Accounts receivable - related parties	141.8	110.3
Inventories	889.3	1,038.9
Derivative assets	105.0	110.0
Prepaid and other current assets	166.0	136.3
Total current assets	2,998.6	2,843.0
Property, plant and equipment, net	6,112.7	5,622.6
Investments in unconsolidated affiliates	43,962.6	41,616.6
Intangible assets, net	659.2	675.5
Goodwill	459.5	459.5
Other assets	292.1	296.4
Total assets	54,484.7	51,513.6
Current liabilities:
Current maturities of debt	1,500.0	2,854.6
Accounts payable - trade	404.0	290.2
Accounts payable - related parties	1,557.3	1,320.3
Accrued product payables	1,574.7	1,825.9
Accrued interest	395.5	358.0
Derivative liabilities	86.2	115.2
Other current liabilities	87.9	108.9
Total current liabilities	5,605.6	6,873.1
Long-term debt	24,663.4	21,699.0
Deferred tax liabilities	17.0	6.7
Other long-term liabilities	65.2	60.4
Commitments and contingencies
Equity:
Partners' and other owners' equity	24,133.5	22,874.4
Noncontrolling interests	0.0	0.0
Total equity	24,133.5	22,874.4
Total liabilities and equity	54,484.7	51,513.6
Other Subsidiaries (Non-guarantor) [Member]
Current assets:
Cash and cash equivalents and restricted cash	50.3	31.5	58.9	71.1
Accounts receivable - trade, net	2,356.8	2,976.6
Accounts receivable - related parties	1,423.7	1,182.1
Inventories	633.2	572.3
Derivative assets	49.1	43.4
Prepaid and other current assets	155.1	189.0
Total current assets	4,668.2	4,994.9
Property, plant and equipment, net	32,628.7	29,996.3
Investments in unconsolidated affiliates	4,170.6	4,298.0
Intangible assets, net	2,963.0	3,028.6
Goodwill	5,285.7	5,285.7
Other assets	131.9	110.0
Total assets	49,848.1	47,713.5
Current liabilities:
Current maturities of debt	0.1	0.4
Accounts payable - trade	734.3	537.8
Accounts payable - related parties	127.5	112.0
Accrued product payables	1,902.3	2,741.7
Accrued interest	0.9	0.0
Derivative liabilities	61.7	53.0
Other current liabilities	326.3	320.1
Total current liabilities	3,153.1	3,765.0
Long-term debt	14.7	14.7
Deferred tax liabilities	62.0	50.2
Other long-term liabilities	518.4	396.5
Commitments and contingencies
Equity:
Partners' and other owners' equity	46,031.8	43,412.0
Noncontrolling interests	68.1	75.1
Total equity	46,099.9	43,487.1
Total liabilities and equity	49,848.1	47,713.5
Consolidated EPO and Subsidiaries [Member]
Current assets:
Cash and cash equivalents and restricted cash	410.1	70.3	417.6	34.9
Accounts receivable - trade, net	3,659.1	4,358.4
Accounts receivable - related parties	35.4	3.1
Inventories	1,522.1	1,609.8
Derivative assets	154.4	153.4
Prepaid and other current assets	310.9	312.7
Total current assets	6,092.0	6,507.7
Property, plant and equipment, net	38,737.6	35,620.4
Investments in unconsolidated affiliates	2,615.1	2,659.4
Intangible assets, net	3,608.4	3,690.3
Goodwill	5,745.2	5,745.2
Other assets	201.9	195.4
Total assets	57,000.2	54,418.4
Current liabilities:
Current maturities of debt	1,500.1	2,855.0
Accounts payable - trade	1,102.8	801.6
Accounts payable - related parties	140.9	127.3
Accrued product payables	3,475.8	4,566.3
Accrued interest	395.6	358.0
Derivative liabilities	148.2	168.2
Other current liabilities	404.8	418.2
Total current liabilities	7,168.2	9,294.6
Long-term debt	24,678.1	21,713.7
Deferred tax liabilities	78.1	56.4
Other long-term liabilities	361.7	244.5
Commitments and contingencies
Equity:
Partners' and other owners' equity	24,247.4	22,853.1
Noncontrolling interests	466.7	256.1
Total equity	24,714.1	23,109.2
Total liabilities and equity	57,000.2	54,418.4
Consolidated EPO and Subsidiaries [Member] \| Eliminations and Adjustments [Member]
Current assets:
Cash and cash equivalents and restricted cash	(33.6)	(26.4)	(7.5)	(50.6)
Accounts receivable - trade, net	(0.8)	(0.5)
Accounts receivable - related parties	(1,530.1)	(1,289.3)
Inventories	(0.4)	(1.4)
Derivative assets	0.3	0.0
Prepaid and other current assets	(10.2)	(12.6)
Total current assets	(1,574.8)	(1,330.2)
Property, plant and equipment, net	(3.8)	1.5
Investments in unconsolidated affiliates	(45,518.1)	(43,255.2)
Intangible assets, net	(13.8)	(13.8)
Goodwill	0.0	0.0
Other assets	(222.1)	(211.0)
Total assets	(47,332.6)	(44,808.7)
Current liabilities:
Current maturities of debt	0.0	0.0
Accounts payable - trade	(35.5)	(26.4)
Accounts payable - related parties	(1,543.9)	(1,305.0)
Accrued product payables	(1.2)	(1.3)
Accrued interest	(0.8)	0.0
Derivative liabilities	0.3	0.0
Other current liabilities	(9.4)	(10.8)
Total current liabilities	(1,590.5)	(1,343.5)
Long-term debt	0.0	0.0
Deferred tax liabilities	(0.9)	(0.5)
Other long-term liabilities	(221.9)	(212.4)
Commitments and contingencies
Equity:
Partners' and other owners' equity	(45,917.9)	(43,433.3)
Noncontrolling interests	398.6	181.0
Total equity	(45,519.3)	(43,252.3)
Total liabilities and equity	(47,332.6)	(44,808.7)
Enterprise Products Partners L.P. (Guarantor) [Member]
Current assets:
Cash and cash equivalents and restricted cash	0.0	0.0	$ 0.0	$ 0.0
Accounts receivable - trade, net	0.0	0.0
Accounts receivable - related parties	0.8	0.0
Inventories	0.0	0.0
Derivative assets	0.0	0.0
Prepaid and other current assets	0.0	0.0
Total current assets	0.8	0.0
Property, plant and equipment, net	0.0	0.0
Investments in unconsolidated affiliates	24,273.6	22,881.5
Intangible assets, net	0.0	0.0
Goodwill	0.0	0.0
Other assets	0.9	1.0
Total assets	24,275.3	22,882.5
Current liabilities:
Current maturities of debt	0.0	0.0
Accounts payable - trade	0.0	0.1
Accounts payable - related parties	31.9	1.3
Accrued product payables	0.0	0.0
Accrued interest	0.0	0.0
Derivative liabilities	0.0	0.0
Other current liabilities	0.0	0.0
Total current liabilities	31.9	1.4
Long-term debt	0.0	0.0
Deferred tax liabilities	0.0	0.0
Other long-term liabilities	389.9	333.9
Commitments and contingencies
Equity:
Partners' and other owners' equity	23,853.5	22,547.2
Noncontrolling interests	0.0	0.0
Total equity	23,853.5	22,547.2
Total liabilities and equity	$ 24,275.3	$ 22,882.5

Condensed Consolidating Financial Information, Statements of Operations (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

$ 9,182.3

$ 9,585.9

$ 8,467.5

$ 9,298.5

$ 8,426.6

$ 6,886.9

$ 6,607.6

$ 7,320.4

$ 36,534.2

^[1]

$ 29,241.5

^[2]

$ 23,022.3

^[2]

31,397.3

25,557.5

19,643.5

208.3

181.1

160.1

31,605.6

25,738.6

19,803.6

480.0

426.0

362.0

1,640.4

1,643.3

986.4

1,138.5

1,079.4

879.2

938.7

1,031.6

5,408.6

3,928.9

3,580.7

(1,096.7)

(984.6)

(982.6)

(13.1)

(63.0)

(21.7)

(1,109.8)

(1,047.6)

(1,004.3)

4,298.8

2,881.3

2,576.4

(60.3)

(25.7)

(23.4)

Net income attributable to noncontrolling interests

1,305.2

1,334.6

687.2

911.5

797.3

621.3

666.0

771.0

4,238.5

2,855.6

2,553.0

(66.1)

(56.3)

(39.9)

Eliminations and Adjustments [Member]

$ 1,284.7

$ 1,313.2

$ 673.8

$ 900.7

$ 774.0

$ 610.9

$ 653.7

$ 760.7

4,172.4

2,799.3

2,513.1

Condensed Consolidated Statement of Operations Information [Abstract]

0.0

0.0

0.1

0.0

0.1

0.0

(4,230.8)

(2,865.4)

(2,539.9)

(4,230.9)

(2,865.4)

(2,539.9)

0.0

0.0

0.0

(4,230.9)

(2,865.4)

(2,539.9)

(1.5)

0.0

(2.1)

Net income attributable to noncontrolling interests

(4,232.4)

(2,865.4)

(2,542.0)

5.3

Subsidiary Issuer (EPO) [Member]

(4,227.1)

(2,860.1)

(2,536.7)

Condensed Consolidated Statement of Operations Information [Abstract]

42,946.4

40,696.8

28,958.7

41,718.2

39,809.6

28,108.2

31.8

31.4

22.5

41,750.0

39,841.0

28,130.7

4,148.3

2,990.1

2,686.1

5,344.7

3,845.9

3,514.1

(1,097.1)

(982.5)

(973.1)

12.1

9.2

8.3

(1,085.0)

(973.3)

(964.8)

4,259.7

2,872.6

2,549.3

(29.2)

(12.0)

(13.1)

Net income attributable to noncontrolling interests

4,230.5

2,860.6

2,536.2

0.0

Other Subsidiaries (Non-guarantor) [Member]

4,230.5

2,860.6

2,536.2

Condensed Consolidated Statement of Operations Information [Abstract]

23,756.4

18,451.2

15,296.8

19,845.2

15,654.9

12,768.9

172.0

148.0

135.3

20,017.2

15,802.9

12,904.2

587.2

566.8

521.7

4,326.4

3,215.1

2,914.3

(10.5)

(11.8)

(17.3)

41.8

1.8

2.3

31.3

(10.0)

(15.0)

4,357.7

3,205.1

2,899.3

(29.6)

(13.7)

(8.2)

Net income attributable to noncontrolling interests

4,328.1

3,191.4

2,891.1

(7.6)

(6.5)

(7.4)

Consolidated EPO and Subsidiaries [Member]

4,320.5

3,184.9

2,883.7

Condensed Consolidated Statement of Operations Information [Abstract]

36,534.2

29,241.5

23,022.3

31,397.3

25,557.5

19,643.5

205.9

179.3

157.8

31,603.2

25,736.8

19,801.3

480.0

426.0

362.0

5,411.0

3,930.7

3,583.0

(1,096.7)

(984.6)

(982.6)

43.0

1.3

2.8

(1,053.7)

(983.3)

(979.8)

4,357.3

2,947.4

2,603.2

(58.8)

(25.7)

(21.3)

Net income attributable to noncontrolling interests

4,298.5

2,921.7

2,581.9

(71.4)

(61.6)

(45.2)

Consolidated EPO and Subsidiaries [Member] | Eliminations and Adjustments [Member]

4,227.1

2,860.1

2,536.7

Condensed Consolidated Statement of Operations Information [Abstract]

(30,168.6)

(29,906.5)

(21,233.2)

(30,166.1)

(29,907.0)

(21,233.6)

2.1

(0.1)

0.0

(30,164.0)

(29,907.1)

(21,233.6)

(4,255.5)

(3,130.9)

(2,845.8)

(4,260.1)

(3,130.3)

(2,845.4)

10.9

9.7

7.8

(10.9)

(9.7)

(7.8)

0.0

(4,260.1)

(3,130.3)

(2,845.4)

0.0

Net income attributable to noncontrolling interests

(4,260.1)

(3,130.3)

(2,845.4)

(63.8)

(55.1)

(37.8)

Enterprise Products Partners L.P. (Guarantor) [Member]

(4,323.9)

(3,185.4)

(2,883.2)

Condensed Consolidated Statement of Operations Information [Abstract]

0.0

0.0

2.3

1.8

2.3

2.3

1.8

2.3

4,230.8

2,865.4

2,539.9

4,228.5

2,863.6

2,537.6

0.0

(56.1)

(64.3)

(24.5)

(56.1)

(64.3)

(24.5)

4,172.4

2,799.3

2,513.1

0.0

Net income attributable to noncontrolling interests

4,172.4

2,799.3

2,513.1

0.0