Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

For the Three Months Ended March 31, 2018 and 2017

The following information should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and accompanying Notes included in this quarterly report on Form 10-Q and the Audited Consolidated Financial Statements and related Notes, together with our discussion and analysis of financial position and results of operations, included in our annual report on Form 10-K for the year ended December 31, 2017 (the “2017 Form 10-K”), as filed on February 28, 2018 with the U.S. Securities and Exchange Commission (“SEC”). Our financial statements have been prepared in accordance with generally accepted accounting principles (“GAAP”) in the United States (“U.S.”).

Key References Used in this Management’s Discussion and Analysis

Unless the context requires otherwise, references to “we,” “us,” “our,” “Enterprise” or “Enterprise Products Partners” are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries. References to “EPO” mean Enterprise Products Operating LLC, which is a wholly owned subsidiary of Enterprise, and its consolidated subsidiaries, through which Enterprise Products Partners L.P. conducts its business. Enterprise is managed by its general partner, Enterprise Products Holdings LLC (“Enterprise GP”), which is a wholly owned subsidiary of Dan Duncan LLC, a privately held Texas limited liability company.

The membership interests of Dan Duncan LLC are owned by a voting trust, the current trustees (“DD LLC Trustees”) of which are: (i) Randa Duncan Williams, who is also a director and Chairman of the Board of Directors (the “Board”) of Enterprise GP; (ii) Richard H. Bachmann, who is also a director and Vice Chairman of the Board of Enterprise GP; and (iii) Dr. Ralph S. Cunningham. Ms. Duncan Williams and Mr. Bachmann also currently serve as managers of Dan Duncan LLC along with W. Randall Fowler, who is also a director and President of Enterprise GP.

References to “EPCO” mean Enterprise Products Company, a privately held Texas corporation, and its privately held affiliates. A majority of the outstanding voting capital stock of EPCO is owned by a voting trust, the current trustees (“EPCO Trustees”) of which are: (i) Ms. Duncan Williams, who serves as Chairman of EPCO; (ii) Dr. Cunningham, who serves as Vice Chairman of EPCO; and (iii) Mr. Bachmann, who serves as the President and Chief Executive Officer of EPCO. Ms. Duncan Williams and Mr. Bachmann also currently serve as directors of EPCO along with Mr. Fowler, who is also the Executive Vice President and Chief Administrative Officer of EPCO. EPCO, together with its privately held affiliates, owned approximately 32% of our limited partner interests at March 31, 2018.

As generally used in the energy industry and in this quarterly report, the acronyms below have the following meanings:

/d	=	per day	MMBbls	=	million barrels
BBtus	=	billion British thermal units	MMBPD	=	million barrels per day
Bcf	=	billion cubic feet	MMBtus	=	million British thermal units
BPD	=	barrels per day	MMcf	=	million cubic feet
MBPD	=	thousand barrels per day	TBtus	=	trillion British thermal units

As used in this quarterly report, the phrase “quarter-to-quarter” means the first quarter of 2018 compared to the first quarter of 2017.

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Cautionary Statement Regarding Forward-Looking Information

This quarterly report on Form 10-Q contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us. When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “seek,” “goal,” “estimate,” “forecast,” “intend,” “could,” “should,” “would,” “will,” “believe,” “may,” “potential” and similar expressions and statements regarding our plans and objectives for future operations are intended to identify forward-looking statements. Although we and our general partner believe that our expectations reflected in such forward-looking statements are reasonable, neither we nor our general partner can give any assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions as described in more detail under Part I, Item 1A of our 2017 Form 10-K and within Part II, Item 1A of this quarterly report. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. You should not put undue reliance on any forward-looking statements. The forward-looking statements in this quarterly report speak only as of the date hereof. Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason.

Overview of Business

We are a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.” We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO and are a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, petrochemicals and refined products.

Our integrated midstream energy asset network links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the U.S., Canada and the Gulf of Mexico with domestic consumers and international markets. Our midstream energy operations currently include: natural gas gathering, treating, processing, transportation and storage; NGL transportation, fractionation, storage, and export and import terminals (including those used to export liquefied petroleum gases, or “LPG,” and ethane); crude oil gathering, transportation, storage, and export and import terminals; petrochemical and refined products transportation, storage, export and import terminals, and related services; and a marine transportation business that operates primarily on the U.S. inland and Intracoastal Waterway systems. Our assets currently include approximately 50,000 miles of pipelines; 260 MMBbls of storage capacity for NGLs, crude oil, petrochemicals and refined products; and 14 Bcf of natural gas storage capacity.

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.

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.

Each of our business segments benefits from the supporting role of our related marketing activities. The main purpose of our marketing activities is to support the utilization and expansion of assets across our midstream energy asset network by increasing the volumes handled by such assets, which results in additional fee-based earnings for each business segment. In performing these support roles, our marketing activities also seek to participate in supply and demand opportunities as a supplemental source of gross operating margin, a non-generally accepted accounting principle (“non-GAAP”) financial measure, for the partnership. The financial results of our marketing efforts fluctuate due to changes in volumes handled and overall market conditions, which are influenced by current and forward market prices for the products bought and sold.

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We provide investors access to additional information regarding our partnership, including information relating to our governance procedures and principles, through our website, www.enterpriseproducts.com.

Significant Recent Developments

Enterprise and Energy Transfer form Joint Venture to Restore Service on Old Ocean Pipeline

In May 2018, we announced the formation of a 50/50 joint venture with Energy Transfer Partners, L.P. (“Energy Transfer”) to resume service on the Old Ocean natural gas pipeline owned by Energy Transfer. 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. The Old Ocean Pipeline is expected to resume service in the second quarter of 2018 and provide natural gas transportation capacity of approximately 160 MMcf/d. The resumption of service on the Old Ocean Pipeline will provide producers with additional takeaway capacity from the growing Delaware Basin and Midland Basin.

In addition, both parties are expanding their jointly owned North Texas 36-inch diameter pipeline, which is a component of our Texas Intrastate System, to provide additional natural gas takeaway capacity of 150 MMcf/d from West Texas for deliveries into the Old Ocean Pipeline. The North Texas Pipeline expansion project is expected to be complete by late fourth quarter of 2018.

Proposed Expansions of our Front Range Pipeline and Texas Express Pipelines

In May 2018, we announced the start of a binding open commitment period to determine shipper interest in proposed expansions of our Front Range Pipeline (“Front Range”) and Texas Express Pipeline (“Texas Express”). The binding open commitment periods extend to June 4, 2018.

The proposed expansions are designed to facilitate growing production of NGLs from domestic shale basins, including the Denver-Julesburg (“DJ”) Basin in Colorado, by providing DJ Basin producers with flow assurance and greater access to the Gulf Coast markets. If constructed, the expansions would increase the transportation capacity of Front Range and Texas Express by 100 MBPD and 90 MBPD, respectively. The expansion projects, which are subject to receiving sufficient commitments from shippers, would begin service during the second quarter of 2019.

Enterprise Begins Service at Orla Natural Gas Processing Plant in the Delaware Basin

In May 2018, we announced the start of commercial operations for the initial processing train (“Orla I”) at our new cryogenic natural gas processing facility located near Orla, Texas in Reeves County. The Orla I plant has a nameplate natural gas processing capacity of 300 MMcf/d and is capable of extracting in excess of 40 MBPD of NGLs. We expect that the second and third processing trains at the facility (Orla II and Orla III) will be placed into service in the fourth quarter of 2018 and third quarter of 2019, respectively. Once Orla III is completed, the Orla facility is expected to have up to 1 Bcf/d of aggregate natural gas processing capacity and the ability to extract up to 150 MBPD of NGLs. We own and operate the Orla facility.

In conjunction with the start-up of Orla I, we placed into service approximately 70 miles of natural gas pipelines that connect the Orla facility to our Texas Intrastate System. We also placed into service a 30-mile extension of our NGL system that will provide producers at the Orla facility with NGL takeaway capacity and direct access to our integrated network of downstream NGL assets.

Enterprise Expands Marine Terminal on the Houston Ship Channel

In April 2018, we purchased a 65-acre waterfront site located on the Houston Ship Channel that will serve as the next phase of expansion at our Enterprise Hydrocarbons Terminal (“EHT”). Located immediately to the east of EHT, the property features two existing docks, dredging infrastructure that will be utilized for maintenance and dock expansion at the site, and land that we plan to use for expanding our marine terminal capabilities at EHT. Our future plans for the site include the construction of at least two additional deepwater docks capable of accommodating Suezmax vessels.

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Expected Sale of 20% Ownership Interest in Midland-to-ECHO Pipeline

In April 2018, an affiliate of Western Gas Partners, LP (“Western”) exercised its option to acquire a noncontrolling 20% ownership interest in the Midland-to-ECHO crude oil pipeline and its related commercial activities for approximately $200 million. This transaction is expected to close in mid-2018 subject to the execution of definitive agreements.

At closing, Western will be credited for 20% of the pipeline’s earnings since it was placed into service in November 2017. Our expected obligation to Western related to the pipeline’s earnings totaled $35.9 million at March 31, 2018, which is a component of other current liabilities on our Unaudited Condensed Consolidated Balance Sheet. As a result of this arrangement, we report the pipeline’s volumes on a net basis reflecting our expected 80% ownership. Western is also expected to proportionately share in the results of our limited commercial activities attributable to the pipeline.

Enterprise Begins Full Service on Midland-to-ECHO Pipeline

In April 2018, we announced that the 416-mile Midland-to-Sealy segment of our Midland-to-ECHO Pipeline is now in full service with an expanded transportation capacity of 540 MBPD. The completed pipeline provides Permian Basin producers with the ability to transport multiple grades of crude oil, including West Texas Intermediate (“WTI”), Light WTI, West Texas Sour and condensate, to Gulf Coast markets.

By the end of May 2018, we expect to increase the pipeline’s capacity to 575 MBPD with the completion of incremental tankage and additional infrastructure as well as operating enhancements. In addition, we expect to complete a 143-mile pipeline system that will deliver more than 300 MBPD of crude oil and condensate from the Delaware Basin to our Midland Terminal. This project is scheduled for completion in July 2018 and is supported by long-term commitments from shippers.

Acquisition of Remaining 50% Ownership Interest in Waha Gas Plant

In March 2018, we acquired the remaining 50% member interest in our Delaware Basin Gas Processing LLC (“Delaware Processing”) joint venture for $153.6 million in cash. Delaware Processing owns a cryogenic natural gas processing facility (our “Waha” gas plant) having a capacity of 150 MMcf/d. The Waha plant 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. For information regarding this acquisition, see Note 11 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

Plans to Build Ethylene Export Dock and Related Projects

In January 2018, we announced the formation of a new 50/50 joint venture with Navigator Holdings Ltd. (“Navigator”) to construct, own and operate an ethylene export facility along the U.S. Gulf Coast. The export facility is expected to have the capacity to export approximately one million tons of ethylene per year, with loading rates of approximately 1,000 tons per hour. In addition, the facility is expected to include refrigerated storage for 30,000 tons of ethylene. The project, which is underwritten by long-term contracts with customers, is expected to be completed in the fourth quarter of 2019. The location and final investment decisions for the terminal are subject to reaching acceptable arrangements with local taxing authorities.

Enterprise to Expand Butane Isomerization Facility

In January 2018, we announced plans to expand our butane isomerization facility by up to 30 MBPD of incremental capacity. This expansion is supported by new long-term agreements, including a 20-year, 35 MBPD fee-based, tolling arrangement, to provide butane isomerization, storage and pipeline services.

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Results of Operations

Summarized Consolidated Income Statement Data

The following table summarizes the key components of our results of operations for the periods indicated (dollars in millions):

	For the Three Months Ended March 31,
	2018			2017
Revenues	$	9,298.5		$	7,320.4
Costs and expenses:
Operating costs and expenses:
Cost of sales		7,140.4			5,335.7
Other operating costs and expenses		687.6			610.4
Depreciation, amortization and accretion expenses		394.3			376.2
Net gains attributable to asset sales		(0.5	)		(0.3	)
Asset impairment and related charges		0.9			11.2
Total operating costs and expenses		8,222.7			6,333.2
General and administrative costs		53.0			50.4
Total costs and expenses		8,275.7			6,383.6
Equity in income of unconsolidated affiliates		115.7			94.8
Operating income		1,138.5			1,031.6
Interest expense		(252.1	)		(249.3	)
Other income (expense), net		30.2			(5.3	)
Provision for income taxes		(5.1	)		(6.0	)
Net income		911.5			771.0
Net income attributable to noncontrolling interests		(10.8	)		(10.3	)
Net income attributable to limited partners	$	900.7		$	760.7

Consolidated Revenues

We classify our revenues into sales of products and midstream services. Product sales relate primarily to our various marketing activities whereas midstream services represent our other integrated businesses (i.e., gathering, processing, transportation, fractionation, storage and terminaling). The following table presents our revenues by business segment, and further by revenue type, for the periods indicated (net of eliminations, dollars in millions):

	For the Three Months Ended March 31,
	2018		2017
NGL Pipelines & Services:
Sales of NGLs and related products	$	2,815.4	$	2,887.2
Midstream services		597.9		458.6
Total		3,413.3		3,345.8
Crude Oil Pipelines & Services:
Sales of crude oil		3,341.7		1,618.6
Midstream services		229.2		188.6
Total		3,570.9		1,807.2
Natural Gas Pipelines & Services:
Sales of natural gas		560.0		544.0
Midstream services		244.8		217.2
Total		804.8		761.2
Petrochemical & Refined Products Services:
Sales of petrochemicals and refined products		1,289.3		1,211.1
Midstream services		220.2		195.1
Total		1,509.5		1,406.2
Total consolidated revenues	$	9,298.5	$	7,320.4

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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. Effective January 1, 2018, we adopted FASB ASC 606, Revenue from Contracts with Customers, using a modified retrospective approach that applied the new revenue recognition standard to existing contracts at the implementation date and any future revenue contracts. For information regarding this change in accounting principle (including various transition disclosures), see Notes 2 and 9 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

Selected Energy Commodity Price Data

The following table presents selected average index prices for natural gas and selected NGL and petrochemical products for the periods indicated:

													Polymer		Refinery
	Natural						Normal				Natural		Grade		Grade
	Gas,		Ethane,		Propane,		Butane,		Isobutane,		Gasoline,		Propylene,		Propylene,
	$/MMBtu		$/gallon		$/gallon		$/gallon		$/gallon		$/gallon		$/pound		$/pound
	(1)		(2)		(2)		(2)		(2)		(2)		(3)		(3)
2017 by quarter:
1st Quarter	$	3.32	$	0.23	$	0.71	$	0.98	$	0.94	$	1.10	$	0.47	$	0.32
2nd Quarter	$	3.19	$	0.25	$	0.63	$	0.76	$	0.75	$	1.07	$	0.41	$	0.28
3rd Quarter	$	2.99	$	0.26	$	0.77	$	0.91	$	0.92	$	1.10	$	0.42	$	0.28
4th Quarter	$	2.93	$	0.25	$	0.96	$	1.04	$	1.04	$	1.32	$	0.49	$	0.35
2017 Averages	$	3.11	$	0.25	$	0.77	$	0.92	$	0.91	$	1.15	$	0.45	$	0.31

2018 by quarter:
1st Quarter	$	3.01	$	0.25	$	0.85	$	0.96	$	1.00	$	1.41	$	0.53	$	0.33

(1) Natural gas prices are based on Henry-Hub Inside FERC commercial index prices as reported by Platts, which is a division of McGraw Hill Financial, Inc. (2) NGL prices for ethane, propane, normal butane, isobutane and natural gasoline are based on Mont Belvieu Non-TET commercial index prices as reported by Oil Price Information Service. (3) Polymer grade propylene prices represent average contract pricing for such product as reported by IHS Chemical, a division of IHS Inc. (“IHS Chemical”). Refinery grade propylene prices represent weighted-average spot prices for such product as reported by IHS Chemical.

The following table presents selected average index prices for crude oil for the periods indicated:


	WTI		Midland		Houston		LLS
	Crude Oil,		Crude Oil,		Crude Oil		Crude Oil,
	$/barrel		$/barrel		$/barrel		$/barrel
	(1)		(2)		(2)		(3)
2017 by quarter:
1st Quarter	$	51.91	$	51.72	$	53.27	$	53.52
2nd Quarter	$	48.28	$	47.29	$	49.77	$	50.31
3rd Quarter	$	48.20	$	47.37	$	50.84	$	51.62
4th Quarter	$	55.40	$	55.47	$	59.84	$	61.07
2017 Averages	$	50.95	$	50.44	$	53.41	$	54.13

2018 by quarter:
1st Quarter	$	62.87	$	62.51	$	65.47	$	65.79

(1) WTI prices are based on commercial index prices at Cushing, Oklahoma as measured by the New York Mercantile Exchange. (2) Midland and Houston crude oil prices are based on commercial index prices as reported by Argus. (3) Light Louisiana Sweet (“LLS”) prices are based on commercial index prices as reported by Platts.

Fluctuations in our consolidated revenues and cost of sales amounts are explained in large part by changes in energy commodity prices. Energy commodity prices fluctuate for a variety of reasons, including supply and demand imbalances and geopolitical tensions. The weighted-average indicative market price for NGLs was $0.77 per gallon in the first quarter of 2018 versus $0.66 per gallon during the first quarter of 2017.

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An increase in our consolidated marketing revenues due to higher energy commodity sales prices may not result in an increase in gross operating margin or cash available for distribution, since our consolidated cost of sales amounts would also be higher due to comparable increases in the purchase prices of the underlying energy commodities. The same correlation would be true in the case of lower energy commodity sales prices and purchase costs.

We attempt to mitigate commodity price exposure through our hedging activities and the use of fee-based arrangements. See Note 14 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report for information regarding our commodity hedging activities.

Consolidated Income Statement Highlights

The following information highlights significant changes in our comparative income statement amounts and the primary drivers of such changes.

Revenues

Total revenues for the first quarter of 2018 increased $1.98 billion when compared to the first quarter of 2017 primarily due to a $1.75 billion increase in marketing revenues. Revenues from the marketing of crude oil increased $1.72 billion quarter-to-quarter primarily due to higher sales volumes, which accounted for a $1.38 billion increase, and higher sales prices, which accounted for an additional $345.4 million increase. Crude oil marketing sales volumes increased quarter-to-quarter as we seek to optimize the utilization of our crude oil pipelines and related assets (e.g., the Midland-to-ECHO Pipeline) and capitalize on pricing opportunities attributable to significant increases in crude oil production in West Texas and the Permian Basin. Revenues from the marketing of petrochemicals increased $70.3 million quarter-to-quarter primarily due to higher prices for propylene. Revenues from the marketing of NGLs and related products decreased a net $71.8 million quarter-to-quarter primarily due to lower sales volumes, which accounted for a $556.5 million decrease, partially offset by a $484.7 million increase due to higher sales prices.

Revenues from midstream services for the first quarter of 2018 increased $232.6 million when compared to the first quarter of 2017. As a result of adopting ASC 606, we recognized $113.8 million of revenues during the first quarter of 2018 in connection with the receipt of non-cash consideration (in the form of equity NGLs) for providing natural gas processing services. Midstream service revenues from our pipeline assets increased $101.3 million quarter-to-quarter primarily due to strong demand for transportation services in Texas and on the Appalachia-to-Texas Express (“ATEX”) pipeline. Propylene fractionation revenues increased $14.0 million quarter-to-quarter primarily due to higher fees.

Operating costs and expenses

Total operating costs and expenses for the first quarter of 2018 increased $1.89 billion when compared to the first quarter of 2017 primarily due to a $1.80 billion increase in cost of sales. The cost of sales associated with our marketing of crude oil increased $1.76 billion quarter-to-quarter primarily due to higher sales volumes, which accounted for a $1.31 billion increase, and higher purchase prices, which accounted for an additional $447.4 million increase. The cost of sales associated with our NGL marketing activities increased $136.8 million quarter-to-quarter primarily due to the sale of NGLs received in connection with providing natural gas processing services (i.e., equity NGLs).

Other operating costs and expenses for the first quarter of 2018 increased a net $77.2 million when compared to the first quarter of 2017. Employee compensation, power and maintenance costs increased a combined $38.4 million quarter-to-quarter. Depreciation, amortization and accretion expense increased $18.1 million quarter-to-quarter primarily due to assets we constructed and placed into service since the first quarter of 2017 (e.g., our Midland-to-ECHO pipeline and the assets we acquired from Azure Midstream Partners, LP and its operating subsidiaries (collectively, “Azure”)). Non-cash asset impairment charges decreased $10.3 million quarter-to-quarter. Our non-cash asset impairment charges for the first quarter of 2017 primarily related to the write-down of materials held as spare parts.

General and administrative costs

General and administrative costs for the first quarter of 2018 increased a net $2.6 million when compared to the first quarter of 2017. Employee compensation and legal-related costs increased a combined $7.3 million quarter-to-quarter, partially offset by a $4.6 million quarter-to-quarter decrease in regulatory costs.

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Equity in income of unconsolidated affiliates

Equity income from our unconsolidated affiliates for the first quarter of 2018 increased $20.9 million when compared to the same period in 2017 primarily due to an increase in earnings from our investments in crude oil pipelines.

Operating income

Operating income for the first quarter of 2018 increased $106.9 million due to the previously described quarter-to-quarter changes in revenues, operating costs and expenses, general and administrative costs and equity in income of unconsolidated affiliates.

Interest expense

Interest expense for the first quarter of 2018 increased $2.8 million when compared to the first quarter of 2017. The following table presents the components of our consolidated interest expense for the periods indicated (dollars in millions):

	For the Three Months Ended March 31,
	2018			2017
Interest charged on debt principal outstanding	$	292.0		$	272.9
Impact of interest rate hedging program, including related amortization (1)		3.7			8.7
Interest costs capitalized in connection with construction projects (2)		(58.2	)		(39.6	)
Other (3)		14.6			7.3
Total	$	252.1		$	249.3

(1) Amount presented for first quarter of 2018 includes $7.2 million of swaption premium income. (2) We capitalize interest costs incurred on funds used to construct property, plant and equipment while the asset is in its construction phase. Capitalized interest amounts become part of the historical cost of an asset and are charged to earnings (as a component of depreciation expense) on a straight-line basis over the estimated useful life of the asset once the asset enters its intended service. When capitalized interest is recorded, it reduces interest expense from what it would be otherwise. Capitalized interest amounts fluctuate based on the timing of when projects are placed into service, our capital spending levels and the interest rates charged on borrowings. (3) Primarily reflects facility commitment fees charged in connection with our revolving credit facilities and amortization of debt issuance costs. Amount presented for the first quarter of 2018 includes $7.8 million of debt issuance costs that were written off in March 2018 in connection with the redemption of Junior Subordinated Notes B.

Interest charged on debt principal outstanding, which is the primary driver of interest expense, increased $19.1 million quarter-to-quarter primarily due to increased debt principal amounts outstanding during the first quarter of 2018, which accounted for a $17.8 million increase, and the effect of higher overall interest rates during the first quarter of 2018, which accounted for a $1.3 million increase. Our weighted-average debt principal balance for the first quarter of 2018 was $25.24 billion compared to $23.67 billion for the first quarter of 2017.

Our debt principal balances have increased over time due to the partial debt financing of our capital spending program. For a discussion of our consolidated debt obligations and capital spending program, see “Liquidity and Capital Resources” and “Capital Spending” within this Part I, Item 2.

Gain on step acquisition of unconsolidated affiliate

We recognized a gain of $37.0 million related to the step acquisition of Delaware Processing. For information regarding this acquisition, see Note 11 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

Income taxes

Income taxes primarily reflect our state tax obligations under the Revised Texas Franchise Tax. Our provision for income taxes for the first quarter of 2018 decreased $0.9 million when compared to the same period in 2017.

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Total 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.

The following table presents gross operating margin by segment and non-GAAP total gross operating margin for the periods indicated (dollars in millions):

	For the Three Months Ended March 31,
	2018		2017
Gross operating margin by segment:
NGL Pipelines & Services	$	884.9	$	856.0
Crude Oil Pipelines & Services		220.0		264.6
Natural Gas Pipelines & Services		197.9		170.9
Petrochemical & Refined Products Services		271.9		181.8
Total segment gross operating margin (1)		1,574.7		1,473.3
Net adjustment for shipper make-up rights		11.5		(4.2	)
Total gross operating margin (non-GAAP)	$	1,586.2	$	1,469.1

(1) Within the context of this table, total segment gross operating margin represents a subtotal and corresponds to measures similarly titled within our business segment disclosures found in Note 10 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

Total gross operating margin includes equity in the earnings of unconsolidated affiliates, but is exclusive of other income and expense transactions, income taxes, the cumulative effect of changes in accounting principles and extraordinary charges. Total gross operating margin is presented on a 100% basis before any allocation of earnings to noncontrolling interests.

Gross operating margin by segment for NGL Pipelines & Services and Crude Oil Pipelines & Services reflect adjustments for shipper make-up rights that are included in management’s evaluation of segment results. However, these adjustments are excluded from non-GAAP total gross operating margin.

The GAAP financial measure most directly comparable to total gross operating margin is operating income. For a discussion of operating income and its components, see the previous section titled “Consolidated Income Statement Highlights” within this Item 2. The following table presents a reconciliation of operating income to total gross operating margin for the periods indicated (dollars in millions):

	For the Three Months Ended March 31,
	2018			2017
Operating income (GAAP)	$	1,138.5		$	1,031.6
Adjustments to reconcile operating income to total gross operating margin:
Add depreciation, amortization and accretion expense in operating costs and expenses		394.3			376.2
Add asset impairment and related charges in operating costs and expenses		0.9			11.2
Subtract net gains attributable to asset sales in operating costs and expenses		(0.5	)		(0.3	)
Add general and administrative costs		53.0			50.4
Total gross operating margin (non-GAAP)	$	1,586.2		$	1,469.1

Each of our business segments benefits from the supporting role of our marketing activities. The main purpose of our marketing activities is to support the utilization and expansion of assets across our midstream energy asset network by increasing the volumes handled by such assets, which results in additional fee-based earnings for each business segment. In performing these support roles, our marketing activities also seek to participate in supply and demand opportunities as a supplemental source of gross operating margin for the partnership. The financial results of our marketing efforts fluctuate due to changes in volumes handled and overall market conditions, which are influenced by current and forward market prices for the products bought and sold.

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The following information highlights significant changes in our quarter-to-quarter segment results (i.e., our gross operating margin by segment amounts) and the primary drivers of such changes. The volume statistics presented for each segment are reported on a net basis, taking into account our ownership interests, and reflect the periods in which we owned an interest in such operations.

Business Segment Highlights

The following discussions of gross operating margin by segment are based on amounts actually recognized in our Unaudited Condensed Statements of Consolidated Operations for the first quarters of 2018 and 2017.

NGL Pipelines & Services

The following table presents segment gross operating margin and selected volumetric data for the NGL Pipelines & Services segment for the periods indicated (dollars in millions, volumes as noted):

	For the Three Months Ended March 31,
	2018		2017
Segment gross operating margin:
Natural gas processing and related NGL marketing activities	$	248.5	$	277.9
NGL pipelines, storage and terminals		509.3		454.9
NGL fractionation		127.1		123.2
Total	$	884.9	$	856.0
Selected volumetric data:
Equity NGL production (MBPD) (1)		165		150
Fee-based natural gas processing (MMcf/d) (2)		4,364		4,489
NGL pipeline transportation volumes (MBPD)		3,287		3,225
NGL marine terminal volumes (MBPD)		575		569
NGL fractionation volumes (MBPD)		824		799

(1) Represents the NGL volumes we earn and take title to in connection with our processing activities. (2) Volumes reported correspond to the revenue streams earned by our gas plants.

Natural gas processing and related NGL marketing activities. Gross operating margin from natural gas processing and related NGL marketing activities for the first quarter of 2018 decreased a net $29.4 million when compared to the first quarter of 2017.

Gross operating margin from our NGL marketing activities decreased a net $62.9 million quarter-to-quarter primarily due to lower sales volumes, which accounted for a $93.7 million decrease, partially offset by a $30.7 million increase due to higher sales margins. The results from marketing strategies to optimize our storage and export dock assets decreased a combined $72.3 million quarter-to-quarter, partially offset by a $19.6 million increase in earnings from the optimization of our transportation assets.

Gross operating margin from our natural gas processing plants increased $33.5 million quarter-to-quarter primarily due to higher average processing margins (including the impact of hedging activities) in the first quarter of 2018 at our Rockies and South Texas plants. In addition, higher equity NGL production in the first quarter of 2018 at our Meeker and Pioneer plants accounted for a $5.4 million quarter-to-quarter increase in gross operating margin. These increases were partially offset by the impact of lower fee-based processing volumes in the first quarter of 2018 at our Louisiana and South Texas plants, which accounted for a combined $4.5 million quarter-to-quarter decrease in gross operating margin.

NGL pipelines, storage and terminals. Gross operating margin from NGL pipelines, storage and terminal assets for the first quarter of 2018 increased a net $54.4 million when compared to the first quarter of 2017.

Gross operating margin from our Seminole, Chaparral and affiliated pipelines increased a combined $22.6 million quarter-to-quarter primarily due to higher average transportation fees, which accounted for a $12.7 million increase, and higher transportation volumes, which accounted for an additional $8.3 million increase. On a combined basis, NGL transportation volumes on these pipelines increased 37 MBPD quarter-to-quarter.

Gross operating margin from ATEX increased $18.6 million quarter-to-quarter primarily due to higher transportation volumes, which increased 32 MBPD in the first quarter of 2018.

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Gross operating margin from our equity investment in the Texas Express Pipeline increased $3.2 million quarter-to-quarter primarily due to contractual increases in committed volumes from anchor shippers.

Gross operating margin from our Dixie Pipeline and related terminals increased a combined $1.5 million quarter-to-quarter primarily due to higher transportation volumes of 21 MBPD in the first quarter of 2018, which accounted for a $4.4 million increase, partially offset by higher operating costs, which accounted for a $3.1 million quarter-to-quarter decrease.

Gross operating margin from our South Texas NGL Pipeline System decreased $7.8 million quarter-to-quarter primarily due to lower transportation volumes, which accounted for a $4.7 million decrease, and lower storage revenues, which accounted for an additional $2.1 million decrease. Transportation volumes for the South Texas NGL Pipeline System decreased 39 MBPD quarter-to-quarter.

Gross operating margin from our storage complexes in South Louisiana and Mont Belvieu increased a combined $8.9 million quarter-to-quarter primarily due to increased storage and storage-related activity revenues.

Gross operating margin from our Morgan’s Point Ethane Export Terminal increased $12.0 million quarter-to-quarter primarily due to higher ethane loading volumes of 75 MBPD.

Gross operating margin from EHT decreased $11.0 million quarter-to-quarter primarily due to lower marine terminal volumes of 68 MBPD, which accounted for a $9.7 million decrease, and higher maintenance and other operating costs, which accounted for an additional $1.6 million decrease.

NGL fractionation. Gross operating margin from NGL fractionation for the first quarter of 2018 increased a net $3.9 million when compared to the first quarter of 2017 primarily due to higher product blending revenues at our Mont Belvieu and Hobbs NGL fractionators. NGL fractionation volumes at our Mont Belvieu facility increased 25 MBPD, net to our interest.

Crude Oil Pipelines & Services

The following table presents segment gross operating margin and selected volumetric data for the Crude Oil Pipelines & Services segment for the periods indicated (dollars in millions, volumes as noted):

	For the Three Months Ended March 31,
	2018		2017
Segment gross operating margin	$	220.0	$	264.6
Selected volumetric data:
Crude oil pipeline transportation volumes (MBPD)		2,034		1,356
Crude oil marine terminal volumes (MBPD)		634		475

Gross operating margin from our Crude Oil Pipelines & Services segment for the first quarter of 2018 decreased a net $44.6 million when compared to the first quarter of 2017.

Gross operating margin from our South Texas Crude Oil Pipeline System increased a net $39.8 million quarter-to-quarter primarily due to higher firm capacity reservation fees associated with the Midland-to-ECHO Pipeline, which accounted for a $24.0 million increase, and higher transportation volumes, which accounted for an additional $21.8 million increase, partially offset by lower average transportation fees, which accounted for a $7.2 million decrease. Crude oil transportation volumes for this system increased 65 MBPD quarter-to-quarter. Gross operating margin from our West Texas System and equity investment in the Eagle Ford Crude Oil Pipeline System increased a combined $6.8 million quarter-to-quarter primarily due to higher crude oil transportation volumes from the Permian Basin. Crude oil transportation volumes on the Eagle Ford Crude Oil Pipeline System increased 91 MBPD quarter-to-quarter (net to our interest) and 6 MBPD on the West Texas System.

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Gross operating margin from our ECHO and Midland terminals increased a net $9.7 million quarter-to-quarter primarily due to higher terminaling volumes, which accounted for a $7.5 million increase, higher average terminaling fees, which accounted for an additional $3.1 million increase, partially offset by higher maintenance and other operating costs, which accounted for a $1.0 million decrease. Gross operating margin from our EHT increased $8.1 million quarter-to-quarter primarily due to higher volumes of 181 MBPD.

Gross operating margin from our crude oil marketing activities, excluding those attributable to our commercial activities on the Midland-to-ECHO Pipeline (see below), decreased $46.1 million quarter-to-quarter primarily due to mark-to-market losses in the first quarter of 2018 in connection with the widening of crude oil commodity price differentials between the Midland, Texas and Cushing, Oklahoma markets.

Midland-to-ECHO Pipeline and related marketing activities. Gross operating margin from our Midland-to-ECHO Pipeline and related marketing activities was a combined loss of $60.2 million for the first quarter of 2018. Transportation volumes on the pipeline, which entered into limited commercial service during the fourth quarter of 2017 and full service in April 2018, averaged 398 MBPD during the first quarter (net to our interest).

Gross operating margin for this business during the first quarter of 2018 includes $114.0 million of non-cash mark-to-market losses associated with the hedging of crude oil commodity price differentials (basis spreads) between the Midland and Houston area markets. These hedges, which were entered into throughout 2017, served to lock in an average $2.59 per barrel positive margin on our anticipated purchases of crude oil at Midland and subsequent anticipated sales to customers in the Houston area for periods extending predominantly into 2019 and minimally in 2020. The mark-to-market losses recognized during the first quarter of 2018 were due to the widening of the basis spreads between Midland and Houston to an average of $5.99 per barrel through 2020 (as of March 31, 2018).

Basis swaps, in all but very limited circumstances, do not qualify for cash flow hedge accounting despite being highly effective at hedging the price risk inherent in the underlying physical transactions. The volume hedged throughout the remainder of 2018 through 2020 varies from quarter-to-quarter and year-to-year, however the hedge levels generally correspond to pipeline capacity currently expected to be available to us during the first three years of the pipeline’s operations as customer commitment volumes ramp up to peak levels.

If the basis spreads underlying these hedges widen further, we would be exposed to additional temporary non-cash mark-to-market losses. Conversely, if basis spreads narrow in the future reverting back towards or below the average $2.59 per barrel spread we originally locked in, then we would recognize temporary non-cash mark-to-market gains in future periods. When the forecasted physical receipts and deliveries of crude oil ultimately occur in the future, we will realize a physical gross margin at then prevailing commodity price spreads; however the realized settlement of the associated financial hedges will convert that physical margin to the average $2.59 per barrel spread of the financial hedges. At that time, the unrealized mark-to-market losses recognized in the first quarter of 2018 and in future periods until the physical deliveries occur will be reversed, thus eliminating their impact to cumulative earnings recognized over the entire life-to-date period of the hedge.

At March 31, 2018, approximately 47% of the Midland-to-EHCO Pipeline’s uncommitted capacity available to us through 2020 remains unhedged, thus providing us with potential upside to widening or downside to narrowing market spreads.

The basis spread between the Midland and Houston markets has continued to widen during the second quarter of 2018. For information regarding the impact of these higher spreads on our crude oil marketing hedging portfolio, see Item 3, Quantitative and Qualitative Disclosures about Market Risk, within this Part I, Item 2. For general information regarding our derivative instruments and hedging activities, see Note 14 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

Gross operating margin from the Midland-to-ECHO Pipeline for the first quarter of 2018 was also reduced by $24.2 million in connection with the expected allocation of pipeline earnings to Western upon closing of their acquisition of a 20% ownership interest in the pipeline. For additional information regarding this pending transaction, see “Significant Recent Developments” within this Part I, Item 2.

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Natural Gas Pipelines & Services

The following table presents segment gross operating margin and selected volumetric data for the Natural Gas Pipelines & Services segment for the periods indicated (dollars in millions, volumes as noted):

	For the Three Months Ended March 31,
	2018		2017
Segment gross operating margin	$	197.9	$	170.9
Selected volumetric data:
Natural gas pipeline transportation volumes (BBtus/d)		13,029		11,429

Gross operating margin from our Natural Gas Pipelines & Services segment for the first quarter of 2018 increased a net $27.0 million when compared to the first quarter of 2017.

Gross operating margin from our Texas Intrastate System increased a net $9.6 million quarter-to-quarter primarily due to higher firm capacity and other fees, which accounted for a $13.2 million increase, partially offset by higher maintenance and other operating costs, which accounted for a $3.6 million decrease. Transportation volumes on our Texas Intrastate System increased 45 BBtus/d quarter-to-quarter.

Gross operating margin from our Haynesville Gathering System increased $6.3 million quarter-to-quarter primarily due to higher gathering volumes, which accounted for $3.3 million of the increase, and higher treating revenues, which accounted for an additional $1.8 million increase. Gross operating margin from our Acadian Gas System decreased a net $0.2 million quarter-to-quarter primarily due to lower average transportation fees on the Haynesville Extension pipeline, which accounted for an $8.2 million decrease, and higher maintenance and other operating costs, which accounted for an additional $1.6 million decrease, partially offset by higher transportation volumes on the Haynesville Extension pipeline, which accounted for a $9.7 million increase. Transportation volumes for the Haynesville Extension pipeline, which is a component of the Acadian Gas System, increased 402 BBtus/d and volumes for the Haynesville Gathering System increased 329 BBtus/d.

Gross operating margin from our Jonah Gathering System increased $5.0 million quarter-to-quarter primarily due to a 194 BBtus/d increase in gathering volumes.

Gross operating margin from the East Texas natural gas pipeline assets we acquired from Azure in April 2017 was $5.0 million on gathering volumes of 279 BBtus/d.

Petrochemical & Refined Products Services

The following table presents segment gross operating margin and selected volumetric data for the Petrochemical & Refined Products Services segment for the periods indicated (dollars in millions, volumes as noted):

	For the Three Months Ended March 31,
	2018		2017
Segment gross operating margin:
Propylene production and related activities	$	129.4	$	68.6
Butane isomerization and related operations		24.7		10.9
Octane enhancement and related plant operations		32.4		18.9
Refined products pipelines and related activities		80.9		76.7
Marine transportation and other		4.5		6.7
Total	$	271.9	$	181.8

Selected volumetric data:
Propylene production volumes (MBPD)		105		80
Butane isomerization volumes (MBPD)		113		92
Standalone DIB processing volumes (MBPD)		78		83
Octane additive and related plant production volumes (MBPD)		26		20
Pipeline transportation volumes, primarily refined products and petrochemicals (MBPD)		852		827
Refined products and petrochemical marine terminal volumes (MBPD)		370		399

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Propylene production and related activities. Gross operating margin from propylene production and related marketing activities for the first quarter of 2018 increased $60.8 million when compared to the first quarter of 2017.

Gross operating margin from our Mont Belvieu propylene fractionation plants increased $41.6 million quarter-to-quarter primarily due to higher average propylene sales margins.

Commissioning costs at our PDH facility decreased $13.5 million quarter-to-quarter. This facility was placed into service in April 2018.

Gross operating margin from our Sorrento-to-Breaux Bridge RGP Pipeline was $4.1 million on transportation volumes of 23 MBPD. This pipeline was completed and placed into service in the fourth quarter of 2017.

Butane isomerization and related operations. Gross operating margin from butane isomerization and deisobutanizer (“DIB”) operations for the first quarter of 2018 increased $13.8 million when compared to the first quarter of 2017. The increase in gross operating margin is primarily due to higher by-product sales revenues, which accounted for $7.8 million of the quarter-to-quarter increase. Butane isomerization and standalone DIB processing volumes increased 21 MBPD and decreased 5 MBPD, respectively, quarter-to-quarter.

Octane enhancement and related operations. Gross operating margin from our octane enhancement facility and high purity isobutylene plant for the first quarter of 2018 increased $13.5 million when compared to the first quarter of 2017 primarily due to higher plant production volumes.

Refined products pipelines and related activities. Gross operating margin from refined products pipelines and related marketing activities for the first quarter of 2018 increased $4.2 million when compared to the first quarter of 2017.

Gross operating margin from our TE Products Pipeline and related refined products terminals increased a net $6.3 million quarter-to-quarter primarily due to higher NGL transportation volumes, which accounted for an increase of $8.1 million, and higher average transportation fees, which accounted for an additional increase of $4.6 million, partially offset by higher maintenance and other operating costs, which accounted for a $5.8 million decrease. NGL transportation volumes on our TE Products Pipeline increased 19 MBPD quarter-to-quarter.

Gross operating margin from our Houston Ship Channel refined products marine terminal decreased $2.7 million quarter-to-quarter primarily due to lower storage revenues.

Marine transportation and other. Gross operating margin from marine transportation for the first quarter of 2018 decreased $2.2 million when compared to the first quarter of 2017 primarily due to higher employee-related costs.

Liquidity and Capital Resources

Based on current market conditions (as of the filing date of this quarterly report), we believe we will have sufficient liquidity, cash flow from operations and access to capital markets to fund our capital expenditures and working capital needs for the reasonably foreseeable future. At March 31, 2018, we had $5.02 billion of consolidated liquidity, which was comprised of $4.92 billion of available borrowing capacity under EPO’s revolving credit facilities and $102.1 million of unrestricted cash on hand.

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

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Consolidated Debt

The following table presents scheduled maturities of our consolidated debt obligations outstanding at March 31, 2018 for the years indicated (dollars in millions):

			Scheduled Maturities of Debt
	Total		Remainder of 2018		2019		2020		2021		2022		Thereafter
Commercial Paper Notes	$	576.8	$	576.8	$	--	$	--	$	--	$	--	$	--
Senior Notes		21,850.0		1,100.0		1,500.0		1,500.0		1,325.0		650.0		15,775.0
Junior Subordinated Notes		3,191.7		--		--		--		--		--		3,191.7
Total	$	25,618.5	$	1,676.8	$	1,500.0	$	1,500.0	$	1,325.0	$	650.0	$	18,966.7

Issuance of $2.0 Billion of Senior Notes and $700 Million of Junior Subordinated Notes in February 2018

In February 2018, EPO issued $2.7 billion aggregate principal amount of notes comprised of (i) $750 million principal amount of senior notes due February 15, 2021 (“Senior Notes TT”), (ii) $1.25 billion principal amount of senior notes due February 15, 2048 (“Senior Notes UU”) and (iii) $700 million principal amount of junior subordinated notes due February 15, 2078 (“Junior Subordinated Notes F”).

Net proceeds from these offerings were used by EPO for the temporary repayment of amounts outstanding under its commercial paper program, general company purposes, and the redemption of all $682.7 million outstanding aggregate principal amount of its 7.034% 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.

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.

Redemption of Junior Subordinated Notes B

On March 5, 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. The redemption of the 7.034% Junior Subordinated Notes B and the issuance of the 5.375% Junior Subordinated Notes F will result in annual interest savings to EPO of approximately $11.3 million.

For additional information regarding our debt agreements, see Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

Issuance of Common Units

The following table summarizes the issuance of common units in connection with our distribution reinvestment plan (“DRIP”) and employee unit purchase plan (“EUPP”) for the three months ended March 31, 2018 (dollars in millions, number of units issued as shown):

		Number of Common Units Issued				Net Cash Proceeds Received
Common units issued in connection with DRIP and EUPP			6,642,286			$	177.0

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DRIP and EUPP

We have a registration statement on file with the SEC in connection with our 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 new common units. After taking into account the number of common units issued under the DRIP through March 31, 2018, we have the capacity to issue an additional 74,207,487 common units under this plan.

Privately held affiliates of EPCO purchased $100 million of our common units through the DRIP in connection with the distribution paid on February 7, 2018.

In addition to the DRIP, we have registration statements on file with the SEC in connection with our EUPP. After taking into account the number of common units issued under the EUPP through March 31, 2018, we have the capacity to issue an additional 5,628,178 common units under this plan.

ATM Program

We have a registration statement on file 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 at-the-market (“ATM”) program. No sales were made under this program during the first quarter of 2018. After taking into account the aggregate sales price of common units sold under the ATM program in periods prior to the first quarter of 2018, we have the capacity to issue additional common units under the ATM program up to an aggregate sales price of $2.54 billion.

Use of Proceeds

The net cash proceeds we received from the issuance of common units during the three months ended March 31, 2018 were used to temporarily reduce amounts outstanding under EPO’s commercial paper program and for general company purposes.

For additional information regarding our issuance of common units and related registration statements, see Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

Restricted Cash

Restricted cash represents amounts held in segregated bank accounts by our clearing brokers as margin in support of our commodity derivative instruments portfolio and related physical purchases and sales of natural gas, NGLs, crude oil and refined products. At March 31, 2018 and December 31, 2017, our restricted cash amounts were $113.5 million and $65.2 million, respectively.

Additional cash may be restricted to maintain our commodity derivative instruments portfolio as prices fluctuate or margin requirements change. For information regarding our derivative instruments and hedging activities, see Note 14 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report. In addition, see Item 3, Quantitative and Qualitative Disclosures about Market Risk, within this Part I, Item 2.

Credit Ratings

As of May 1, 2018, the investment-grade credit ratings of EPO’s long-term senior unsecured debt securities were BBB+ from Standard and Poor’s, Baa1 from Moody’s and BBB+ from Fitch Ratings. In addition, the credit ratings of EPO’s short-term senior unsecured debt securities were A-2 from Standard and Poor’s, P-2 from Moody’s and F-2 from Fitch Ratings.

EPO’s credit ratings reflect only the view of a rating agency and should not be interpreted as a recommendation to buy, sell or hold any of our securities. A credit rating can be revised upward or downward or withdrawn at any time by a rating agency, if it determines that circumstances warrant such a change. A credit rating from one rating agency should be evaluated independently of credit ratings from other rating agencies.

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Cash Flows from Operating, Investing and Financing Activities

The following table summarizes our consolidated cash flows from operating, investing and financing activities for the periods indicated (dollars in millions). For additional information regarding our cash flow amounts, please refer to the Unaudited Condensed Statements of Consolidated Cash Flows included under Part I, Item 1 of this quarterly report.

	For the Three Months Ended March 31,
	2018		2017
Net cash flows provided by operating activities	$	1,233.6	$	875.6
Cash used in investing activities		1,119.1		444.0
Cash provided by (used in) financing activities		30.8		(742.1	)

Net cash flows provided by operating activities are largely dependent on earnings from our consolidated business activities. We operate 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. We may also incur credit and price risk to the extent customers do not fulfill their obligations to us in connection with our marketing of natural gas, NGLs, propylene, refined products and/or crude oil and long-term take-or-pay agreements. For a more complete discussion of these and other risk factors pertinent to our business, see “Risk Factors” under Part I, Item 1A of our 2017 Form 10-K.

Comparison of Three Months Ended March 31, 2018 with Three Months Ended March 31, 2017

The following information highlights significant quarter-to-quarter fluctuations in our consolidated cash flow amounts:

Operating activities. Net cash flows provided by operating activities for the first quarter of 2018 increased $358.0 million when compared to the first quarter of 2017. The increase in cash provided by operating activities was primarily due to:

a $255.3 million increase in cash resulting from higher partnership earnings in the first quarter of 2018 compared to the same period in 2017 (after adjusting our $140.5 million quarter-to-quarter increase in net income for changes in the non-cash items identified on our Unaudited Condensed Statements of Consolidated Cash Flows);

a $17.0 million quarter-to-quarter increase in cash distributions received on earnings from unconsolidated affiliates primarily due to our investments in crude oil pipeline joint ventures; and

an $85.7 million quarter-to-quarter increase in cash primarily due to the timing of cash receipts and payments related to operations.

For information regarding significant quarter-to-quarter changes in our consolidated net income and underlying segment results, see “Results of Operations” within this Part I, Item 2.

Investing activities. Cash used for investing activities in the first quarter of 2018 increased $675.1 million when compared to the same period in 2017 primarily due to:

a $516.1 million quarter-to-quarter increase in capital spending for consolidated property, plant and equipment (see “Capital Spending” within this Part I, Item 2 for additional information regarding our capital spending program);

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a $133.8 million quarter-to-quarter increase in cash used for business combinations, net of cash received. During the first quarter of 2018, net cash used for business combinations was $149.8 million, which was related to the acquisition of the remaining member interest of Delaware Processing. During the same period in 2017, a $16.0 million deposit was paid for the acquisition of Azure, which was completed in April 2017; and

a $24.2 million quarter-to-quarter increase in investments in unconsolidated affiliates.

Financing activities. Cash provided by financing activities for the first quarter of 2018 was $30.8 million compared to cash used in financing activities of $742.1 million for the first quarter of 2017. The $772.9 million quarter-to-quarter change in cash flow from financing activities was primarily due to:

a $2.02 billion net cash inflow attributable to the issuance of $2.7 billion in principal amount of senior and junior subordinated notes offset by the repayment of $682.7 million in principal amount of Junior Subordinated Notes B during the first quarter of 2018 compared to no such issuances or repayments during the first quarter of 2017. Net repayments under EPO’s commercial paper program increased $894.7 million quarter-to-quarter; partially offset by

a $271.8 million quarter-to-quarter decrease in net cash proceeds from the issuance of common units. We issued an aggregate 6,642,286 common units, which generated $177.0 million of net cash proceeds, in connection with our DRIP and EUPP during the first quarter of 2018. This compares to an aggregate 16,305,930 common units we issued in connection with our ATM, DRIP and EUPP during the first quarter of 2017, which collectively generated $448.8 million of net cash proceeds; and

a $49.5 million quarter-to-quarter increase in cash distributions paid to limited partners during the first quarter of 2018 when compared to the first quarter of 2017. The increase in cash distributions is due to increases in both the number of distribution-bearing common units outstanding and the quarterly cash distribution rates per unit.

Cash Distributions to Limited Partners

Our partnership agreement requires us to make quarterly distributions to our unitholders of all available cash, after any cash reserves established by Enterprise GP in its sole discretion. Cash reserves include those for the proper conduct of our business including, for example, those for capital expenditures, debt service, working capital, operating expenses, commitments and contingencies and other significant amounts. The retention of cash by the partnership allows us to reinvest in our growth and reduce our future reliance on the equity and debt capital markets.

We measure available cash by reference to “distributable cash flow,” which is a non-GAAP liquidity measure. Distributable cash flow is an important non-GAAP financial measure for our limited partners since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flows at a level that can sustain or support an increase in our quarterly cash distributions. Distributable cash flow is also a quantitative standard used by the investment community with respect to publicly traded partnerships because the value of a partnership unit is, in part, measured by its yield, which is based on the amount of cash distributions a partnership can pay to a unitholder. Our management compares the distributable cash flow we generate to the cash distributions we expect to pay our partners. Using this metric, management computes our distribution coverage ratio.

Based on the level of available cash, management proposes a quarterly cash distribution rate to the Board of Enterprise GP, which has sole authority in approving such matters. Unlike several other master limited partnerships, our general partner has a non-economic ownership interest in us and is not entitled to receive any cash distributions from us based on incentive distribution rights or other equity interests.

Our use of distributable cash flow for the limited purposes described above and in this report is not a substitute for net cash flows provided by operating activities, which is the most comparable GAAP measure. For a discussion of net cash flows provided by operating activities, see the previous section titled “Cash Flows from Operating, Investing and Financing Activities” within this Item 2.

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The following table summarizes our calculation of distributable cash flow for the periods indicated (dollars in millions):

	For the Three Months Ended March 31,
	2018			2017
Net income attributable to limited partners (1)	$	900.7		$	760.7
Adjustments to GAAP net income attributable to limited partners to derive non-GAAP distributable cash flow:
Add depreciation, amortization and accretion expenses		431.0			402.3
Add non-cash asset impairment and related charges		0.9			11.2
Subtract net gains attributable to asset sales		(0.5	)		(0.3	)
Add cash proceeds from asset sales		1.1			2.0
Subtract gain on step acquisition of unconsolidated affiliate		(37.0	)		--
Add changes in fair value of Liquidity Option Analysis		7.5			5.5
Add or subtract changes in fair market value of derivative instruments		136.9			(20.3	)
Add cash distributions received from unconsolidated affiliates (2)		122.4			102.5
Subtract equity in income of unconsolidated affiliates (2)		(115.7	)		(94.8	)
Subtract sustaining capital expenditures (3)		(66.3	)		(48.0	)
Add deferred income tax expense or subtract benefit, as applicable		(1.1	)		0.1
Other, net		10.7			7.7
Distributable cash flow	$	1,390.6		$	1,128.6

Total cash distributions paid to limited partners with respect to period	$	933.5		$	892.8

Cash distribution per unit declared by Enterprise GP with respect to period (4)	$	0.4275		$	0.4150

Total distributable cash flow retained by partnership with respect to period (5)	$	457.1		$	235.8

Distribution coverage ratio (6)		1.5x			1.3x

(1) For a discussion of significant changes in our comparative income statement amounts underlying net income attributable to limited partners, along with the primary drivers of such changes, see “Consolidated Income Statements Highlights” within this Part I, Item 2. (2) Reflects both distributions received on earnings from unconsolidated affiliates and those attributable to a return of capital from unconsolidated affiliates. For information regarding our unconsolidated affiliates, see Note 5 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report. (3) Sustaining capital expenditures include cash payments and accruals applicable to the period. (4) See Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report for additional information regarding our quarterly cash distributions declared with respect to the periods presented. (5) At the sole discretion of Enterprise GP, cash retained by the partnership with respect to each of these periods was primarily reinvested in our growth capital spending program, which reduced our reliance on the equity and debt capital markets to fund such major expenditures. (6) Distribution coverage ratio is determined by dividing distributable cash flow by total cash distributions paid to limited partners and in connection with distribution equivalent rights with respect to the period.

The following table presents a reconciliation of net cash flows provided by operating activities to non-GAAP distributable cash flow for the periods indicated (dollars in millions):

	For the Three Months Ended March 31,
	2018			2017
Net cash flows provided by operating activities	$	1,233.6		$	875.6
Adjustments to reconcile net cash flows provided by operating activities to distributable cash flow:
Subtract sustaining capital expenditures		(66.3	)		(48.0	)
Add cash proceeds from asset sales		1.1			2.0
Net effect of changes in operating accounts		203.1			288.8
Other, net		19.1			10.2
Distributable cash flow	$	1,390.6		$	1,128.6

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Capital Spending

We have approximately $5.3 billion of growth capital projects scheduled to be completed by the end of 2019. These projects include:

our ninth NGL fractionator in Mont Belvieu, Texas (second quarter of 2018);

the completion of joint venture-owned dock infrastructure in Corpus Christi designed to accommodate crude oil volumes (third quarter of 2018);

the Shin Oak NGL pipeline (second quarter of 2019);

expansions of our Front Range and Texas Express NGL pipelines (second and fourth quarters of 2019, respectively);

our isobutane dehydrogenation (“iBDH”) facility (fourth quarter of 2019); and,

the ethylene export terminal (fourth quarter of 2019).

Our PDH facility recently completed its commissioning phase and was placed into service in April 2018. In addition, the first processing train at our Orla natural gas processing facility (“Orla I”) entered service in May 2018.

Based on information currently available, we expect our total growth capital spending for 2018 to approximate $3.2 billion to $3.4 billion, which includes the approximate $150 million we spent in March 2018 to acquire the remaining equity interest in Delaware Processing. Further, we expect our sustaining capital expenditures for 2018 to approximate $315 million, of which $73 million was spent in the first quarter of 2018.

Our forecast of capital spending for 2018 is based on our announced strategic operating and growth plans (through the filing date of this quarterly report), which are dependent upon our ability to generate the required funds from either operating cash flows or other means, including borrowings under debt agreements, the issuance of additional equity and debt securities, and potential divestitures. We may revise our forecast of capital spending due to factors beyond our control, such as adverse economic conditions, weather related issues and changes in supplier prices. Furthermore, our forecast of capital spending may change as a result of decisions made by management at a later date, which may include unforeseen acquisition opportunities.

Our success in raising capital, including the formation of joint ventures to share costs and risks, continues to be a significant factor in determining how much capital we can invest. We believe our access to capital resources is sufficient to meet the demands of our current and future growth needs and, although we expect to make the forecast capital expenditures noted above, we may adjust the timing and amounts of projected expenditures in response to changes in capital market conditions.

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The following table summarizes the primary elements of our capital spending for the periods indicated (dollars in millions):

	For the Three Months Ended March 31,
	2018		2017
Capital spending for property, plant and equipment: (1)
Growth capital projects (2)	$	873.3	$	379.6
Sustaining capital projects (3)		73.2		50.8
Total	$	946.5	$	430.4

Cash used for business combinations, net (4)	$	149.8	$	16.0

Investments in unconsolidated affiliates	$	37.9	$	13.7

(1) Growth and sustaining capital amounts presented in the table above are presented on a cash basis. (2) Growth capital projects either (a) result in new sources of cash flow due to enhancements of or additions to existing assets (e.g., additional revenue streams, cost savings resulting from debottlenecking of a facility, etc.) or (b) expand our asset base through construction of new facilities that will generate additional revenue streams and cash flows. (3) Sustaining capital expenditures are capital expenditures (as defined by GAAP) resulting from improvements to existing assets. Such expenditures serve to maintain existing operations but do not generate additional revenues or result in significant cost savings. (4) Amount presented for the first quarter of 2018 represents the acquisition of the remaining 50% ownership interest in our Delaware Processing joint venture, which closed on March 29, 2018.

Fluctuations in our spending for growth capital projects and investments in unconsolidated affiliates are explained in large part by increases or decreases in spending on major expansion projects. Our most significant growth capital expenditures for the three months ended March 31, 2018 involved projects to support crude oil, natural gas and NGL production from the Permian Basin and export activities at our Gulf Coast terminal. Fluctuations in spending for sustaining capital projects are explained in large part by the timing and cost of pipeline integrity and similar projects.

Comparison of Three Months Ended March 31, 2018 with Three Months Ended March 31, 2017

Total capital spending increased $674.1 million quarter-to-quarter primarily due to increased cash used for growth capital projects, which accounted for a $493.7 million increase, and higher cash used for business combinations, which accounted for an additional $133.8 million increase. Of the quarter-to-quarter increase in capital spending, the significant elements are as follows:

Growth capital spending for projects to support Permian Basin production increased $252.5 million quarter-to-quarter. We are in various stages of completion on multiple projects to support crude oil, natural gas and NGL production in the Permian Basin, including our Orla natural gas processing facility and related pipelines and the Shin Oak NGL Pipeline.

Growth capital spending for projects to expand and support export activities at EHT increased $154.3 million quarter-to-quarter.

Growth capital spending at our Mont Belvieu complex increased $68.0 million quarter-to-quarter primarily due to increased capital spending for our iBDH plant, which accounted for a $67.2 million increase, and our ninth NGL fractionator, which accounted for an additional $34.0 million increase, partially offset by lower growth capital spending at our PDH facility, which accounted for a $27.7 million decrease. The ninth NGL fractionator, which resumed construction in March 2017 in anticipation of increased NGL production from the Permian Basin, is expected to be completed during the second quarter of 2018.

Net cash used for business combinations increased $133.8 million quarter-to-quarter primarily due to our acquisition of the remaining 50% member interest in Delaware Processing for $149.8 million in March 2018.

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Pipeline Integrity Program

Our pipelines operate under safety regulations administered by the U.S. Department of Transportation (“DOT”) that require pipeline integrity management programs for hazardous liquid and natural gas pipelines. In general, these regulations require companies to assess the condition of their pipelines in certain high consequence areas (as defined by the regulation) and to perform any necessary repairs.

The following table summarizes our pipeline integrity costs, including those attributable to DOT regulations, for the periods presented (dollars in millions):

	For the Three Months Ended March 31,
	2018		2017
Recognized in operating costs and expenses	$	17.0	$	15.3
Reflected as a component of sustaining capital expenditures		7.7		8.2
Total	$	24.7	$	23.5

Critical Accounting Policies and Estimates

A discussion of our critical accounting policies and estimates is included in our 2017 Form 10-K. The following types of estimates, in our opinion, are subjective in nature, require the exercise of professional judgment and involve complex analysis:

depreciation methods and estimated useful lives of property, plant and equipment;

measuring recoverability of long-lived assets and equity method investments;

amortization methods and estimated useful lives of qualifying intangible assets;

methods we employ to measure the fair value of goodwill; and

revenue recognition policies and the use of estimates for revenue and expenses.

When used to prepare our Unaudited Condensed Consolidated Financial Statements, the foregoing types of estimates are based on our current knowledge and understanding of the underlying facts and circumstances. Such estimates may be revised as a result of changes in the underlying facts and circumstances. Subsequent changes in these estimates may have a significant impact on our consolidated financial position, results of operations and cash flows.

Other Items

Contractual Obligations

Our consolidated principal debt obligations at March 31, 2018 were approximately $25.62 billion compared to $24.78 billion at December 31, 2017. For information regarding the scheduled maturities of such debt, see “Liquidity and Capital Resources – Consolidated Debt” within this Part I, Item 2. See Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements under Part I, Item 1 of this quarterly report for additional information regarding our consolidated debt obligations.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements that have or are reasonably expected to have a material current or future effect on our financial position, results of operations and cash flows.

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Recent Accounting Developments

For information regarding recent developments involving changes in our accounting policies for revenue recognition, the presentation of restricted cash on the cash flow statement, and our work involving the new lease accounting standard, see Note 2 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

Related Party Transactions

For information regarding our related party transactions, see Note 15 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

General

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 and other instruments with similar characteristics. Substantially all of our derivatives are used for non-trading activities.

We assess the risk associated with each of our derivative instrument portfolios using a sensitivity analysis model. This approach measures the change in fair value of the derivative instrument portfolio based on a hypothetical 10% change in the underlying interest rates or quoted market prices on a particular day. In addition to these variables, the fair value of each portfolio is influenced by changes in the notional amounts of the instruments outstanding and the discount rates used to determine the present values. The sensitivity analysis approach does not reflect the impact that the same hypothetical price movement would have on the hedged exposures to which they relate. Therefore, the impact on the fair value of a derivative instrument resulting from a change in interest rates or quoted market prices (as applicable) would normally be offset by a corresponding gain or loss on the hedged debt instrument, inventory value or forecasted transaction assuming:

§	the derivative instrument functions effectively as a hedge of the underlying risk;

§	the derivative instrument is not closed out in advance of its expected term; and

§	the hedged forecasted transaction occurs within the expected time period.

We routinely review the effectiveness of our derivative instrument portfolios in light of current market conditions. Accordingly, the nature and volume of our derivative instruments may change depending on the specific exposure being managed.

See Note 14 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report for additional information regarding our derivative instruments and hedging activities.

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Commodity Hedging Activities

The prices of natural gas, NGLs, crude oil, petrochemicals and refined products are subject to fluctuations in response to changes in supply and demand, market conditions and a variety of additional factors that are beyond our control. In order to manage such price risks, we enter into commodity derivative instruments such as physical forward contracts, futures contracts, fixed-for-float swaps, basis swaps and option contracts. The following table summarizes our portfolio of commodity derivative instruments outstanding at March 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)	2.1	n/a	Cash flow hedge
Octane enhancement:
Forecasted purchase of NGLs (MMBbls)	0.5	n/a	Cash flow hedge
Forecasted sales of octane enhancement products (MMBbls)	0.5	n/a	Cash flow hedge
Natural gas marketing:
Natural gas storage inventory management activities (Bcf)	1.7	n/a	Fair value hedge
NGL marketing:
Forecasted purchases of NGLs and related hydrocarbon products (MMBbls)	48.6	n/a	Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products (MMBbls)	60.2	n/a	Cash flow hedge
NGLs inventory management activities (MMBbls)	0.4	n/a	Fair value hedge
Refined products marketing:
Forecasted purchase of refined products (MMBbls)	0.5	n/a	Cash flow hedge
Forecasted sales of refined products (MMBbls)	1.1	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)	4.0	6.5	Cash flow hedge
Forecasted sales of crude oil (MMBbls)	8.4	6.5	Cash flow hedge
Propylene marketing:
Forecasted purchases of NGLs for propylene marketing activities (MMBbls)	0.8	n/a	Cash flow hedge
Forecasted sales of NGLs for propylene marketing activities (MMBbls)	0.8	n/a	Cash flow hedge
Derivatives not designated as hedging instruments:
Natural gas risk management activities (Bcf) (3,4)	92.0	5.6	Mark-to-market
NGL risk management activities (MMBbls) (4)	0.2	n/a	Mark-to-market
Refined products risk management activities (MMBbls) (4)	2.3	n/a	Mark-to-market
Crude oil risk management activities (MMBbls) (4)	91.3	23.8	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, December 2018 and December 2020, respectively. (3) Current and long-term volumes include 42.4 Bcf and 3.0 Bcf, respectively, of physical derivative instruments that are predominantly priced at a market-based index plus a premium or minus a discount related to location differences. (4) Reflects the use of derivative instruments to manage risks associated with transportation, processing and storage assets.

At March 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.

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§	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 shows the effect of hypothetical price movements (a sensitivity analysis) on the estimated economic value of our natural gas marketing portfolio at the dates indicated (dollars in millions):

		Portfolio Fair Value at
Scenario	Resulting Classification	December 31, 2017				March 31, 2018				April 16, 2018
Fair value assuming no change in underlying commodity prices	Asset (Liability)		$	(13.9	)		$	(11.3	)		$	(12.7	)
Fair value assuming 10% increase in underlying commodity prices	Asset (Liability)			(16.9	)			(12.5	)			(14.1	)
Fair value assuming 10% decrease in underlying commodity prices	Asset (Liability)			(10.8	)			(10.1	)			(11.3	)

The following table shows the effect of hypothetical price movements (a sensitivity analysis) on the estimated economic value of our NGL marketing, refined products marketing and octane enhancement portfolios at the dates indicated (dollars in millions):

		Portfolio Fair Value at
Scenario	Resulting Classification	December 31, 2017				March 31, 2018				April 16, 2018
Fair value assuming no change in underlying commodity prices	Asset (Liability)		$	(76.4	)		$	(8.1	)		$	(15.5	)
Fair value assuming 10% increase in underlying commodity prices	Asset (Liability)			(126.1	)			(18.3	)			(25.6	)
Fair value assuming 10% decrease in underlying commodity prices	Asset (Liability)			(26.8	)			2.1				(5.5	)

The following table shows the effect of hypothetical price movements (a sensitivity analysis) on the estimated economic value of our crude oil marketing portfolio at the dates indicated (dollars in millions):

		Portfolio Fair Value at
Scenario	Resulting Classification	December 31, 2017				March 31, 2018				April 16, 2018
Fair value assuming no change in underlying commodity prices	Asset (Liability)		$	(65.5	)		$	(193.4	)		$	(245.6	)
Fair value assuming 10% increase in underlying commodity prices	Asset (Liability)			(109.4	)			(258.2	)			(318.0	)
Fair value assuming 10% decrease in underlying commodity prices	Asset (Liability)			(21.6	)			(128.7	)			(173.3	)

As noted in our discussion of results for the Crude Oil Pipelines & Services segment (Midland-to-ECHO Pipeline and related commercial activities), we entered into hedges of the crude oil commodity price differentials between the Midland and Houston Texas areas. The mark-to-market derivative liability for these instruments increased from $42.4 million at December 31, 2017 to $156.4 million at March 31, 2018, which resulted in a $114.0 million decrease in the fair value of the crude oil marketing portfolio for the first quarter of 2018. The mark-to-market derivative liability for these instruments increased to $481.3 million at May 3, 2018 primarily due to a further widening of the crude oil commodity price differentials (basis spreads) between the Midland and Houston markets since March 31, 2018. Excluding those hedges that settle through June 30, 2018 and assuming no further change in the basis spreads between May 3, 2018 and June 30, 2018, the impact to earnings would be an approximate $309.6 million non-cash, mark-to-market loss recognized in the second quarter of 2018. These losses are temporary such that when the hedged transactions occur in the future, the unrealized mark-to-market losses will reverse and be realized against the expected gains on the physical transactions.

Additional cash may be posted to maintain our commodity derivative instruments portfolio as prices fluctuate or margin requirements change. Our restricted cash balance increased from $113.5 million at March 31, 2018 to $253.2 million at May 3, 2018. In addition, we have posted $221.7 million of cash and $52.9 million under stand-by letters of credit in connection with margin requirements on the Chicago Mercantile Exchange through May 3, 2018. The increase in restricted cash and other cash postings since March 31, 2018 is primarily due to changes in the fair value of our crude oil marketing transportation hedges.

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Interest Rate Hedging Activities

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

With respect to the tabular data below, each portfolio’s estimated economic value at a given date is based on a number of factors, including the number and types of derivatives outstanding at that date, the notional value of the swaps and associated interest rates.

Interest rate swaps exchange the stated interest rate paid on a notional amount of existing debt for the fixed or floating interest rate stipulated in the derivative instrument. The following table summarizes our portfolio of interest rate swaps at March 31, 2018 (dollars in millions):

Hedged Transaction	Number and Type of Derivatives Outstanding		Notional Amount			Period of Hedge	Rate Swap	Accounting Treatment
Senior Notes OO	10 fixed-to-floating swaps		$	750.0		5/2015 to 5/2018	1.65% to 2.27%	Fair value hedge

The following table shows the effect of hypothetical price movements (a sensitivity analysis) on the estimated economic value of our interest rate swap portfolio at the dates indicated (dollars in millions):

		Interest Rate Swap Portfolio Fair Value at
Scenario	Resulting Classification	December 31, 2017				March 31, 2018				April 16, 2018
Fair value assuming no change in underlying interest rates	Asset (Liability)		$	(1.5	)		$	(1.6	)		$	(1.6	)
Fair value assuming 10% increase in underlying interest rates	Asset (Liability)			(1.8	)			(1.6	)			(1.6	)
Fair value assuming 10% decrease in underlying interest rates	Asset (Liability)			(1.2	)			(1.6	)			(1.6	)

The following table summarizes our portfolio of 30-year forward starting swaps outstanding at March 31, 2018. Forward starting swaps hedge the expected underlying benchmark interest rates related to future issuances of debt.

Hedged Transaction	Number and Type of Derivatives Outstanding		Notional Amount			Expected Settlement Date	Average Rate Locked	Accounting Treatment
Future long-term debt offering	2 forward starting swaps		$	175.0		2/2019	2.56%	Cash flow hedge

The following table shows the effect of hypothetical price movements (a sensitivity analysis) on the estimated economic value of our forward starting swap portfolio at the dates indicated (dollars in millions):

		Forward Starting Swap Portfolio Fair Value at
Scenario	Resulting Classification	December 31, 2017				March 31, 2018				April 16, 2018
Fair value assuming no change in underlying interest rates	Asset (Liability)		$	(0.1	)		$	9.5			$	11.8
Fair value assuming 10% increase in underlying interest rates	Asset (Liability)			13.8				18.7				21.0
Fair value assuming 10% decrease in underlying interest rates	Asset (Liability)			(15.1	)			(0.3	)			1.9

As a result of market conditions in January 2018, we elected to terminate $100 million notional amount of the forward starting swaps that were outstanding at December 31, 2017, which resulted in cash proceeds totaling $1.5 million for the first quarter of 2018.

We sold swaptions related to our interest rate hedging activities during the first quarter of 2018, which resulted in the recognition of $7.2 million of cash gains that are reflected as a reduction in interest expense for the quarter. These swaptions expired in March 2018. In April 2018, we sold additional swaptions related to our interest rate hedging activities for which we received $11.8 million in premiums. The April 2018 swaptions expire in June 2018.

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Item 4.

Controls and Procedures.

Disclosure Controls and Procedures

As of the end of the period covered by this quarterly report, our management carried out an evaluation, with the participation of (i) A. James Teague, our general partner’s Chief Executive Officer, (ii) W. Randall Fowler, our general partner’s President, and (iii) Bryan F. Bulawa, our general partner’s Chief Financial Officer, of the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 of the Securities Exchange Act of 1934. Mr. Teague is our principal executive officer and Messrs. Fowler and Bulawa represent our principal financial officers. Based on this evaluation, as of the end of the period covered by this quarterly report, Messrs. Teague, Fowler and Bulawa concluded:

(i)

that our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our principal executive and financial officers, as appropriate to allow for timely decisions regarding required disclosures; and

(ii)

that our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

There were no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) during the first quarter of 2018, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

Section 302 and 906 Certifications

The required certifications of Messrs. Teague, Fowler and Bulawa under Sections 302 and 906 of the Sarbanes-Oxley Act of 2002 are included as exhibits to this quarterly report (see Exhibits 31 and 32 under Part II, Item 6 of this quarterly report).

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings.

As part of our normal business activities, we may be named as defendants in litigation and 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 indemnify us against liabilities arising from future legal proceedings. We will vigorously defend the partnership in litigation matters.

For additional information regarding our litigation matters, see “Litigation” under Note 16 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report, which subsection is incorporated by reference into this Part II, Item 1.

Item 1A. Risk Factors.

An investment in our securities involves certain risks. Security holders and potential investors in our securities should carefully consider the risks described under “Risk Factors” set forth in Part I, Item 1A of our 2017 Form 10-K, in addition to other information in such annual report. The risk factors set forth in our 2017 Form 10-K are important factors that could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us or on our behalf.

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Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds.

The following table summarizes our repurchase activity during the three months ended March 31, 2018 in connection with the vesting of phantom unit awards:

Period	Total Number of Units Purchased		Average Price Paid per Unit		Total Number of Units Purchased as Part of Publicly Announced Plans		Maximum Number of Units That May Yet Be Purchased Under the Plans
January 2018 (1)		2,559	$	27.73		--		--
February 2018 (2)		945,409	$	26.40		--		--
March 2018 (3)		1,810	$	25.68		--		--

(1) Of the 8,000 phantom unit awards that vested in January 2018 and converted to common units, 2,559 units were sold back to us by employees to cover related withholding tax requirements. (2) Of the 3,156,811 phantom unit awards that vested in February 2018 and converted to common units, 945,409 units were sold back to us by employees to cover related withholding tax requirements. (3) Of the 6,050 phantom unit awards that vested in March 2018 and converted to common units, 1,810 units were sold back to us by employees to cover related withholding tax requirements.

Item 3. Defaults Upon Senior Securities.

None.

Item 4.

Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

Disclosure Under Section 13(r) of the Securities Exchange Act of 1934

Under Section 13(r) of the Securities Exchange Act of 1934, as amended by the Iran Threat Reduction and Syria Human Rights Act of 2012, issuers are required to include certain disclosures in their periodic reports if they or any of their “affiliates” (as defined in Rule 12b-2 thereunder) have knowingly engaged in certain specified activities relating to Iran. Disclosure is required even where the activities are conducted outside the U.S. by non-U.S. affiliates in compliance with applicable law, and even if the activities are not covered or prohibited by U.S. law.

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 or “Oiltanking GP”), and the incentive distribution rights held by Oiltanking GP from Oiltanking Holdings Americas, Inc. 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. Collectively, the first and second steps of the acquisition of Oiltanking and Oiltanking GP are referred to as the “Oiltanking acquisition.”

Marquard & Bahls AG (“M&B”), a German corporation and the former parent company of Oiltanking, is entitled to designate a nominee for election to the Board (the “M&B Designee”) as long as M&B and its affiliates beneficially own at least 27,403,676 of the common units we issued to M&B and its affiliates in connection with step one of the Oiltanking acquisition. In the event that the M&B Designee becomes unable or unwilling to, or for another reason ceases to, serve as a member of the Board while M&B is entitled to maintain the M&B Designee, M&B may designate another person reasonably acceptable to the Board as a replacement. The initial M&B Designee, Dr. F. Christian Flach, resigned from the Board in November 2017. No replacement for Dr. Flach has been nominated by M&B as of the filing date of this quarterly report.

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M&B owns and controls Oiltanking GmbH, which in turn owns a joint venture interest in the Exir Chemical Terminal (“ECT”) in Iran via its wholly owned affiliates Oiltanking ME Holding GmbH (formerly named Oiltanking Iran GmbH) and OMEA GmbH. This interest results from an investment dating back to 2002. Oiltanking GmbH currently has the contractual right to vote for the appointment of two members of ECT’s three-member board. Oiltanking GmbH provides no goods, services, technology, information or support to ECT and plays no role in the management or day-to-day operations of ECT.

ECT stores chemicals and hydrocarbons, including naphtha, linear alkyl benzene and n-hexane, for distribution in Iran and for export to Asia and Europe. To our knowledge, ECT’s activities are in compliance with applicable U.S., European Union or United Nations sanctions laws. ECT pays routine and standard charges (i) to the Petrochemical Special Economic Zone Organization (“Petzone”) for the use of pipelines and (ii) to the National Petrochemical Company (“NPC”), which operates the berth. Petzone is a subsidiary of NPC, which is owned and controlled by the Government of Iran. As Oiltanking GmbH has no direct involvement in the day-to-day operations of ECT, we have no information regarding ECT’s intent to continue or not continue making the payments described above.

Oiltanking GmbH maintains an internal compliance program to ensure compliance with all applicable sanctions regimes, including sanctions laws maintained by the U.S., European Union and United Nations. Although the existence of the routine payments described above may be reportable under Section 13(r), Oiltanking GmbH has informed us that neither it, nor any of its subsidiaries or affiliates, has engaged in any conduct that would be sanctionable under any of these legal regimes.

Item 6. Exhibits.

Exhibit Number	Exhibit*
2.1	Merger Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form 8-K filed December 15, 2003).
2.2	Amendment No. 1 to Merger Agreement, dated as of August 31, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form 8-K filed September 7, 2004).
2.3	Parent Company Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.2 to Form 8-K filed December 15, 2003).
2.4	Amendment No. 1 to Parent Company Agreement, dated as of April 19, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.1 to Form 8-K filed April 21, 2004).
2.5	Purchase and Sale Agreement (Gas Plants), dated as of December 15, 2003, by and between El Paso Corporation, El Paso Field Services Management, Inc., El Paso Transmission, L.L.C., El Paso Field Services Holding Company and Enterprise Products Operating L.P. (incorporated by reference to Exhibit 2.4 to Form 8-K filed December 15, 2003).
2.6	Agreement and Plan of Merger, dated as of June 28, 2009, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Sub B LLC, TEPPCO Partners, L.P. and Texas Eastern Products Pipeline Company, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed June 29, 2009).
2.7	Agreement and Plan of Merger, dated as of June 28, 2009, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Sub A LLC, TEPPCO Partners, L.P. and Texas Eastern Products Pipeline Company, LLC (incorporated by reference to Exhibit 2.2 to Form 8-K filed June 29, 2009).

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2.8	Agreement and Plan of Merger, dated as of September 3, 2010, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise ETE LLC, Enterprise GP Holdings L.P. and EPE Holdings, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed September 7, 2010).
2.9	Agreement and Plan of Merger, dated as of September 3, 2010, by and among Enterprise Products GP, LLC, Enterprise GP Holdings L.P. and EPE Holdings, LLC (incorporated by reference to Exhibit 2.2 to Form 8-K filed September 7, 2010).
2.10	Contribution Agreement, dated as of September 30, 2010, by and between Enterprise Products Company and Enterprise Products Partners L.P. (incorporated by reference to Exhibit 2.1 to Form 8-K filed October 1, 2010).
2.11	Agreement and Plan of Merger, dated as of April 28, 2011, by and among Enterprise Products Partners L.P., Enterprise Products Holdings LLC, EPD MergerCo LLC, Duncan Energy Partners L.P. and DEP Holdings, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed April 29, 2011).
2.12	Contribution and Purchase Agreement, dated as of October 1, 2014, by and among Enterprise Products Partners L.P., Oiltanking Holding Americas, Inc. and OTB Holdco, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed October 1, 2014).
2.13	Agreement and Plan of Merger, dated as of November 11, 2014, by and among Enterprise Products Partners L.P., Enterprise Products Holdings LLC, EPOT MergerCo LLC, Oiltanking Partners, L.P. and OTLP GP, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed November 12, 2014).
3.1	Certificate of Limited Partnership of Enterprise Products Partners L.P. (incorporated by reference to Exhibit 3.6 to Form 10-Q filed November 9, 2007).
3.2	Certificate of Amendment to Certificate of Limited Partnership of Enterprise Products Partners L.P., filed on November 22, 2010 with the Delaware Secretary of State (incorporated by reference to Exhibit 3.6 to Form 8-K filed November 23, 2010).
3.3	Sixth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated November 22, 2010 (incorporated by reference to Exhibit 3.2 to Form 8-K filed November 23, 2010).
3.4	Amendment No. 1 to Sixth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated effective as of August 11, 2011 (incorporated by reference to Exhibit 3.1 to Form 8-K filed August 16, 2011).
3.5	Amendment No. 2 to Sixth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated effective as of August 21, 2014 (incorporated by reference to Exhibit 3.1 to Form 8-K filed August 26, 2014).
3.6	Amendment No. 3 to the Sixth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated as of November 28, 2017 (incorporated by reference to Exhibit 3.1 to Form 8-K filed December 1, 2017).
3.7	Certificate of Formation of Enterprise Products Holdings LLC (formerly named EPE Holdings, LLC) (incorporated by reference to Exhibit 3.3 to Form S-1/A Registration Statement, Reg. No. 333-124320, filed by Enterprise GP Holdings L.P. on July 22, 2005).
3.8	Certificate of Amendment to Certificate of Formation of Enterprise Products Holdings LLC (formerly named EPE Holdings, LLC), filed on November 22, 2010 with the Delaware Secretary of State (incorporated by reference to Exhibit 3.5 to Form 8-K filed November 23, 2010).
3.9	Fifth Amended and Restated Limited Liability Company Agreement of Enterprise Products Holdings LLC dated effective as of September 7, 2011 (incorporated by reference to Exhibit 3.1 to Form 8-K filed September 8, 2011).
3.10	Amendment No. 1 to Fifth Amended and Restated Limited Liability Company Agreement of Enterprise Products Holdings LLC, dated effective as of April 26, 2017 (incorporated by reference to Exhibit 3.1 to Form 8-K filed May 2, 2017).
3.11	Company Agreement of Enterprise Products Operating LLC dated June 30, 2007 (incorporated by reference to Exhibit 3.3 to Form 10-Q filed August 8, 2007).
3.12	Certificate of Incorporation of Enterprise Products OLPGP, Inc., dated December 3, 2003 (incorporated by reference to Exhibit 3.5 to Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).

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3.13	Bylaws of Enterprise Products OLPGP, Inc., dated December 8, 2003 (incorporated by reference to Exhibit 3.6 to Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).
4.1	Form of Common Unit certificate (incorporated by reference to Exhibit A to Exhibit 3.1 to Form 8-K filed August 16, 2011).
4.2	Indenture, dated as of March 15, 2000, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and First Union National Bank, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed March 14, 2000).
4.3	Second Supplemental Indenture, dated as of February 14, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 10-K filed March 31, 2003).
4.4	Third Supplemental Indenture, dated as of June 30, 2007, among Enterprise Products Operating L.P., as Original Issuer, Enterprise Products Partners L.P., as Parent Guarantor, Enterprise Products Operating LLC, as New Issuer, and U.S. Bank National Association, as successor Trustee (incorporated by reference to Exhibit 4.55 to Form 10-Q filed August 8, 2007).
4.5	Indenture, dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed October 6, 2004).
4.6	Fourth Supplemental Indenture, dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.5 to Form 8-K filed October 6, 2004).
4.7	Sixth Supplemental Indenture, dated as of March 2, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed March 3, 2005).
4.8	Eighth Supplemental Indenture, dated as of July 18, 2006, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed July 19, 2006).
4.9	Ninth Supplemental Indenture, dated as of May 24, 2007, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed May 24, 2007).
4.10	Tenth Supplemental Indenture, dated as of June 30, 2007, among Enterprise Products Operating L.P., as Original Issuer, Enterprise Products Partners L.P., as Parent Guarantor, Enterprise Products Operating LLC, as New Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.54 to Form 10-Q filed August 8, 2007).
4.11	Eleventh Supplemental Indenture, dated as of September 4, 2007, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed September 5, 2007).
4.12	Thirteenth Supplemental Indenture, dated as of April 3, 2008, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed April 3, 2008).
4.13	Sixteenth Supplemental Indenture, dated as of October 5, 2009, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed October 5, 2009).
4.14	Seventeenth Supplemental Indenture, dated as of October 27, 2009, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed October 28, 2009).

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4.15	Eighteenth Supplemental Indenture, dated as of October 27, 2009, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed October 28, 2009).
4.16	Nineteenth Supplemental Indenture, dated as of May 20, 2010, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed May 20, 2010).
4.17	Twentieth Supplemental Indenture, dated as of January 13, 2011, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed January 13, 2011).
4.18	Twenty-First Supplemental Indenture, dated as of August 24, 2011, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed August 24, 2011).
4.19	Twenty-Second Supplemental Indenture, dated as of February 15, 2012, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.25 to Form 10-Q filed May 10, 2012).
4.20	Twenty-Third Supplemental Indenture, dated as of August 13, 2012, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed August 13, 2012).
4.21	Twenty-Fourth Supplemental Indenture, dated as of March 18, 2013, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed March 18, 2013).
4.22	Twenty-Fifth Supplemental Indenture, dated as of February 12, 2014, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed February 12, 2014).
4.23	Twenty-Sixth Supplemental Indenture, dated as of October 14, 2014, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed October 14, 2014).
4.24	Twenty-Seventh Supplemental Indenture, dated as of May 7, 2015, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed May 7, 2015).
4.25	Twenty-Eighth Supplemental Indenture, dated as of April 13, 2016, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed April 13, 2016).
4.26	Twenty-Ninth Supplemental Indenture, dated as of August 16, 2017, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed August 16, 2017).
4.27	Thirtieth Supplemental Indenture, dated as of February 15, 2018, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed February 15, 2018).
4.28	Thirty-First Supplemental Indenture, dated as of February 15, 2018, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed February 15, 2018).

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4.29	Form of Global Note representing $499.2 million principal amount of 6.875% Series B Senior Notes due 2033 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 10-K filed March 31, 2003).
4.30	Form of Global Note representing $350.0 million principal amount of 6.65% Series B Senior Notes due 2034 with attached Guarantee (incorporated by reference to Exhibit 4.19 to Form S-3 Registration Statement, Reg. No. 333-123150, filed March 4, 2005).
4.31	Form of Global Note representing $250.0 million principal amount of 5.75% Series B Senior Notes due 2035 with attached Guarantee (incorporated by reference to Exhibit 4.32 to Form 10-Q filed November 4, 2005).
4.32	Form of Global Note representing $300.0 million principal amount of Junior Subordinated Notes due 2066 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.2 to Form 8-K filed July 19, 2006).
4.33	Form of Global Note representing $800.0 million principal amount of 6.30% Senior Notes due 2017 with attached Guarantee (incorporated by reference to Exhibit 4.38 to Form 10-Q filed November 9, 2007).
4.34	Form of Global Note representing $700.0 million principal amount of 6.50% Senior Notes due 2019 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.4 to Form 8-K filed April 3, 2008).
4.35	Form of Global Note representing $500.0 million principal amount of 5.25% Senior Notes due 2020 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed October 5, 2009).
4.36	Form of Global Note representing $600.0 million principal amount of 6.125% Senior Notes due 2039 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed October 5, 2009).
4.37	Form of Global Note representing $349.7 million principal amount of 6.65% Senior Notes due 2018 with attached Guarantee (incorporated by reference to Exhibit D to Exhibit 4.1 to Form 8-K filed October 28, 2009).
4.38	Form of Global Note representing $399.6 million principal amount of 7.55% Senior Notes due 2038 with attached Guarantee (incorporated by reference to Exhibit E to Exhibit 4.1 to Form 8-K filed October 28, 2009).
4.39	Form of Global Note representing $285.8 million principal amount of Junior Subordinated Notes due 2067 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.2 to Form 8-K filed October 28, 2009).
4.40	Form of Global Note representing $1.0 billion principal amount of 5.20% Senior Notes due 2020 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed May 20, 2010).
4.41	Form of Global Note representing $600.0 million principal amount of 6.45% Senior Notes due 2040 with attached Guarantee (incorporated by reference to Exhibit C to Exhibit 4.3 to Form 8-K filed May 20, 2010).
4.42	Form of Global Note representing $750.0 million principal amount of 3.20% Senior Notes due 2016 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed January 13, 2011).
4.43	Form of Global Note representing $750.0 million principal amount of 5.95% Senior Notes due 2041 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed January 13, 2011).
4.44	Form of Global Note representing $650.0 million principal amount of 4.05% Senior Notes due 2022 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed August 24, 2011).
4.45	Form of Global Note representing $600.0 million principal amount of 5.70% Senior Notes due 2042 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed August 24, 2011).
4.46	Form of Global Note representing $750.0 million principal amount of 4.85% Senior Notes due 2042 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.25 to Form 10-Q filed May 10, 2012).

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4.47	Form of Global Note representing $1.1 billion principal amount of 4.45% Senior Notes due 2043 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed August 13, 2012).
4.48	Form of Global Note representing $1.25 billion principal amount of 3.35% Senior Notes due 2023 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed March 18, 2013).
4.49	Form of Global Note representing $1.0 billion principal amount of 4.85% Senior Notes due 2044 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed March 18, 2013).
4.50	Form of Global Note representing $850.0 million principal amount of 3.90% Senior Notes due 2024 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed February 12, 2014).
4.51	Form of Global Note representing $1.15 billion principal amount of 5.10% Senior Notes due 2045 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed February 12, 2014).
4.52	Form of Global Note representing $800.0 million principal amount of 2.55% Senior Notes due 2019 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.4 to Form 8-K filed October 14, 2014).
4.53	Form of Global Note representing $1.15 billion principal amount of 3.75% Senior Notes due 2025 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.4 to Form 8-K filed October 14, 2014).
4.54	Form of Global Note representing $400.0 million principal amount of 4.95% Senior Notes due 2054 with attached Guarantee (incorporated by reference to Exhibit C to Exhibit 4.4 to Form 8-K filed October 14, 2014).
4.55	Form of Global Note representing $400.0 million principal amount of 4.85% Senior Notes due 2044 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed March 18, 2013).
4.56	Form of Global Note representing $750.0 million principal amount of 1.65% Senior Notes due 2018 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed May 7, 2015).
4.57	Form of Global Note representing $875.0 million principal amount of 3.70% Senior Notes due 2026 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed May 7, 2015).
4.58	Form of Global Note representing $875.0 million principal amount of 4.90% Senior Notes due 2046 with attached Guarantee (incorporated by reference to Exhibit C to Exhibit 4.3 to Form 8-K filed May 7, 2015).
4.59	Form of Global Note representing $575.0 million principal amount of 2.85% Senior Notes due 2021 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.4 to Form 8-K filed April 13, 2016).
4.60	Form of Global Note representing $575.0 million principal amount of 3.95% Senior Notes due 2027 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.4 to Form 8-K filed April 13, 2016).
4.61	Form of Global Note representing $100.0 million principal amount of 4.90% Senior Notes due 2046 with attached Guarantee (incorporated by reference to Exhibit C to Exhibit 4.3 to Form 8-K filed May 7, 2015).
4.62	Form of Global Note representing $700 million principal amount of Junior Subordinated Notes D due 2077 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed August 16, 2017).
4.63	Form of Global Note representing $1.0 billion principal amount of Junior Subordinated Notes E due 2077 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed August 16, 2017).
4.64	Form of Global Note representing $750.0 million principal amount of 2.80% Senior Notes due 2021 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.4 to Form 8-K filed February 15, 2018).

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4.65	Form of Global Note representing $1.25 billion principal amount of 4.25% Senior Notes due 2048 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.4 to Form 8-K filed February 15, 2018).
4.66	Form of Global Note representing $700 million principal amount of Junior Subordinated Notes F due 2078 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed February 15, 2018).
4.67	Replacement Capital Covenant, dated July 18, 2006, executed by Enterprise Products Operating L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 99.1 to Form 8-K filed July 19, 2006).
4.68	First Amendment to Replacement Capital Covenant dated August 25, 2006, executed by Enterprise Products Operating L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 99.2 to Form 8-K filed August 25, 2006).
4.69	Replacement Capital Covenant, dated May 24, 2007, executed by Enterprise Products Operating L.P. and Enterprise Products Partners L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 99.1 to Form 8-K filed May 24, 2007).
4.70	Replacement Capital Covenant, dated October 27, 2009, executed by Enterprise Products Operating LLC and Enterprise Products Partners L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 4.9 to Form 8-K filed October 28, 2009).
4.71	Amendment to Replacement Capital Covenants, dated May 6, 2015, executed by Enterprise Products Operating LLC and Enterprise Products Partners L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 4.59 to Form 10-Q filed May 8, 2015).
4.72	Indenture, dated February 20, 2002, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as Subsidiary Guarantors, and First Union National Bank, NA, as Trustee (incorporated by reference to Exhibit 99.2 to the Form 8-K filed by TEPPCO Partners, L.P. on February 20, 2002).
4.73	Supplemental Indenture, dated June 27, 2002, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as Initial Subsidiary Guarantors, Val Verde Gas Gathering Company, L.P., as New Subsidiary Guarantor, and Wachovia Bank, National Association, formerly known as First Union National Bank, as Trustee (incorporated by reference to Exhibit 4.6 to the Form 10-Q filed by TEPPCO Partners, L.P. on August 14, 2002).
4.74	Full Release of Guarantee, dated July 31, 2006, by Wachovia Bank, National Association, as Trustee, in favor of Jonah Gas Gathering Company (incorporated by reference to Exhibit 4.8 to the Form 10-Q filed by TEPPCO Partners, L.P. on November 7, 2006).
4.75	Fourth Supplemental Indenture, dated June 30, 2007, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Val Verde Gas Gathering Company, L.P., TE Products Pipeline Company, LLC and TEPPCO Midstream Companies, LLC, as Subsidiary Guarantors, and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.3 to the Form 8-K filed by TE Products Pipeline Company, LLC on July 6, 2007).
4.76	Sixth Supplemental Indenture, dated March 27, 2008, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.12 to the Form 10-Q filed by TEPPCO Partners, L.P. on May 8, 2008).
4.77	Seventh Supplemental Indenture, dated March 27, 2008, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.13 to the Form 10-Q filed by TEPPCO Partners, L.P. on May 8, 2008).

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4.78	Eighth Supplemental Indenture, dated October 27, 2009, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 to the Form 8-K filed by TEPPCO Partners, L.P. on October 28, 2009).
4.79	Full Release of Guarantee, dated November 23, 2009, of TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P. by U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.64 to Form 10-K filed March 1, 2010).
4.80	Indenture, dated May 14, 2007, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and The Bank of New York Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 99.1 of the Form 8-K filed by TEPPCO Partners, L.P. on May 15, 2007).
4.81	First Supplemental Indenture, dated May 18, 2007, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and The Bank of New York Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.2 to the Form 8-K filed by TEPPCO Partners, L.P. on May 18, 2007).
4.82	Second Supplemental Indenture, dated as of June 30, 2007, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Val Verde Gas Gathering Company, L.P., as Existing Subsidiary Guarantors, TE Products Pipeline Company, LLC and TEPPCO Midstream Companies, LLC, as New Subsidiary Guarantors, and The Bank of New York Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.2 to the Form 8-K filed by TE Products Pipeline Company, LLC on July 6, 2007).
4.83	Third Supplemental Indenture, dated as of October 27, 2009, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and The Bank of New York Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.2 to the Form 8-K filed by TEPPCO Partners, L.P. on October 28, 2009).
4.84	Full Release of Guarantee, dated as of November 23, 2009, of TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P. by The Bank of New York Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.70 to Form 10-K filed March 1, 2010).
4.85	Registration Rights Agreement by and between Enterprise Products Partners L.P. and Oiltanking Holding Americas, Inc. dated as of October 1, 2014 (incorporated by reference to Exhibit 4.1 to Form 8-K filed October 1, 2014).
12.1#	Computation of ratio of earnings to fixed charges for the three months ended March 31, 2018 and each of the years ended December 31, 2017, 2016, 2015, 2014 and 2013.
31.1#	Sarbanes-Oxley Section 302 certification of A. James Teague for Enterprise Products Partners L.P.’s quarterly report on Form 10-Q for the three months ended March 31, 2018.
31.2#	Sarbanes-Oxley Section 302 certification of W. Randall Fowler for Enterprise Products Partners L.P.’s quarterly report on Form 10-Q for the three months ended March 31, 2018.
31.3#	Sarbanes-Oxley Section 302 certification of Bryan F. Bulawa for Enterprise Products Partners L.P.’s quarterly report on Form 10-Q for the three months ended March 31, 2018.
32.1#	Sarbanes-Oxley Section 906 certification of A. James Teague for Enterprise Products Partners L.P.’s quarterly report on Form 10-Q for the three months ended March 31, 2018.
32.2#	Sarbanes-Oxley Section 906 certification of W. Randall Fowler for Enterprise Products Partners L.P.’s quarterly report on Form 10-Q for the three months ended March 31, 2018.
32.3#	Sarbanes-Oxley Section 906 certification of Bryan F. Bulawa for Enterprise Products Partners L.P.’s quarterly report on Form 10-Q for the three months ended March 31, 2018.
101.CAL#	XBRL Calculation Linkbase Document
101.DEF#	XBRL Definition Linkbase Document
101.INS#	XBRL Instance Document

Table of Contents

101.LAB#	XBRL Labels Linkbase Document
101.PRE#	XBRL Presentation Linkbase Document
101.SCH#	XBRL Schema Document

*	With respect to any exhibits incorporated by reference to any Exchange Act filings, the Commission file numbers for Enterprise Products Partners L.P., Enterprise GP Holdings L.P, TEPPCO Partners, L.P. and TE Products Pipeline Company, LLC are 1-14323, 1-32610, 1-10403 and 1-13603, respectively.
***	Identifies management contract and compensatory plan arrangements.
#	Filed with this report.

Table of Contents

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on May 9, 2018.

		ENTERPRISE PRODUCTS PARTNERS L.P. (A Delaware Limited Partnership)
		By:	Enterprise Products Holdings LLC, as General Partner


		By:	/s/ R. Daniel Boss
		Name:	R. Daniel Boss
		Title:	Senior Vice President – Accounting and Risk Control of the General Partner


		By:	/s/ Michael W. Hanson
		Name:	Michael W. Hanson
		Title:	Vice President and Principal Accounting Officer of the General Partner

Delaware		76-0568219
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

Large accelerated filer 	Accelerated filer 
Non-accelerated filer  (Do not check if a smaller reporting company)	Smaller reporting company 
Emerging growth company 

	March 31, 2018			December 31, 2017
ASSETS
Current assets:
Cash and cash equivalents	$	102.1		$	5.1
Restricted cash		113.5			65.2
Accounts receivable – trade, net of allowance for doubtful accounts of $11.4 at March 31, 2018 and $12.1 at December 31, 2017		4,439.9			4,358.4
Accounts receivable – related parties		3.6			1.8
Inventories		1,699.9			1,609.8
Derivative assets		78.7			153.4
Prepaid and other current assets		353.3			312.7
Total current assets		6,791.0			6,506.4
Property, plant and equipment, net		36,416.3			35,620.4
Investments in unconsolidated affiliates		2,583.4			2,659.4
Intangible assets, net of accumulated amortization of $1,607.9 at March 31, 2018 and $1,564.8 at December 31, 2017 (see Note 6)		3,736.4			3,690.3
Goodwill (see Note 6)		5,745.2			5,745.2
Other assets		210.0			196.4
Total assets	$	55,482.3		$	54,418.1

LIABILITIES AND EQUITY
Current liabilities:
Current maturities of debt (see Note 7)	$	2,376.8		$	2,855.0
Accounts payable – trade		730.6			801.7
Accounts payable – related parties		83.0			127.3
Accrued product payables		4,942.8			4,566.3
Accrued interest		210.8			358.0
Derivative liabilities		160.9			168.2
Other current liabilities		334.7			418.6
Total current liabilities		8,839.6			9,295.1
Long-term debt (see Note 7)		23,016.4			21,713.7
Deferred tax liabilities		58.0			58.5
Other long-term liabilities		603.4			578.4
Commitments and contingencies (see Note 16)
Equity: (see Note 8)
Partners’ equity:
Limited partners:
Common units (2,171,412,794 units outstanding at March 31, 2018 and 2,161,089,479 units outstanding at December 31, 2017)		22,914.5			22,718.9
Accumulated other comprehensive loss		(161.2	)		(171.7	)
Total partners’ equity		22,753.3			22,547.2
Noncontrolling interests		211.6			225.2
Total equity		22,964.9			22,772.4
Total liabilities and equity	$	55,482.3		$	54,418.1

	For the Three Months Ended March 31,
	2018			2017

Net income	$	911.5		$	771.0
Other comprehensive income (loss):
Cash flow hedges:
Commodity derivative instruments:
Changes in fair value of cash flow hedges		3.4			144.8
Reclassification of losses (gains) to net income		(14.5	)		7.1
Interest rate derivative instruments:
Changes in fair value of cash flow hedges		11.1			2.4
Reclassification of losses to net income		10.5			9.6
Total cash flow hedges		10.5			163.9
Other		--			(0.1	)
Total other comprehensive income		10.5			163.8
Comprehensive income		922.0			934.8
Comprehensive income attributable to noncontrolling interests		(10.8	)		(10.3	)
Comprehensive income attributable to limited partners	$	911.2		$	924.5

	For the Three Months Ended March 31,
	2018			2017
Operating activities:
Net income	$	911.5		$	771.0
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		431.0			402.3
Asset impairment and related charges (see Note 14)		0.9			11.2
Equity in income of unconsolidated affiliates		(115.7	)		(94.8	)
Distributions received on earnings from unconsolidated affiliates		107.5			90.5
Net gains attributable to asset sales		(0.5	)		(0.3	)
Deferred income tax expense (benefit)		(1.1	)		0.1
Change in fair market value of derivative instruments		136.9			(20.3	)
Change in fair market value of Liquidity Option Agreement		7.5			5.5
Gain on step acquisition of unconsolidated affiliate (see Note 11)		(37.0	)		--
Net effect of changes in operating accounts (see Note 17)		(203.1	)		(288.8	)
Other operating activities		(4.3	)		(0.8	)
Net cash flows provided by operating activities		1,233.6			875.6
Investing activities:
Capital expenditures		(946.5	)		(430.4	)
Cash used for business combinations, net of cash received (see Note 11)		(149.8	)		(16.0	)
Investments in unconsolidated affiliates		(37.9	)		(13.7	)
Distributions received for return of capital from unconsolidated affiliates		14.9			12.0
Proceeds from asset sales		1.1			2.0
Other investing activities		(0.9	)		2.1
Cash used in investing activities		(1,119.1	)		(444.0	)
Financing activities:
Borrowings under debt agreements		16,283.8			17,575.1
Repayments of debt		(15,444.7	)		(17,856.5	)
Debt issuance costs		(24.2	)		--
Monetization of interest rate derivative instruments		1.5			--
Cash distributions paid to limited partners (see Note 8)		(918.5	)		(869.0	)
Cash payments made in connection with distribution equivalent rights		(3.9	)		(3.2	)
Cash distributions paid to noncontrolling interests		(15.4	)		(10.1	)
Cash contributions from noncontrolling interests		0.1			0.2
Net cash proceeds from the issuance of common units		177.0			448.8
Other financing activities		(24.9	)		(27.4	)
Cash provided by (used in) financing activities		30.8			(742.1	)
Net change in cash and cash equivalents, including restricted cash		145.3			(310.5	)
Cash and cash equivalents, including restricted cash, at beginning of period		70.3			417.6
Cash and cash equivalents, including restricted cash, at end of period	$	215.6		$	107.1

		Page No.
PART I. FINANCIAL INFORMATION.
Item 1.	Financial Statements.
	Unaudited Condensed Consolidated Balance Sheets	2
	Unaudited Condensed Statements of Consolidated Operations	3
	Unaudited Condensed Statements of Consolidated Comprehensive Income	4
	Unaudited Condensed Statements of Consolidated Cash Flows	5
	Unaudited Condensed Statements of Consolidated Equity	6
	Notes to Unaudited Condensed Consolidated Financial Statements:
	1. Partnership Organization and Basis of Presentation	7
	2. Summary of Significant Accounting Policies	8
	3. Inventories	10
	4. Property, Plant and Equipment	11
	5. Investments in Unconsolidated Affiliates	12
	6. Intangible Assets and Goodwill	13
	7. Debt Obligations	15
	8. Equity and Distributions	17
	9. Revenues	20
	10. Business Segments	23
	11. Business Combinations	26
	12. Earnings Per Unit	27
	13. Equity-Based Awards	27
	14. Derivative Instruments, Hedging Activities and Fair Value Measurements	30
	15. Related Party Transactions	37
	16. Commitments and Contingencies	38
	17. Supplemental Cash Flow Information	41
	18. Condensed Consolidating Financial Information	42
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	48
Item 3.	Quantitative and Qualitative Disclosures About Market Risk.	70
Item 4.	Controls and Procedures.	74

PART II. OTHER INFORMATION.
Item 1.	Legal Proceedings.	74
Item 1A.	Risk Factors.	74
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	75
Item 3.	Defaults Upon Senior Securities.	75
Item 4.	Mine Safety Disclosures.	75
Item 5.	Other Information.	75
Item 6.	Exhibits.	76

Signatures		85

	Partners’ Equity
	Limited Partners			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
Balance, January 1, 2018	$	22,718.9		$	(171.7	)	$	225.2		$	22,772.4
Net income		900.7			--			10.8			911.5
Cash distributions paid to limited partners		(918.5	)		--			--			(918.5	)
Cash payments made in connection with distribution equivalent rights		(3.9	)		--			--			(3.9	)
Cash distributions paid to noncontrolling interests		--			--			(15.4	)		(15.4	)
Cash contributions from noncontrolling interests		--			--			0.1			0.1
Net cash proceeds from the issuance of common units		177.0			--			--			177.0
Common units issued in connection with employee compensation		39.1			--			--			39.1
Amortization of fair value of equity-based awards		26.0			--			--			26.0
Cash flow hedges		--			10.5			--			10.5
Other		(24.8	)		--			(9.1	)		(33.9	)
Balance, March 31, 2018	$	22,914.5		$	(161.2	)	$	211.6		$	22,964.9

	March 31, 2018		December 31, 2017
NGLs	$	922.4	$	917.4
Petrochemicals and refined products		195.7		161.5
Crude oil		571.1		516.3
Natural gas		10.7		14.6
Total	$	1,699.9	$	1,609.8

	Estimated Useful Life in Years	March 31, 2018		December 31, 2017
Plants, pipelines and facilities (1)	3-45 (5)	$	37,700.9	$	37,132.2
Underground and other storage facilities (2)	5-40 (6)		3,511.1		3,460.9
Transportation equipment (3)	3-10		178.9		177.1
Marine vessels (4)	15-30		809.3		803.8
Land			274.3		273.1
Construction in progress			5,203.1		4,698.1
Total			47,677.6		46,545.2
Less accumulated depreciation			11,261.3		10,924.8
Property, plant and equipment, net		$	36,416.3	$	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. (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.

ARO liability balance, January 1, 2018	$	86.7
Liabilities incurred		--
Liabilities settled		(0.5	)
Revisions in estimated cash flows		--
Accretion expense		1.4
ARO liability balance, March 31, 2018	$	87.6

	Ownership Interest at March 31, 2018	March 31, 2018		December 31, 2017
NGL Pipelines & Services:
Venice Energy Service Company, L.L.C.	13.1%	$	24.6	$	25.7
K/D/S Promix, L.L.C.	50%		29.6		30.9
Baton Rouge Fractionators LLC	32.2%		16.8		17.0
Skelly-Belvieu Pipeline Company, L.L.C.	50%		36.4		37.0
Texas Express Pipeline LLC	35%		310.5		314.4
Texas Express Gathering LLC	45%		35.7		35.9
Front Range Pipeline LLC	33.3%		164.5		165.7
Delaware Basin Gas Processing LLC (“Delaware Processing”)	100%		--		107.3
Crude Oil Pipelines & Services:
Seaway Crude Pipeline Company LLC	50%		1,392.3		1,378.9
Eagle Ford Pipeline LLC	50%		387.8		385.2
Eagle Ford Terminals Corpus Christi LLC	50%		92.4		75.1
Natural Gas Pipelines & Services:
White River Hub, LLC	50%		20.6		20.8
Petrochemical & Refined Products Services:
Centennial Pipeline LLC	50%		57.9		60.8
Other	Various		14.3		4.7
Total		$	2,583.4	$	2,659.4

	March 31, 2018							December 31, 2017
	Gross Value		Accumulated Amortization			Carrying Value		Gross Value		Accumulated Amortization			Carrying Value
NGL Pipelines & Services:
Customer relationship intangibles	$	457.8	$	(191.1	)	$	266.7	$	447.4	$	(187.5	)	$	259.9
Contract-based intangibles		359.6		(221.9	)		137.7		280.8		(218.4	)		62.4
Segment total		817.4		(413.0	)		404.4		728.2		(405.9	)		322.3
Crude Oil Pipelines & Services:
Customer relationship intangibles		2,203.5		(139.5	)		2,064.0		2,203.5		(127.0	)		2,076.5
Contract-based intangibles		281.0		(182.5	)		98.5		281.0		(171.0	)		110.0
Segment total		2,484.5		(322.0	)		2,162.5		2,484.5		(298.0	)		2,186.5
Natural Gas Pipelines & Services:
Customer relationship intangibles		1,350.3		(424.7	)		925.6		1,350.3		(417.1	)		933.2
Contract-based intangibles		464.7		(381.6	)		83.1		464.7		(379.5	)		85.2
Segment total		1,815.0		(806.3	)		1,008.7		1,815.0		(796.6	)		1,018.4
Petrochemical & Refined Products Services:
Customer relationship intangibles		181.4		(47.4	)		134.0		181.4		(45.9	)		135.5
Contract-based intangibles		46.0		(19.2	)		26.8		46.0		(18.4	)		27.6
Segment total		227.4		(66.6	)		160.8		227.4		(64.3	)		163.1
Total intangible assets	$	5,344.3	$	(1,607.9	)	$	3,736.4	$	5,255.1	$	(1,564.8	)	$	3,690.3

	March 31, 2018			December 31, 2017
EPO senior debt obligations:
Commercial Paper Notes, variable-rates	$	576.8		$	1,755.7
Senior Notes V, 6.65% fixed-rate, due April 2018		349.7			349.7
Senior Notes OO, 1.65% fixed-rate, due May 2018		750.0			750.0
364-Day Revolving Credit Agreement, variable-rate, due September 2018		--			--
Senior Notes N, 6.50% fixed-rate, due January 2019		700.0			700.0
Senior Notes LL, 2.55% fixed-rate, due October 2019		800.0			800.0
Senior Notes Q, 5.25% fixed-rate, due January 2020		500.0			500.0
Senior Notes Y, 5.20% fixed-rate, due September 2020		1,000.0			1,000.0
Senior Notes 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 CC, 4.05% fixed-rate, due February 2022		650.0			650.0
Multi-Year Revolving Credit Facility, variable-rate, due September 2022		--			--
Senior Notes HH, 3.35% fixed-rate, due March 2023		1,250.0			1,250.0
Senior Notes JJ, 3.90% fixed-rate, due February 2024		850.0			850.0
Senior Notes MM, 3.75% fixed-rate, due February 2025		1,150.0			1,150.0
Senior Notes PP, 3.70% fixed-rate, due February 2026		875.0			875.0
Senior Notes SS, 3.95% fixed-rate, due February 2027		575.0			575.0
Senior Notes D, 6.875% fixed-rate, due March 2033		500.0			500.0
Senior Notes H, 6.65% fixed-rate, due October 2034		350.0			350.0
Senior Notes J, 5.75% fixed-rate, due March 2035		250.0			250.0
Senior Notes W, 7.55% fixed-rate, due April 2038		399.6			399.6
Senior Notes R, 6.125% fixed-rate, due October 2039		600.0			600.0
Senior Notes Z, 6.45% fixed-rate, due September 2040		600.0			600.0
Senior Notes BB, 5.95% fixed-rate, due February 2041		750.0			750.0
Senior Notes DD, 5.70% fixed-rate, due February 2042		600.0			600.0
Senior Notes EE, 4.85% fixed-rate, due August 2042		750.0			750.0
Senior Notes GG, 4.45% fixed-rate, due February 2043		1,100.0			1,100.0
Senior Notes II, 4.85% fixed-rate, due March 2044		1,400.0			1,400.0
Senior Notes KK, 5.10% fixed-rate, due February 2045		1,150.0			1,150.0
Senior Notes QQ, 4.90% fixed-rate, due May 2046		975.0			975.0
Senior Notes UU, 4.25% fixed-rate, due February 2048		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			0.3
TEPPCO Senior Notes, 7.55% fixed-rate, due April 2038		0.4			0.4
Total principal amount of senior debt obligations		22,426.8			21,605.7
EPO Junior Subordinated Notes A, variable-rate, due August 2066 (1)		521.1			521.1
EPO Junior Subordinated Notes C, variable-rate, due June 2067 (2)		256.4			256.4
EPO Junior Subordinated Notes B, fixed/variable-rate, due January 2068 (3)		--			682.7
EPO Junior Subordinated Notes D, fixed/variable-rate, due August 2077 (4)		700.0			700.0
EPO Junior Subordinated Notes E, fixed/variable-rate, due August 2077 (5)		1,000.0			1,000.0
EPO Junior Subordinated Notes F, fixed/variable-rate, due February 2078 (6)		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		25,618.5			24,780.1
Other, non-principal amounts		(225.3	)		(211.4	)
Less current maturities of debt		(2,376.8	)		(2,855.0	)
Total long-term debt	$	23,016.4		$	21,713.7

(1) Variable rate is reset quarterly and based on 3-month LIBOR plus 3.708%. (2) Variable rate is reset quarterly and based on 3-month LIBOR plus 2.778%. (3) Notes were redeemed in March 2018. (4) Fixed rate of 4.875% through August 15, 2022; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 2.986%. (5) Fixed rate of 5.250% through August 15, 2027; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 3.033%. (6) Fixed rate of 5.375% through February 14, 2028; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 2.57%.

	Range of Interest Rates Paid	Weighted-Average Interest Rate Paid
Commercial Paper Notes	1.50% to 2.50%	1.79%
Multi-Year Revolving Credit Facility	2.58% to 2.59%	2.58%
EPO Junior Subordinated Notes A	5.08% to 5.48%	5.34%
EPO Junior Subordinated Notes C	4.26% to 4.78%	4.44%

Number of common units outstanding at January 1, 2018	2,161,089,479
Common units issued in connection with DRIP and EUPP	6,642,286
Common units issued in connection with the vesting of phantom unit awards	3,170,861
Cancellation of treasury units acquired in connection with the vesting of equity-based awards	(949,778	)
Common units issued in connection with employee compensation	1,443,586
Other	16,360
Number of common units outstanding at March 31, 2018	2,171,412,794

	Gains (Losses) on Cash Flow Hedges
	Commodity Derivative Instruments			Interest Rate Derivative Instruments			Other		Total
Balance, January 1, 2018	$	(10.1	)	$	(165.1	)	$	3.5	$	(171.7	)
Other comprehensive income before reclassifications		3.4			11.1			--		14.5
Amounts reclassified from accumulated other comprehensive loss (income)		(14.5	)		10.5			--		(4.0	)
Total other comprehensive income (loss)		(11.1	)		21.6			--		10.5
Balance, March 31, 2018	$	(21.2	)	$	(143.5	)	$	3.5	$	(161.2	)

		For the Three Months Ended March 31,
	Location	2018			2017
Losses (gains) on cash flow hedges:
Interest rate derivatives	Interest expense	$	10.5		$	9.6
Commodity derivatives	Revenue		(14.0	)		7.5
Commodity derivatives	Operating costs and expenses		(0.5	)		(0.4	)
Total		$	(4.0	)	$	16.7

	Distribution Per Common Unit		Record Date	Payment Date
2017
1st Quarter	$	0.4150	4/28/2017	5/8/2017
2018
1st Quarter	$	0.4275	4/30/2018	5/8/2018

	For the Three Months Ended March 31,
	2018 (1)		2017 (2)
NGL Pipelines & Services:
Sales of NGLs and related products	$	2,815.4	$	2,887.2
Midstream services		597.9		458.6
Total		3,413.3		3,345.8
Crude Oil Pipelines & Services:
Sales of crude oil		3,341.7		1,618.6
Midstream services		229.2		188.6
Total		3,570.9		1,807.2
Natural Gas Pipelines & Services:
Sales of natural gas		560.0		544.0
Midstream services		244.8		217.2
Total		804.8		761.2
Petrochemical & Refined Products Services:
Sales of petrochemicals and refined products		1,289.3		1,211.1
Midstream services		220.2		195.1
Total		1,509.5		1,406.2
Total consolidated revenues	$	9,298.5	$	7,320.4

(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.

Contract Asset	Location	Balance
Unbilled revenue (current amount)	Prepaid and other current assets	$	64.4
Unbilled revenue (noncurrent)	Other assets		0.2
Total		$	64.6

Contract Liability	Location	Balance
Deferred revenue (current amount)	Other current liabilities	$	78.5
Deferred revenue (noncurrent)	Other long-term liabilities		140.6
Total		$	219.1

	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)		--		(54.0	)
Amount recorded during period		62.4		86.0
Amounts recorded during period transferred to other accounts (1)		--		(37.6	)
Amount recorded in connection with business combination		2.2		--
Balance at March 31, 2018	$	64.6	$	219.1

(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.

	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	$	4,504.5	$	(64.6	)	$	4,439.9
Prepaid and other current assets	$	288.9	$	64.4		$	353.3
Property, plant and equipment, net	$	36,410.9	$	5.4		$	36,416.3
Other assets	$	209.8	$	0.2		$	210.0
Liabilities and Equity
Other long-term liabilities	$	601.2	$	2.2		$	603.4
Partners' equity	$	22,750.1	$	3.2		$	22,753.3

	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:
Three months ended March 31, 2018	$	3,409.6	$	3,552.7	$	802.0	$	1,509.5		$	--		$	9,273.8
Three months ended March 31, 2017		3,343.0		1,802.6		757.8		1,406.2			--			7,309.6
Revenues from related parties:
Three months ended March 31, 2018		3.7		18.2		2.8		--			--			24.7
Three months ended March 31, 2017		2.8		4.6		3.4		--			--			10.8
Intersegment and intrasegment revenues:
Three months ended March 31, 2018		6,564.9		11,426.3		170.9		613.3			(18,775.4	)		--
Three months ended March 31, 2017		8,874.8		3,474.0		194.5		414.7			(12,958.0	)		--
Total revenues:
Three months ended March 31, 2018		9,978.2		14,997.2		975.7		2,122.8			(18,775.4	)		9,298.5
Three months ended March 31, 2017		12,220.6		5,281.2		955.7		1,820.9			(12,958.0	)		7,320.4
Equity in income (loss) of unconsolidated affiliates:
Three months ended March 31, 2018		19.4		97.9		1.0		(2.6	)		--			115.7
Three months ended March 31, 2017		15.5		81.2		1.0		(2.9	)		--			94.8

Cash paid for remaining 50% equity interest in Delaware Processing	$	153.6
Fair value of our 50% equity interest in Delaware Processing held before the acquisition		146.4
Total		300.0
Recognized amounts of identifiable assets acquired and liabilities assumed:
Assets acquired in business combination:
Current assets, including cash of $3.8 million	$	12.7
Property, plant and equipment		200.0
Contract-based intangible assets		78.8
Customer relationship intangible assets		10.4
Total assets acquired	$	301.9
Liabilities assumed in business combination:
Current liabilities	$	(1.3	)
Long-term liabilities		(0.6	)
Total liabilities assumed	$	(1.9	)
Total identifiable net assets	$	300.0
Goodwill	$	--

	Number of Units			Weighted- Average Grant Date Fair Value per Unit (1)
Phantom unit awards at January 1, 2018		9,289,501		$	27.65
Granted (2)		4,940,081		$	26.81
Vested		(3,170,861	)	$	28.64
Forfeited		(74,656	)	$	26.98
Phantom unit awards at March 31, 2018		10,984,065		$	26.99

(1) Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued. (2) The aggregate grant date fair value of phantom unit awards issued during 2018 was $132.4 million based on a grant date market price of our common units ranging from $25.40 to $26.81 per unit. An estimated annual forfeiture rate of 3.2% was applied to these awards.

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	$	0.39	Feb. 2020	$13.2 million	$6.6 million
PubCo II	2,834,198	$66.3 million	$	0.39	Feb. 2021	$14.7 million	$8.6 million
PubCo III	105,000	$2.5 million	$	0.39	Apr. 2020	$0.5 million	$0.3 million
PrivCo I	1,111,438	$26.0 million	$	0.39	Feb. 2021	$5.8 million	$0.7 million

(1) Represents fair market value of the Enterprise common units contributed to each Employee Partnership at the applicable contribution date. (2) Each quarter, the Class A limited partner in each Employee Partnership is paid a cash distribution equal to the product of (i) the number of common units owned by the Employee Partnership and (ii) the Class A Preference Return of $0.39 per unit (subject to equitable adjustment in order to reflect any equity split, equity distribution or dividend, reverse split, combination, reclassification, recapitalization or other similar event affecting such common units). To the extent that the Employee Partnership has cash remaining after making this quarterly payment to the Class A limited partner, the residual cash is distributed to the Class B limited partners on a quarterly basis. (3) Represents the total grant date fair value of the profits interest awards irrespective of how such costs will be allocated between us and EPCO and its privately held affiliates. (4) Represents our expected share of the unrecognized compensation cost at March 31, 2018. We expect to recognize our share of the unrecognized compensation cost for PubCo I, PubCo II, PubCo III and PrivCo I over a weighted-average period of 1.9 years, 2.9 years, 2.0 years and 2.9 years, respectively.

	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 2.2%	6.2% to 7.0%	24% to 40%
PubCo II	5.0 years	1.1% to 2.3%	6.1% to 7.0%	27% 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%

	Asset Derivatives						Liability Derivatives
	March 31, 2018			December 31, 2017			March 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	$	9.5	Current assets	$	--	Current liabilities	$	1.6	Current liabilities	$	1.5
Interest rate derivatives	Other assets		--	Other assets		0.1	Other liabilities		--	Other liabilities		0.2
Total interest rate derivatives			9.5			0.1			1.6			1.7
Commodity derivatives	Current assets		61.0	Current assets		109.5	Current liabilities		59.9	Current liabilities		104.4
Commodity derivatives	Other assets		15.7	Other assets		6.4	Other liabilities		15.7	Other liabilities		6.8
Total commodity derivatives			76.7			115.9			75.6			111.2
Total derivatives designated as hedging instruments		$	86.2		$	116.0		$	77.2		$	112.9

Derivatives not designated as hedging instruments
Commodity derivatives	Current assets	$	8.2	Current assets	$	43.9	Current liabilities	$	99.4	Current liabilities	$	62.3
Commodity derivatives	Other assets		0.4	Other assets		1.9	Other liabilities		8.0	Other liabilities		3.4
Total commodity derivatives		$	8.6		$	45.8		$	107.4		$	65.7

	Offsetting of Financial Assets and Derivative Assets
	Gross Amounts of Recognized Assets			Gross Amounts Offset in the Balance Sheet			Amounts of Assets Presented in the Balance Sheet			Gross Amounts Not Offset in the Balance Sheet								Amounts That Would Have Been Presented On Net Basis
	Gross Amounts of Recognized Assets			Gross Amounts Offset in the Balance Sheet			Amounts of Assets Presented in the Balance Sheet			Financial Instruments				Cash Collateral Received		Cash Collateral Paid		Amounts That Would Have Been Presented On Net Basis
	(i)			(ii)			(iii) = (i) – (ii)			(iv)								(v) = (iii) + (iv)
As of March 31, 2018:
Interest rate derivatives		$	9.5		$	--		$	9.5		$	(0.3	)	$	--	$	--		$	9.2
Commodity derivatives			85.3			--			85.3			(84.6	)		--		--			0.7
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 of Recognized Liabilities			Gross Amounts Offset in the Balance Sheet			Amounts of Liabilities Presented in the Balance Sheet			Gross Amounts Not Offset in the Balance Sheet									Amounts That Would Have Been Presented On Net Basis
	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheet			Amounts of Liabilities Presented in the Balance Sheet			Financial Instruments				Cash Collateral Received		Cash Collateral Paid			Amounts That Would Have Been Presented On Net Basis
	(i)			(ii)			(iii) = (i) – (ii)			(iv)									(v) = (iii) + (iv)
As of March 31, 2018:
Interest rate derivatives		$	1.6		$	--		$	1.6		$	(0.3	)	$	--	$	--			$	1.3
Commodity derivatives			183.0			--			183.0			(84.6	)		--		(97.9	)			0.5
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

Derivatives in Fair Value Hedging Relationships	Location	Gain (Loss) Recognized in Income on Derivative
		For the Three Months Ended March 31,
		2018			2017
Interest rate derivatives	Interest expense	$	0.7		$	(0.9	)
Commodity derivatives	Revenue		(0.2	)		18.8
Total		$	0.5		$	17.9

Derivatives in Fair Value Hedging Relationships	Location	Gain (Loss) Recognized in Income on Hedged Item
		For the Three Months Ended March 31,
		2018			2017
Interest rate derivatives	Interest expense	$	(0.8	)	$	0.9
Commodity derivatives	Revenue		3.1			(12.4	)
Total		$	2.3		$	(11.5	)

Derivatives in Cash Flow Hedging Relationships	Change in Value Recognized in Other Comprehensive Income (Loss) on Derivative
	For the Three Months Ended March 31,
	2018		2017
Interest rate derivatives	$	11.1	$	2.4
Commodity derivatives – Revenue (1)		3.0		147.6
Commodity derivatives – Operating costs and expenses (1)		0.4		(2.8	)
Total	$	14.5	$	147.2

(1) The fair value of these derivative instruments will be reclassified to their respective locations on the Unaudited Condensed 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 Three Months Ended March 31,
		2018			2017
Interest rate derivatives	Interest expense	$	(10.5	)	$	(9.6	)
Commodity derivatives	Revenue		14.0			(7.5	)
Commodity derivatives	Operating costs and expenses		0.5			0.4
Total		$	4.0		$	(16.7	)