UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

☑ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2019

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___ to ___.

Commission file number: 001-14323

ENTERPRISE PRODUCTS PARTNERS L.P.

(Exact Name of Registrant as Specified in Its Charter)

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

1100 Louisiana 10th Floor

Houston, Texas 77002

(Address of Principal Executive Offices, including Zip Code)

(713) 381-6500

(Registrant’s Telephone Number, including Area Code)

Securities registered pursuant to Section 12(b) of the Securities Exchange Act of 1934:

Title of Each Class	Trading Symbol(s)	Name of Each Exchange On Which Registered
Common Units	EPD	New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer ☑	Accelerated filer ☐
Non-accelerated filer ☐ (Do not check if a smaller reporting company)	Smaller reporting company ☐
Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑

There were 2,189,005,978 common units of Enterprise Products Partners L.P. outstanding at the close of business on July 31, 2019.

Table of Contents

ENTERPRISE PRODUCTS PARTNERS L.P.

TABLE OF CONTENTS

		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	8
	2. Summary of Significant Accounting Policies	9
	3. Inventories	10
	4. Property, Plant and Equipment	11
	5. Investments in Unconsolidated Affiliates	12
	6. Intangible Assets and Goodwill	13
	7. Debt Obligations	14
	8. Equity and Distributions	16
	9. Revenues	19
	10. Business Segments and Related Information	20
	11. Earnings Per Unit	24
	12. Equity-Based Awards	24
	13. Derivative Instruments, Hedging Activities and Fair Value Measurements	26
	14. Related Party Transactions	33
	15. Commitments and Contingencies	34
	16. Supplemental Cash Flow Information	38
	17. Condensed Consolidating Financial Information	39
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	46
Item 3.	Quantitative and Qualitative Disclosures About Market Risk.	74
Item 4.	Controls and Procedures.	78

PART II. OTHER INFORMATION.
Item 1.	Legal Proceedings.	78
Item 1A.	Risk Factors.	79
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	79
Item 3.	Defaults Upon Senior Securities.	79
Item 4.	Mine Safety Disclosures.	79
Item 5.	Other Information.	79
Item 6.	Exhibits.	80

Signatures		89

Table of Contents

PART I. FINANCIAL INFORMATION.

ITEM 1. FINANCIAL STATEMENTS.

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

	June 30, 2019			December 31, 2018
ASSETS
Current assets:
Cash and cash equivalents	$	107.3		$	344.8
Restricted cash		–			65.3
Accounts receivable – trade, net of allowance for doubtful accounts of $11.5 at June 30, 2019 and $11.5 at December 31, 2018		3,787.6			3,659.1
Accounts receivable – related parties		14.2			3.5
Inventories		1,586.1			1,522.1
Derivative assets		195.8			154.4
Prepaid and other current assets		567.9			311.5
Total current assets		6,258.9			6,060.7
Property, plant and equipment, net		40,089.1			38,737.6
Investments in unconsolidated affiliates		2,652.1			2,615.1
Intangible assets, net of accumulated amortization of $1,815.1 at June 30, 2019 and $1,735.1 at December 31, 2018 (see Note 6)		3,532.6			3,608.4
Goodwill (see Note 6)		5,745.2			5,745.2
Other assets		443.9			202.8
Total assets	$	58,721.8		$	56,969.8

LIABILITIES AND EQUITY
Current liabilities:
Current maturities of debt (see Note 7)	$	500.0		$	1,500.1
Accounts payable – trade		1,078.5			1,102.8
Accounts payable – related parties		73.6			140.2
Accrued product payables		3,614.9			3,475.8
Accrued interest		392.3			395.6
Derivative liabilities		128.4			148.2
Other current liabilities		476.4			404.8
Total current liabilities		6,264.1			7,167.5
Long-term debt (see Note 7)		26,385.0			24,678.1
Deferred tax liabilities		84.6			80.4
Other long-term liabilities		1,012.7			751.6
Commitments and contingencies (see Note 15)
Equity: (see Note 8)
Partners’ equity:
Limited partners:
Common units (2,189,005,978 units outstanding at June 30, 2019 and 2,184,869,029 units outstanding at December 31, 2018)		24,450.5			23,802.6
Accumulated other comprehensive income (loss)		(10.7	)		50.9
Total partners’ equity		24,439.8			23,853.5
Noncontrolling interests		535.6			438.7
Total equity		24,975.4			24,292.2
Total liabilities and equity	$	58,721.8		$	56,969.8

See Notes to Unaudited Condensed Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS

(Dollars in millions, except per unit amounts)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
Revenues:
Third parties	$	8,250.5		$	8,411.9		$	16,781.7		$	17,685.7
Related parties		25.8			55.6			38.1			80.3
Total revenues (see Note 9)		8,276.3			8,467.5			16,819.8			17,766.0
Costs and expenses:
Operating costs and expenses:
Third parties		6,469.5			7,174.3			13,124.8			15,078.6
Related parties		331.4			377.7			695.8			696.1
Total operating costs and expenses		6,800.9			7,552.0			13,820.6			15,774.7
General and administrative costs:
Third parties		21.4			20.9			41.8			42.2
Related parties		31.1			30.5			62.9			62.2
Total general and administrative costs		52.5			51.4			104.7			104.4
Total costs and expenses (see Note 10)		6,853.4			7,603.4			13,925.3			15,879.1
Equity in income of unconsolidated affiliates		137.4			122.3			292.0			238.0
Operating income		1,560.3			986.4			3,186.5			2,124.9
Other income (expense):
Interest expense		(290.1	)		(274.6	)		(567.3	)		(526.7	)
Change in fair market value of Liquidity Option Agreement		(26.6	)		(8.9	)		(84.4	)		(16.4	)
Gain on step acquisition of unconsolidated affiliate (see Note 16)		–			2.4			–			39.4
Other, net		2.6			0.3			4.1			1.0
Total other expense, net		(314.1	)		(280.8	)		(647.6	)		(502.7	)
Income before income taxes		1,246.2			705.6			2,538.9			1,622.2
Provision for income taxes		(9.7	)		(18.4	)		(22.0	)		(23.5	)
Net income		1,236.5			687.2			2,516.9			1,598.7
Net income attributable to noncontrolling interests (see Note 8)		(21.8	)		(13.4	)		(41.7	)		(24.2	)
Net income attributable to limited partners	$	1,214.7		$	673.8		$	2,475.2		$	1,574.5

Earnings per unit: (see Note 11)
Basic earnings per unit	$	0.55		$	0.31		$	1.12		$	0.72
Diluted earnings per unit	$	0.55		$	0.31		$	1.12		$	0.72

See Notes to Unaudited Condensed Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED

COMPREHENSIVE INCOME

(Dollars in millions)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018

Net income	$	1,236.5		$	687.2		$	2,516.9		$	1,598.7
Other comprehensive income (loss):
Cash flow hedges:
Commodity derivative instruments:
Changes in fair value of cash flow hedges		81.5			(13.6	)		(13.7	)		(10.2	)
Reclassification of losses (gains) to net income		(2.2	)		39.2			(60.5	)		24.7
Interest rate derivative instruments:
Changes in fair value of cash flow hedges		(5.2	)		3.5			(5.2	)		14.6
Reclassification of losses to net income		9.2			9.4			18.4			19.9
Total cash flow hedges		83.3			38.5			(61.0	)		49.0
Other		–			(0.5	)		(0.6	)		(0.5	)
Total other comprehensive income (loss)		83.3			38.0			(61.6	)		48.5
Comprehensive income		1,319.8			725.2			2,455.3			1,647.2
Comprehensive income attributable to noncontrolling interests		(21.8	)		(13.4	)		(41.7	)		(24.2	)
Comprehensive income attributable to limited partners	$	1,298.0		$	711.8		$	2,413.6		$	1,623.0

See Notes to Unaudited Condensed Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Dollars in millions)

	For the Six Months Ended June 30,
	2019			2018
Operating activities:
Net income	$	2,516.9		$	1,598.7
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		963.1			873.8
Asset impairment and related charges		11.8			16.8
Equity in income of unconsolidated affiliates		(292.0	)		(238.0	)
Distributions received on earnings from unconsolidated affiliates		291.1			227.6
Net gains attributable to asset sales		(2.5	)		(1.4	)
Deferred income tax expense		4.2			10.0
Change in fair market value of derivative instruments		(83.8	)		459.0
Change in fair market value of Liquidity Option Agreement		84.4			16.4
Gain on step acquisition of unconsolidated affiliate (see Note 16)		–			(39.4	)
Net effect of changes in operating accounts (see Note 16)		(332.0	)		(228.5	)
Other operating activities		22.5			2.8
Net cash flows provided by operating activities		3,183.7			2,697.8
Investing activities:
Capital expenditures		(2,260.8	)		(1,921.1	)
Cash used for business combination (see Note 16)		–			(149.7	)
Investments in unconsolidated affiliates		(59.9	)		(45.9	)
Distributions received for return of capital from unconsolidated affiliates		23.4			25.9
Proceeds from asset sales		16.1			2.6
Other investing activities		(5.3	)		(1.4	)
Cash used in investing activities		(2,286.5	)		(2,089.6	)
Financing activities:
Borrowings under debt agreements		40,318.1			38,566.4
Repayments of debt		(39,617.3	)		(37,437.0	)
Debt issuance costs		(0.3	)		(24.3	)
Cash distributions paid to limited partners (see Note 8)		(1,907.9	)		(1,847.3	)
Cash payments made in connection with distribution equivalent rights		(10.5	)		(8.6	)
Cash distributions paid to noncontrolling interests		(46.9	)		(28.3	)
Cash contributions from noncontrolling interests		99.6			206.9
Net cash proceeds from the issuance of common units		82.2			261.0
Repurchase of common units under 2019 Buyback Program (see Note 8)		(81.1	)		–
Other financing activities		(35.9	)		(25.8	)
Cash used in financing activities		(1,200.0	)		(337.0	)
Net change in cash and cash equivalents, including restricted cash		(302.8	)		271.2
Cash and cash equivalents, including restricted cash, at beginning of period		410.1			70.3
Cash and cash equivalents, including restricted cash, at end of period	$	107.3		$	341.5

See Notes to Unaudited Condensed Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2019

(Dollars in millions)

	Partners’ Equity
For the Three Months Ended June 30, 2019:	Limited Partners			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
Balance, March 31, 2019	$	24,151.9		$	(94.0	)	$	463.4		$	24,521.3
Net income		1,214.7			–			21.8			1,236.5
Cash distributions paid to limited partners		(957.5	)		–			–			(957.5	)
Cash payments made in connection with distribution equivalent rights		(6.0	)		–			–			(6.0	)
Cash distributions paid to noncontrolling interests		–			–			(28.9	)		(28.9	)
Cash contributions from noncontrolling interests		–			–			64.8			64.8
Net cash proceeds from the issuance of common units		39.5			–			–			39.5
Repurchase of common units under 2019 Buyback Program (see Note 8)		(29.5	)		–			–			(29.5	)
Amortization of fair value of equity-based awards		38.5			–			–			38.5
Cash flow hedges		–			83.3			–			83.3
Other		(1.1	)		–			14.5			13.4
Balance, June 30, 2019	$	24,450.5		$	(10.7	)	$	535.6		$	24,975.4

	Partners’ Equity
For the Six Months Ended June 30, 2019:	Limited Partners			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
Balance, December 31, 2018	$	23,802.6		$	50.9		$	438.7		$	24,292.2
Net income		2,475.2			–			41.7			2,516.9
Cash distributions paid to limited partners		(1,907.9	)		–			–			(1,907.9	)
Cash payments made in connection with distribution equivalent rights		(10.5	)		–			–			(10.5	)
Cash distributions paid to noncontrolling interests		–			–			(46.9	)		(46.9	)
Cash contributions from noncontrolling interests		–			–			99.6			99.6
Net cash proceeds from the issuance of common units		82.2			–			–			82.2
Common units issued in connection with employee compensation		45.6			–			–			45.6
Repurchase of common units under 2019 Buyback Program		(81.1	)		–			–			(81.1	)
Amortization of fair value of equity-based awards		70.5			–			–			70.5
Cash flow hedges		–			(61.0	)		–			(61.0	)
Other		(26.1	)		(0.6	)		2.5			(24.2	)
Balance, June 30, 2019	$	24,450.5		$	(10.7	)	$	535.6		$	24,975.4

See Notes to Unaudited Condensed Consolidated Financial Statements. For information regarding Unit History,

Accumulated Other Comprehensive Income (Loss) and Noncontrolling Interests, see Note 8.

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ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2018

(Dollars in millions)

	Partners’ Equity
For the Three Months Ended June 30, 2018:	Limited Partners			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
Balance, March 31, 2018	$	22,914.5		$	(161.2	)	$	211.6		$	22,964.9
Net income		673.8			–			13.4			687.2
Cash distributions paid to limited partners		(928.8	)		–			–			(928.8	)
Cash payments made in connection with distribution equivalent rights		(4.7	)		–			–			(4.7	)
Cash distributions paid to noncontrolling interests		–			–			(12.9	)		(12.9	)
Cash contributions from noncontrolling interests		–			–			206.8			206.8
Net cash proceeds from the issuance of common units		84.0			–			–			84.0
Common units issued in connection with land acquisition		30.0			–			–			30.0
Amortization of fair value of equity-based awards		26.6			–			–			26.6
Cash flow hedges		–			38.5			–			38.5
Other		(0.6	)		(0.5	)		–			(1.1	)
Balance, June 30, 2018	$	22,794.8		$	(123.2	)	$	418.9		$	23,090.5

	Partners’ Equity
For the Six Months Ended June 30, 2018:	Limited Partners			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
Balance, December 31, 2017	$	22,718.9		$	(171.7	)	$	225.2		$	22,772.4
Net income		1,574.5			–			24.2			1,598.7
Cash distributions paid to limited partners		(1,847.3	)		–			–			(1,847.3	)
Cash payments made in connection with distribution equivalent rights		(8.6	)		–			–			(8.6	)
Cash distributions paid to noncontrolling interests		–			–			(28.3	)		(28.3	)
Cash contributions from noncontrolling interests		–			–			206.9			206.9
Net cash proceeds from the issuance of common units		261.0			–			–			261.0
Common units issued in connection with employee compensation		39.1			–			–			39.1
Common units issued in connection with land acquisition		30.0			–			–			30.0
Amortization of fair value of equity-based awards		52.6			–			–			52.6
Cash flow hedges		–			49.0			–			49.0
Other		(25.4	)		(0.5	)		(9.1	)		(35.0	)
Balance, June 30, 2018	$	22,794.8		$	(123.2	)	$	418.9		$	23,090.5

See Notes to Unaudited Condensed Consolidated Financial Statements. For information regarding Unit History,

Accumulated Other Comprehensive Income (Loss) and Noncontrolling Interests, see Note 8.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

stated in millions of dollars.

KEY REFERENCES USED IN THESE

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

References to “EPCO” mean Enterprise Products Company, a privately held Texas corporation, and its privately held affiliates. A majority of the outstanding voting capital stock of EPCO is owned by a voting trust, the current trustees (“EPCO Trustees”) of which are: (i) Ms. Duncan Williams, who serves as Chairman of EPCO; (ii) Dr. Cunningham, who serves as Vice Chairman of EPCO; and (iii) Mr. Bachmann, who serves as the President and Chief Executive Officer of EPCO. Ms. Duncan Williams and Mr. Bachmann also currently serve as directors of EPCO along with Mr. Fowler, who is also the Executive Vice President and Chief Financial Officer of EPCO. EPCO, together with its privately held affiliates, owned approximately 31.9% of EPD’s limited partner common units at June 30, 2019.

Note 1. Partnership Organization and Basis of Presentation

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.

We conduct substantially all of our business through EPO and are owned 100% by EPD’s limited partners from an economic perspective. Enterprise GP manages our partnership and owns a non-economic general partner interest in us. We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates under the collective common control of the DD LLC Trustees and the EPCO Trustees. Like many publicly traded partnerships, we have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement (the “ASA”) or by other service providers. See Note 14 for information regarding related party matters.

Our results of operations for the six months ended June 30, 2019 are not necessarily indicative of results expected for the full year of 2019. In our opinion, the accompanying Unaudited Condensed Consolidated Financial Statements include all adjustments consisting of normal recurring accruals necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with United States (“U.S.”) generally accepted accounting principles (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”).

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

These Unaudited Condensed Consolidated Financial Statements and Notes thereto should be read in conjunction with the Audited Consolidated Financial Statements and Notes thereto included in our annual report on Form 10-K for the year ended December 31, 2018 (the “2018 Form 10-K”) filed with the SEC on March 1, 2019.

Note 2. Summary of Significant Accounting Policies

Apart from those matters noted below, there have been no changes in our significant accounting policies since those reported under Note 2 of the 2018 Form 10-K.

Cash, Cash Equivalents and Restricted Cash

The following table provides a reconciliation of cash and cash equivalents, and restricted cash reported within the Unaudited Condensed Consolidated Balance Sheets that sum to the total of the amounts shown in the Unaudited Condensed Statements of Consolidated Cash Flows.

	June 30, 2019		December 31, 2018
Cash and cash equivalents	$	107.3	$	344.8
Restricted cash		–		65.3
Total cash, cash equivalents and restricted cash shown in the Unaudited Condensed Statements of Consolidated Cash Flows	$	107.3	$	410.1

Restricted cash represents amounts held in segregated bank accounts by our clearing brokers as margin in support of our commodity derivative instruments portfolio and related physical purchases and sales of natural gas, NGLs, crude oil and refined products. Additional cash may be restricted to maintain our commodity derivative instruments portfolio as prices fluctuate or margin requirements change. See Note 13 for information regarding our derivative instruments and hedging activities.

Recent Accounting Developments

Lease accounting standard

In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Codification (“ASC”) 842, Leases, which requires substantially all leases be recorded on the balance sheet. We adopted the new standard on January 1, 2019 and applied it to (i) all new leases entered into after January 1, 2019 and (ii) all existing lease contracts as of January 1, 2019. ASC 842 supersedes existing lease accounting guidance found under ASC 840, Leases.

The new standard introduces two lessee accounting models, which result in a lease being classified as either a “finance” or “operating” lease based on whether the lessee effectively obtains control of the underlying asset during the lease term. A lease would be classified as a finance lease if it meets one of five classification criteria, four of which are generally consistent with ASC 840 lease accounting guidance. By default, a lease that does not meet the criteria to be classified as a finance lease will be deemed an operating lease. Regardless of classification, the initial measurement of both lease types will result in the balance sheet recognition of a right-of-use (“ROU”) asset (representing a company’s right to use the underlying asset for a specified period of time) and a corresponding lease liability. The lease liability will be recognized at the present value of the future lease payments, and the ROU asset will equal the lease liability adjusted for any prepaid rent, lease incentives provided by the lessor, and any indirect costs.

The subsequent measurement of each type of lease varies. For finance leases, a lessee will amortize the ROU asset (generally on a straight-line basis in a manner similar to depreciation) and accrete the lease liability (as a component of interest expense) using the effective interest method. Operating leases will result in the recognition of a single lease expense amount that is recorded on a straight-line basis.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

ASC 842 resulted in changes to the way our operating leases are recorded, presented and disclosed in our consolidated financial statements. Upon adoption of ASC 842 on January 1, 2019, we recognized a ROU asset and a corresponding lease liability based on the present value of then existing long-term operating lease obligations. In addition, we elected to apply several practical expedients and made accounting policy elections upon adoption of ASC 842 including:

•

We will not recognize ROU assets and lease liabilities for short-term leases and instead record them in a manner similar to operating leases under legacy lease accounting guidelines. A short term lease is one with a maximum lease term of 12 months or less and does not include a purchase option the lessee is reasonably certain to exercise.

•

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

•

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

•

We will combine lease and nonlease components relating to our office and warehouse leases, as applicable.

See Note 15 regarding our new disclosures regarding operating lease obligations.

Note 3. Inventories

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

	June 30, 2019		December 31, 2018
NGLs	$	824.4	$	647.7
Petrochemicals and refined products		210.1		264.7
Crude oil		540.3		593.4
Natural gas		11.3		16.3
Total	$	1,586.1	$	1,522.1

Due to fluctuating commodity prices, we recognize lower of cost or net realizable value adjustments when the carrying value of our available-for-sale inventories exceeds their net realizable value. The following table presents our total cost of sales amounts and lower of cost or net realizable value adjustments for the periods indicated:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
Cost of sales (1)		$	5,609.4		$	6,391.9		$	11,445.0		$	13,532.3
Lower of cost or net realizable value adjustments recognized within cost of sales			4.9			0.7			10.3			2.6

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

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 4. Property, Plant and Equipment

The historical costs of our property, plant and equipment and related accumulated depreciation balances were as follows at the dates indicated:

	Estimated Useful Life in Years			June 30, 2019		December 31, 2018
Plants, pipelines and facilities (1)		3-45	(5)	$	44,578.5	$	42,371.0
Underground and other storage facilities (2)		5-40	(6)		3,700.2		3,624.2
Transportation equipment (3)		3-10			195.0		187.1
Marine vessels (4)		15-30			877.2		828.6
Land					365.1		359.5
Construction in progress					3,230.6		3,526.8
Total					52,946.6		50,897.2
Less accumulated depreciation					12,857.5		12,159.6
Property, plant and equipment, net				$	40,089.1	$	38,737.6

(1)	Plants, pipelines and facilities include processing plants; NGL, natural gas, crude oil and petrochemical and refined products pipelines; terminal loading and unloading facilities; buildings; office furniture and equipment; laboratory and shop equipment and related assets.
(2)	Underground and other storage facilities include underground product storage caverns; above ground storage tanks; water wells and related assets.
(3)	Transportation equipment includes tractor-trailer tank trucks and other vehicles and similar assets used in our operations.
(4)	Marine vessels include tow boats, barges and related equipment used in our marine transportation business.
(5)	In general, the estimated useful lives of major assets within this category are: processing plants, 20-35 years; pipelines and related equipment, 5-45 years; terminal facilities, 10-35 years; buildings, 20-40 years; office furniture and equipment, 3-20 years; and laboratory and shop equipment, 5-35 years.
(6)	In general, the estimated useful lives of assets within this category are: underground storage facilities, 5-35 years; storage tanks, 10-40 years; and water wells, 5-35 years.

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

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
Depreciation expense (1)		$	389.3		$	361.0		$	769.9		$	692.8
Capitalized interest (2)			32.8			27.1			69.0			85.3

(1)

Depreciation expense is a component of “Costs and expenses” as presented on our Unaudited Condensed Statements of Consolidated Operations.

(2)

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

Asset Retirement Obligations

Property, plant and equipment at June 30, 2019 and December 31, 2018 includes $67.1 million and $72.5 million, respectively, of asset retirement costs capitalized as an increase in the associated long-lived asset. The following table presents information regarding our asset retirement obligations, or AROs, since December 31, 2018:

ARO liability balance, December 31, 2018	$	126.3
Liabilities incurred		0.7
Liabilities settled		(0.3	)
Revisions in estimated cash flows		(4.8	)
Accretion expense		4.0
ARO liability balance, June 30, 2019	$	125.9

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 5. Investments in Unconsolidated Affiliates

The following table presents our investments in unconsolidated affiliates by business segment at the dates indicated. We account for these investments using the equity method.

	June 30, 2019		December 31, 2018
NGL Pipelines & Services	$	686.7	$	662.0
Crude Oil Pipelines & Services		1,881.9		1,867.5
Natural Gas Pipelines & Services		24.0		22.8
Petrochemical & Refined Products Services		59.5		62.8
Total	$	2,652.1	$	2,615.1

The following table presents our equity in income (loss) of unconsolidated affiliates by business segment for the periods indicated:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
NGL Pipelines & Services	$	26.7		$	39.4		$	56.8		$	58.8
Crude Oil Pipelines & Services		111.0			83.5			235.6			181.4
Natural Gas Pipelines & Services		1.6			1.6			3.3			2.6
Petrochemical & Refined Products Services		(1.9	)		(2.2	)		(3.7	)		(4.8	)
Total	$	137.4		$	122.3		$	292.0		$	238.0

Combined results of operations data for the periods indicated for our unconsolidated affiliates are summarized in the following table (all data presented on a 100% basis):

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2019		2018		2019		2018
Income Statement Data:
Revenues	$	497.9	$	461.3	$	1,014.4	$	857.3
Operating income		299.3		288.1		637.8		531.8
Net income		298.8		286.4		636.4		528.7

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 6. Intangible Assets and Goodwill

Identifiable Intangible Assets

The following table summarizes our intangible assets by business segment at the dates indicated:

	June 30, 2019							December 31, 2018
	Gross Value		Accumulated Amortization			Carrying Value		Gross Value		Accumulated Amortization			Carrying Value
NGL Pipelines & Services:
Customer relationship intangibles	$	447.8	$	(199.3	)	$	248.5	$	457.3	$	(201.9	)	$	255.4
Contract-based intangibles		375.4		(249.9	)		125.5		363.4		(238.7	)		124.7
Segment total		823.2		(449.2	)		374.0		820.7		(440.6	)		380.1
Crude Oil Pipelines & Services:
Customer relationship intangibles		2,203.5		(207.7	)		1,995.8		2,203.5		(174.1	)		2,029.4
Contract-based intangibles		276.9		(224.2	)		52.7		276.9		(211.7	)		65.2
Segment total		2,480.4		(431.9	)		2,048.5		2,480.4		(385.8	)		2,094.6
Natural Gas Pipelines & Services:
Customer relationship intangibles		1,350.3		(464.9	)		885.4		1,350.3		(447.8	)		902.5
Contract-based intangibles		466.4		(391.7	)		74.7		464.7		(387.9	)		76.8
Segment total		1,816.7		(856.6	)		960.1		1,815.0		(835.7	)		979.3
Petrochemical & Refined Products Services:
Customer relationship intangibles		181.4		(54.8	)		126.6		181.4		(51.8	)		129.6
Contract-based intangibles		46.0		(22.6	)		23.4		46.0		(21.2	)		24.8
Segment total		227.4		(77.4	)		150.0		227.4		(73.0	)		154.4
Total intangible assets	$	5,347.7	$	(1,815.1	)	$	3,532.6	$	5,343.5	$	(1,735.1	)	$	3,608.4

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

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2019		2018		2019		2018
NGL Pipelines & Services	$	9.0	$	9.3	$	18.1	$	16.4
Crude Oil Pipelines & Services		24.1		22.6		46.1		46.6
Natural Gas Pipelines & Services		10.0		9.6		20.9		19.3
Petrochemical & Refined Products Services		2.2		2.1		4.4		4.4
Total	$	45.3	$	43.6	$	89.5	$	86.7

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

Remainder of 2019				2020				2021				2022				2023
$	82.1			$	160.5			$	162.8			$	168.4			$	168.5

Goodwill

Goodwill represents the excess of the purchase price of an acquired business over the amounts assigned to assets acquired and liabilities assumed in the transaction. There has been no change in our goodwill amounts since those reported in our 2018 Form 10-K.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 7. Debt Obligations

The following table presents our consolidated debt obligations (arranged by company and maturity date) at the dates indicated:

	June 30, 2019			December 31, 2018
EPO senior debt obligations:
Commercial Paper Notes, variable-rates (1)	$	1,425.0		$	–
Senior Notes N, 6.50% fixed-rate, due January 2019		–			700.0
364-Day Revolving Credit Agreement, variable-rate, due September 2019		–			–
Senior Notes LL, 2.55% fixed-rate, due October 2019 (1)		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			750.0
Senior Notes RR, 2.85% fixed-rate, due April 2021		575.0			575.0
Senior Notes VV, 3.50% fixed-rate, due February 2022		750.0			750.0
Senior Notes CC, 4.05% fixed-rate, due February 2022		650.0			650.0
Multi-Year Revolving Credit Facility, variable-rate, due September 2022		–			–
Senior Notes HH, 3.35% fixed-rate, due March 2023		1,250.0			1,250.0
Senior Notes JJ, 3.90% fixed-rate, due February 2024		850.0			850.0
Senior Notes MM, 3.75% fixed-rate, due February 2025		1,150.0			1,150.0
Senior Notes PP, 3.70% fixed-rate, due February 2026		875.0			875.0
Senior Notes SS, 3.95% fixed-rate, due February 2027		575.0			575.0
Senior Notes WW, 4.15% fixed-rate, due October 2028		1,000.0			1,000.0
Senior Notes D, 6.875% fixed-rate, due March 2033		500.0			500.0
Senior Notes H, 6.65% fixed-rate, due October 2034		350.0			350.0
Senior Notes J, 5.75% fixed-rate, due March 2035		250.0			250.0
Senior Notes W, 7.55% fixed-rate, due April 2038		399.6			399.6
Senior Notes R, 6.125% fixed-rate, due October 2039		600.0			600.0
Senior Notes Z, 6.45% fixed-rate, due September 2040		600.0			600.0
Senior Notes BB, 5.95% fixed-rate, due February 2041		750.0			750.0
Senior Notes DD, 5.70% fixed-rate, due February 2042		600.0			600.0
Senior Notes EE, 4.85% fixed-rate, due August 2042		750.0			750.0
Senior Notes GG, 4.45% fixed-rate, due February 2043		1,100.0			1,100.0
Senior Notes II, 4.85% fixed-rate, due March 2044		1,400.0			1,400.0
Senior Notes KK, 5.10% fixed-rate, due February 2045		1,150.0			1,150.0
Senior Notes QQ, 4.90% fixed-rate, due May 2046		975.0			975.0
Senior Notes UU, 4.25% fixed-rate, due February 2048		1,250.0			1,250.0
Senior Notes XX, 4.80% fixed-rate, due February 2049		1,250.0			1,250.0
Senior Notes NN, 4.95% fixed-rate, due October 2054		400.0			400.0
TEPPCO senior debt obligations:
TEPPCO Senior Notes, 7.55% fixed-rate, due April 2038		0.4			0.4
Total principal amount of senior debt obligations		24,475.0			23,750.0
EPO Junior Subordinated Notes C, variable-rate, due June 2067 (2)		232.2			256.4
EPO Junior Subordinated Notes D, fixed/variable-rate, due August 2077 (3)		700.0			700.0
EPO Junior Subordinated Notes E, fixed/variable-rate, due August 2077 (4)		1,000.0			1,000.0
EPO Junior Subordinated Notes F, fixed/variable-rate, due February 2078 (5)		700.0			700.0
TEPPCO Junior Subordinated Notes, variable-rate, due June 2067 (2)		14.2			14.2
Total principal amount of senior and junior debt obligations		27,121.4			26,420.6
Other, non-principal amounts		(236.4	)		(242.4	)
Less current maturities of debt (1)		(500.0	)		(1,500.1	)
Total long-term debt	$	26,385.0		$	24,678.1

(1)	In accordance with ASC 470, Debt, long-term and current maturities of debt reflect the classification of such obligations at June 30, 2019 after taking into consideration EPO's issuance of senior notes in July 2019.
(2)	Variable rate is reset quarterly and based on 3-month LIBOR, or London Inter-Bank Offered Rate, plus 2.778%. During the second quarter of 2019, EPO repurchased and retired $24.2 million in principal amount of these junior subordinated notes.
(3)	Fixed rate of 4.875% through August 15, 2022; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 2.986%.
(4)	Fixed rate of 5.250% through August 15, 2027; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 3.033%.
(5)	Fixed rate of 5.375% through February 14, 2028; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 2.57%.

References to “TEPPCO” mean TEPPCO Partners, L.P. prior to its merger with one of our wholly owned subsidiaries in October 2009.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table presents the range of interest rates and weighted-average interest rates paid on our consolidated variable-rate debt during the six months ended June 30, 2019:

	Range of Interest Rates Paid	Weighted-Average Interest Rate Paid
Commercial Paper Notes	2.59% to 2.80%	2.72%
EPO Junior Subordinated Notes C and TEPPCO Junior Subordinated Notes	5.30% to 5.52%	5.42%

Amounts borrowed under our 364-Day and Multi-Year Revolving Credit Facilities bear interest, at our election, equal to: (i) LIBOR, plus an additional variable spread; or (ii) an alternate base rate, which is the greater of (a) the Prime Rate in effect on such day, (b) the Federal Funds Effective Rate in effect on such day plus 0.5%, or (c) the LIBO Market Index Rate in effect on such day plus 1% and a variable spread. The applicable spreads are determined based on our debt ratings.

Issuance of $2.5 Billion of Senior Notes in July 2019

In July 2019, EPO issued $2.5 billion aggregate principal amount of senior notes comprised of $1.25 billion principal amount of senior notes due July 2029 (“Senior Notes YY”) and $1.25 billion principal amount of senior notes due January 2050 (“Senior Notes ZZ”). Net proceeds from this offering were used by EPO for (i) the repayment of debt, including the temporary repayment of amounts outstanding under its commercial paper program and the future payment of $800 million principal amount of its Senior Notes LL due October 2019 at their maturity, and (ii) for general company purposes, including for growth capital expenditures.

After taking into account EPO’s issuance of Senior Notes YY and Senior Notes ZZ in July 2019 and the expected use of net proceeds, the following table presents the scheduled contractual maturities of principal amounts of our consolidated debt obligations for the next five years and in total thereafter:

			Scheduled Maturities of Debt
	Total		Remainder of 2019		2020		2021		2022		2023		Thereafter
Principal amount of senior and junior debt obligations at June 30, 2019	$	27,121.4	$	–	$	1,500.0	$	1,325.0	$	1,400.0	$	1,250.0	$	21,646.4

Parent-Subsidiary Guarantor Relationships

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

Partial Retirement of Junior Subordinated Notes During Second Quarter of 2019

During the second quarter of 2019, EPO repurchased and retired $24.2 million in principal amount of its Junior Subordinated Notes C. A $1.5 million gain on the extinguishment of these debt obligations is included in “Other, net” on our Unaudited Condensed Statements of Consolidated Operations.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Lender Financial Covenants

We were in compliance with the financial covenants of our consolidated debt agreements at June 30, 2019.

Letters of Credit

At June 30, 2019, EPO had $101.4 million of letters of credit outstanding primarily related to our commodity hedging activities.

Note 8. Equity and Distributions

Limited Partner Common Units Outstanding

The following table summarizes changes in the number of EPD limited partner common units outstanding since December 31, 2018:

Common units outstanding at December 31, 2018	2,184,869,029
Common unit repurchases under 2019 Buyback Program	(1,852,392	)
Common units issued in connection with DRIP and EUPP	1,516,779
Common units issued in connection with employee compensation	1,626,041
Common units issued in connection with the vesting of phantom unit awards, net	2,379,620
Other	21,595
Common units outstanding at March 31, 2019	2,188,560,672
Common unit repurchases under 2019 Buyback Program	(1,056,736	)
Common units issued in connection with DRIP and EUPP	1,381,211
Common units issued in connection with the vesting of phantom unit awards, net	120,831
Common units outstanding at June 30, 2019	2,189,005,978

We have a universal shelf registration statement (the “2019 Shelf”) on file with the SEC which allows EPD and EPO (each on a standalone basis) to issue an unlimited amount of equity and debt securities, respectively. The 2019 Shelf replaced our prior universal shelf registration statement, which expired in May 2019.

In addition, EPD has a registration statement on file with the SEC covering the issuance of up to $2.54 billion of its common units in amounts, at prices and on terms to be determined by market conditions and other factors at the time of such offerings in connection with its at-the-market (“ATM”) program. During the six months ended June 30, 2019 and 2018, EPD did not issue any common units under its ATM program. After taking into account the aggregate sales price of common units sold under the ATM program through June 30, 2019, EPD has the capacity to issue additional common units under its ATM program up to an aggregate sales price of $2.54 billion.

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

Common unit repurchases under 2019 Buyback Program

In January 2019, we announced that the Board of Enterprise GP had approved a $2.0 billion multi-year unit buyback program (the “2019 Buyback Program”), which provides EPD with an additional method to return capital to investors. The 2019 Buyback Program authorizes EPD to repurchase its common units from time to time, including through open market purchases and negotiated transactions. The timing and pace of buy backs under the program will be determined by a number of factors including (i) our financial performance and flexibility, (ii) organic growth and acquisition opportunities with higher potential returns on investment, (iii) EPD’s unit price and implied cash flow yield and (iv) maintaining targeted financial leverage with a debt-to-normalized adjusted EBITDA, or earnings before interest, taxes, depreciation and amortization, ratio in the 3.5 times area. No time limit has been set for completion of the program, and it may be suspended or discontinued at any time.

EPD repurchased 2,909,128 common units under the 2019 Buyback Program through open market purchases during the six months ended June 30, 2019. The total purchase price of these repurchases was $81.1 million, excluding commissions and fees. The repurchased units were cancelled immediately upon acquisition. At June 30, 2019, the remaining available capacity under the 2019 Buyback Program was $1.92 billion.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Common units issued in connection with DRIP and EUPP

EPD has registration statements on file with the SEC in connection with its distribution reinvestment plan (“DRIP”) and employee unit purchase plan (“EUPP”). EPD issued and delivered a total of 2,601,727 new common units under the DRIP during the six months ended June 30, 2019, which generated net cash proceeds of $73.7 million. During the six months ended June 30, 2018, EPD issued and delivered 9,608,839 new common units under the DRIP, which generated net cash proceeds of $253.7 million. After taking into account the number of common units delivered under the DRIP through June 30, 2019, EPD has the capacity to deliver an additional 58,798,632 common units under this plan. The period-to-period decrease in net cash proceeds from the DRIP is primarily due to lower reinvestments by privately held affiliates of EPCO in 2019 and a reduction in the discount applicable to common unit purchases made under the DRIP from 2.5% to 0% beginning with the distribution paid in February 2019.

EPD issued and delivered 296,263 new common units under the EUPP during the six months ended June 30, 2019, which generated net cash proceeds of $8.5 million. During the six months ended June 30, 2018, EPD issued and delivered 268,251 new common units under its EUPP, which generated net cash proceeds of $7.3 million. After taking into account the number of common units delivered under the EUPP through June 30, 2019, EPD may deliver an additional 4,919,378 common units under this plan.

Net cash proceeds from the issuance of new common units under the DRIP and EUPP during the six months ended June 30, 2019 were used to temporarily reduce amounts outstanding under EPO’s commercial paper program and for general company purposes, including for growth capital expenditures.

In July 2019, EPD announced that, beginning with the quarterly distribution payment to be made in August 2019, it has elected to use common units purchased on the open market, rather than issuing new common units, to satisfy its delivery obligations under the DRIP and EUPP. This election is subject to change in future quarters depending on the partnership’s need for equity capital.

Common Units Issued in Connection With Employee Compensation

In February 2019, certain employees of EPCO received discretionary bonus payments, less any retirement plan deductions and applicable withholding taxes, for work performed on our behalf during the prior fiscal year (e.g., the February 2019 bonus amount was applicable to the year ended December 31, 2018). The net dollar value of the bonus amounts was remitted through the issuance of an equivalent value of newly issued EPD common units under EPCO’s 2008 Enterprise Products Long-Term Incentive Plan (Third Amendment and Restatement) (“2008 Plan”). In February 2019, EPD issued 1,626,041 common units, which had a value of $45.6 million, in connection with the employee bonus awards. The compensation expense associated with each bonus award was recognized during the year in which the work was performed.

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

During the six months ended June 30, 2019, after taking into account tax withholding requirements, EPD issued a net 2,500,451 new common units to employees in connection with the vesting of phantom unit awards. See Note 12 for information regarding our phantom unit awards.

Accumulated Other Comprehensive Income (Loss)

The following tables present the components of accumulated other comprehensive income (loss) as reported on our Unaudited Condensed Consolidated Balance Sheets at the dates indicated:

	Cash Flow Hedges
	Commodity Derivative Instruments			Interest Rate Derivative Instruments			Other			Total
Accumulated Other Comprehensive Income (Loss), December 31, 2018	$	152.7		$	(104.8	)	$	3.0		$	50.9
Other comprehensive income (loss) for period, before reclassifications		(13.7	)		(5.2	)		(0.6	)		(19.5	)
Reclassification of losses (gains) to net income during period		(60.5	)		18.4			–			(42.1	)
Total other comprehensive income (loss) for period		(74.2	)		13.2			(0.6	)		(61.6	)
Accumulated Other Comprehensive Income (Loss), June 30, 2019	$	78.5		$	(91.6	)	$	2.4		$	(10.7	)

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	Cash Flow Hedges
	Commodity Derivative Instruments			Interest Rate Derivative Instruments			Other			Total
Accumulated Other Comprehensive Income (Loss), December 31, 2017	$	(10.1	)	$	(165.1	)	$	3.5		$	(171.7	)
Other comprehensive income (loss) for period, before reclassifications		(10.2	)		14.6			(0.5	)		3.9
Reclassification of losses (gains) to net income during period		24.7			19.9			–			44.6
Total other comprehensive income (loss) for period		14.5			34.5			(0.5	)		48.5
Accumulated Other Comprehensive Income (Loss), June 30, 2018	$	4.4		$	(130.6	)	$	3.0		$	(123.2	)

The following table presents reclassifications of (income) loss out of accumulated other comprehensive income into net income during the periods indicated:

		For the Three Months Ended June 30,						For the Six Months Ended June 30,
Losses (gains) on cash flow hedges:	Location	2019			2018			2019			2018
Interest rate derivatives	Interest expense	$	9.2		$	9.4		$	18.4		$	19.9
Commodity derivatives	Revenue		(2.5	)		39.4			(67.8	)		25.4
Commodity derivatives	Operating costs and expenses		0.3			(0.2	)		7.3			(0.7	)
Total		$	7.0		$	48.6		$	(42.1	)	$	44.6

For information regarding our interest rate and commodity derivative instruments, see Note 13.

Noncontrolling Interests

In June 2019, an affiliate of American Midstream, LP acquired a noncontrolling 25% equity interest in our consolidated subsidiary that owns the Pascagoula natural gas processing plant for $36.0 million in cash.

Cash Distributions

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

On July 9, 2019, EPD announced that the Board declared a cash distribution of $0.4400 per common unit with respect to the second quarter of 2019, which represents a 2.3% increase over the $0.4300 per common unit EPD declared and paid with respect to the second quarter of 2018. The distribution with respect to the second quarter of 2019 will be paid on August 13, 2019 to unitholders of record as of the close of business on July 31, 2019.

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Note 9. Revenues

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

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2019		2018		2019		2018
NGL Pipelines & Services:
Sales of NGLs and related products	$	2,659.4	$	2,610.9	$	5,330.6	$	5,426.3
Segment midstream services:
Natural gas processing and fractionation		288.2		332.6		557.7		585.0
Transportation		243.9		228.3		519.2		483.7
Storage and terminals		93.2		101.9		191.6		192.0
Total segment midstream services		625.3		662.8		1,268.5		1,260.7
Total NGL Pipelines & Services		3,284.7		3,273.7		6,599.1		6,687.0
Crude Oil Pipelines & Services:
Sales of crude oil		2,531.7		2,532.2		4,860.1		5,873.9
Segment midstream services:
Transportation		205.3		161.1		389.0		302.8
Storage and terminals		129.6		87.9		224.8		175.4
Total segment midstream services		334.9		249.0		613.8		478.2
Total Crude Oil Pipelines & Services		2,866.6		2,781.2		5,473.9		6,352.1
Natural Gas Pipelines & Services:
Sales of natural gas		531.4		532.5		1,187.1		1,092.5
Segment midstream services:
Transportation		287.9		260.3		559.7		505.1
Total segment midstream services		287.9		260.3		559.7		505.1
Total Natural Gas Pipelines & Services		819.3		792.8		1,746.8		1,597.6
Petrochemical & Refined Products Services:
Sales of petrochemicals and refined products		1,087.7		1,413.4		2,568.3		2,702.7
Segment midstream services:
Fractionation and isomerization		41.5		45.2		82.3		100.9
Transportation, including marine logistics		132.2		114.2		258.8		233.8
Storage and terminals		44.3		47.0		90.6		91.9
Total segment midstream services		218.0		206.4		431.7		426.6
Total Petrochemical & Refined Products Services		1,305.7		1,619.8		3,000.0		3,129.3
Total consolidated revenues	$	8,276.3	$	8,467.5	$	16,819.8	$	17,766.0

Substantially all of our revenues are derived from contracts with customers. In total, product sales and midstream services accounted for 82% and 18%, respectively, of our consolidated revenues for the three months ended June 30, 2019. During the six months ended June 30, 2019, product sales and midstream services accounted for 83% and 17%, respectively, of our consolidated revenues. During the three months ended June 30, 2018, product sales and midstream services accounted for 84% and 16%, respectively, of our consolidated revenues. During the six months ended June 30, 2018, product sales and midstream services accounted for 85% and 15%, respectively, of our consolidated revenues.

Unbilled Revenue and Deferred Revenue

The following table provides information regarding our contract assets and contract liabilities at June 30, 2019:

Contract Asset	Location	Balance
Unbilled revenue (current amount)	Prepaid and other current assets	$	160.9
Total		$	160.9

Contract Liability	Location	Balance
Deferred revenue (current amount)	Other current liabilities	$	111.7
Deferred revenue (noncurrent)	Other long-term liabilities		198.8
Total		$	310.5

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The following table presents significant changes in our unbilled revenue and deferred revenue balances during the six months ended June 30, 2019:

	Unbilled Revenue			Deferred Revenue
Balance at December 31, 2018	$	13.3		$	291.2
Amount included in opening balance transferred to other accounts during period (1)		(3.4	)		(83.2	)
Amount recorded during period		169.3			277.0
Amounts recorded during period transferred to other accounts (1)		(18.3	)		(172.6	)
Other changes		–			(1.9	)
Balance at June 30, 2019	$	160.9		$	310.5

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

Remaining Performance Obligations

The following table presents estimated fixed future consideration from contracts with customers as of June 30, 2019 that contain minimum volume commitments, deficiency and similar fees, and contract terms exceeding one year.

Remainder of 2019				2020				2021				2022				2023				Thereafter				Total
$	1,910.5			$	3,436.4			$	2,925.1			$	2,404.1			$	1,990.1			$	8,528.7			$	21,194.9

Note 10. Business Segments and Related Information

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.

Segment Gross Operating Margin

We evaluate segment performance based on our financial measure of gross operating margin. Gross operating margin is an important performance measure of the core profitability of our operations and forms the basis of our internal financial reporting. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results. Gross operating margin is exclusive of other income and expense transactions, income taxes, the cumulative effect of changes in accounting principles and extraordinary charges. Gross operating margin is presented on a 100% basis before any allocation of earnings to noncontrolling interests.

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The following table presents our measurement of total segment gross operating margin for the periods presented. The financial measure most directly comparable to total segment gross operating margin is operating income.

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
Operating income	$	1,560.3		$	986.4		$	3,186.5		$	2,124.9
Adjustments to reconcile operating income to total segment gross operating margin (addition or subtraction indicated by sign):
Depreciation, amortization and accretion expense in operating costs and expenses		462.8			425.3			913.7			819.6
Asset impairment and related charges in operating costs and expenses		7.0			15.9			11.8			16.8
Net gains attributable to asset sales in operating costs and expenses		(2.1	)		(0.9	)		(2.5	)		(1.4	)
General and administrative costs		52.5			51.4			104.7			104.4
Non-refundable payments received from shippers attributable to make-up rights (1)		11.3			5.6			13.5			8.3
Subsequent recognition of revenues attributable to make-up rights (2)		(5.6	)		(22.0	)		(13.1	)		(36.2	)
Total segment gross operating margin	$	2,086.2		$	1,461.7		$	4,214.6		$	3,036.4

(1)	Since make-up rights entail a future performance obligation by the pipeline to the shipper, these receipts are recorded as deferred revenue for GAAP purposes; however, these receipts are included in gross operating margin in the period of receipt since they are nonrefundable to the shipper.
(2)	As deferred revenues attributable to make-up rights are subsequently recognized as revenue under GAAP, gross operating margin must be adjusted to remove such amounts to prevent duplication since the associated non-refundable payments were previously included in gross operating margin.

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

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2019		2018		2019		2018
Gross operating margin by segment:
NGL Pipelines & Services	$	966.3	$	913.7	$	1,925.5	$	1,798.6
Crude Oil Pipelines & Services		513.2		52.8		1,175.5		272.8
Natural Gas Pipelines & Services		301.8		213.4		566.1		411.3
Petrochemical & Refined Products Services		304.9		281.8		547.5		553.7
Total segment gross operating margin	$	2,086.2	$	1,461.7	$	4,214.6	$	3,036.4

The following table summarizes the non-cash mark-to-market gains (losses) included in gross operating margin and interest expense for the periods indicated:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
Mark-to-market gains (losses) in gross operating margin:
NGL Pipelines & Services	$	(0.7	)	$	11.2		$	0.6		$	7.8
Crude Oil Pipelines & Services		(14.6	)		(338.0	)		85.2			(467.6	)
Natural Gas Pipelines & Services		0.3			3.4			–			1.2
Petrochemical & Refined Products Services		2.5			1.3			(2.0	)		(0.3	)
Total mark-to-market impact on gross operating margin		(12.5	)		(322.1	)		83.8			(458.9	)
Mark-to-market loss in interest expense		–			–			–			(0.1	)
Total	$	(12.5	)	$	(322.1	)	$	83.8		$	(459.0	)

For information regarding our hedging activities, see Note 13.

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Summarized Segment Financial Information

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

	Reportable Business Segments
	NGL Pipelines & Services		Crude Oil Pipelines & Services		Natural Gas Pipelines & Services		Petrochemical & Refined Products Services			Adjustments and Eliminations			Consolidated Total
Revenues from third parties:
Three months ended June 30, 2019	$	3,282.2	$	2,847.0	$	815.6	$	1,305.7		$	–		$	8,250.5
Three months ended June 30, 2018		3,268.8		2,733.8		789.5		1,619.8			–			8,411.9
Six months ended June 30, 2019		6,593.8		5,448.6		1,739.3		3,000.0			–			16,781.7
Six months ended June 30, 2018		6,678.4		6,286.5		1,591.5		3,129.3			–			17,685.7
Revenues from related parties:
Three months ended June 30, 2019		2.5		19.6		3.7		–			–			25.8
Three months ended June 30, 2018		4.9		47.4		3.3		–			–			55.6
Six months ended June 30, 2019		5.3		25.3		7.5		–			–			38.1
Six months ended June 30, 2018		8.6		65.6		6.1		–			–			80.3
Intersegment and intrasegment revenues:
Three months ended June 30, 2019		4,494.8		9,453.3		163.1		617.9			(14,729.1	)		–
Three months ended June 30, 2018		6,004.6		9,978.5		165.0		784.0			(16,932.1	)		–
Six months ended June 30, 2019		9,986.2		17,338.3		358.5		1,332.3			(29,015.3	)		–
Six months ended June 30, 2018		12,569.5		21,404.8		335.9		1,397.3			(35,707.5	)		–
Total revenues:
Three months ended June 30, 2019		7,779.5		12,319.9		982.4		1,923.6			(14,729.1	)		8,276.3
Three months ended June 30, 2018		9,278.3		12,759.7		957.8		2,403.8			(16,932.1	)		8,467.5
Six months ended June 30, 2019		16,585.3		22,812.2		2,105.3		4,332.3			(29,015.3	)		16,819.8
Six months ended June 30, 2018		19,256.5		27,756.9		1,933.5		4,526.6			(35,707.5	)		17,766.0
Equity in income (loss) of unconsolidated affiliates:
Three months ended June 30, 2019		26.7		111.0		1.6		(1.9	)		–			137.4
Three months ended June 30, 2018		39.4		83.5		1.6		(2.2	)		–			122.3
Six months ended June 30, 2019		56.8		235.6		3.3		(3.7	)		–			292.0
Six months ended June 30, 2018		58.8		181.4		2.6		(4.8	)		–			238.0

Segment revenues include intersegment and intrasegment transactions, which are generally based on transactions made at market-based rates. Our consolidated revenues reflect the elimination of intercompany transactions. Substantially all of our consolidated revenues are earned in the U.S. and derived from a wide customer base.

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

	Reportable Business Segments
	NGL Pipelines & Services		Crude Oil Pipelines & Services		Natural Gas Pipelines & Services		Petrochemical & Refined Products Services		Adjustments and Eliminations		Consolidated Total
Property, plant and equipment, net: (see Note 4)
At June 30, 2019	$	16,109.6	$	6,293.5	$	8,275.8	$	6,179.6	$	3,230.6	$	40,089.1
At December 31, 2018		14,845.4		5,847.7		8,303.8		6,213.9		3,526.8		38,737.6
Investments in unconsolidated affiliates: (see Note 5)
At June 30, 2019		686.7		1,881.9		24.0		59.5		–		2,652.1
At December 31, 2018		662.0		1,867.5		22.8		62.8		–		2,615.1
Intangible assets, net: (see Note 6)
At June 30, 2019		374.0		2,048.5		960.1		150.0		–		3,532.6
At December 31, 2018		380.1		2,094.6		979.3		154.4		–		3,608.4
Goodwill: (see Note 6)
At June 30, 2019		2,651.7		1,841.0		296.3		956.2		–		5,745.2
At December 31, 2018		2,651.7		1,841.0		296.3		956.2		–		5,745.2
Segment assets:
At June 30, 2019		19,822.0		12,064.9		9,556.2		7,345.3		3,230.6		52,019.0
At December 31, 2018		18,539.2		11,650.8		9,602.2		7,387.3		3,526.8		50,706.3

Supplemental Revenue and Expense Information

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

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
Consolidated revenues:
NGL Pipelines & Services	$	3,284.7		$	3,273.7		$	6,599.1		$	6,687.0
Crude Oil Pipelines & Services		2,866.6			2,781.2			5,473.9			6,352.1
Natural Gas Pipelines & Services		819.3			792.8			1,746.8			1,597.6
Petrochemical & Refined Products Services		1,305.7			1,619.8			3,000.0			3,129.3
Total consolidated revenues	$	8,276.3		$	8,467.5		$	16,819.8		$	17,766.0

Consolidated costs and expenses
Operating costs and expenses:
Cost of sales	$	5,609.4		$	6,391.9		$	11,445.0		$	13,532.3
Other operating costs and expenses (1)		723.8			719.8			1,452.6			1,407.4
Depreciation, amortization and accretion		462.8			425.3			913.7			819.6
Asset impairment and related charges		7.0			15.9			11.8			16.8
Net gains attributable to asset sales		(2.1	)		(0.9	)		(2.5	)		(1.4	)
General and administrative costs		52.5			51.4			104.7			104.4
Total consolidated costs and expenses	$	6,853.4		$	7,603.4		$	13,925.3		$	15,879.1

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

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

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Note 11. Earnings Per Unit

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

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
BASIC EARNINGS PER UNIT
Net income attributable to limited partners	$	1,214.7		$	673.8		$	2,475.2		$	1,574.5
Undistributed earnings allocated and cash payments on phantom unit awards (1)		(7.4	)		(4.6	)		(15.2	)		(9.3	)
Net income available to common unitholders	$	1,207.3		$	669.2		$	2,460.0		$	1,565.2

Basic weighted-average number of common units outstanding		2,189.1			2,174.6			2,188.1			2,170.7

Basic earnings per unit	$	0.55		$	0.31		$	1.12		$	0.72

DILUTED EARNINGS PER UNIT
Net income attributable to limited partners	$	1,214.7		$	673.8		$	2,475.2		$	1,574.5

Diluted weighted-average number of units outstanding:
Distribution-bearing common units		2,189.1			2,174.6			2,188.1			2,170.7
Phantom units (1)		13.5			10.8			13.0			10.6
Total		2,202.6			2,185.4			2,201.1			2,181.3

Diluted earnings per unit	$	0.55		$	0.31		$	1.12		$	0.72

(1)

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

Note 12. Equity-Based Awards

An allocated portion of the fair value of EPCO’s equity-based awards is charged to us under the ASA. The following table summarizes compensation expense we recognized in connection with equity-based awards for the periods indicated:

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2019		2018		2019		2018
Equity-classified awards:
Phantom unit awards	$	35.5	$	25.9	$	64.9	$	50.5
Profits interest awards		3.0		1.0		5.6		2.6
Liability-classified awards		–		0.1		–		0.2
Total	$	38.5	$	27.0	$	70.5	$	53.3

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

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Phantom Unit Awards

Phantom unit awards allow recipients to acquire EPD common units (at no cost to the recipient apart from fulfilling service and other conditions) once a defined vesting period expires, subject to customary forfeiture provisions. The following table presents phantom unit award activity for the period indicated:

	Number of Units			Weighted- Average Grant Date Fair Value per Unit (1)
Phantom unit awards at December 31, 2018		10,333,277		$	26.97
Granted (2)		6,836,920		$	27.75
Vested		(3,561,704	)	$	27.58
Forfeited		(182,095	)	$	27.18
Phantom unit awards at June 30, 2019		13,426,398		$	27.21

(1)	Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued.
(2)	The aggregate grant date fair value of phantom unit awards issued during 2019 was $189.7 million based on a grant date market price of EPD common units ranging from $27.75 to $28.55 per unit. An estimated annual forfeiture rate of 3.0% was applied to these awards.

Each phantom unit award includes a DER, which entitles the recipient to receive cash payments equal to the product of the number of phantom unit awards and the cash distribution per unit paid to EPD’s common unitholders. Cash payments made in connection with DERs are nonforfeitable and charged to partners’ equity when the phantom unit award is expected to result in the issuance of common units; otherwise, such amounts are expensed.

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

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2019		2018		2019		2018
Cash payments made in connection with DERs	$	6.0	$	4.7	$	10.5	$	8.6
Total intrinsic value of phantom unit awards that vested during period		4.7		3.1		101.7		85.1

The unrecognized compensation cost associated with phantom unit awards was $209.3 million at June 30, 2019, of which our share of the cost is currently estimated to be $178.2 million. Due to the graded vesting provisions of these awards, we expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 2.2 years.

Profits Interest Awards

EPCO has established five limited partnerships (referred to as “Employee Partnerships”) that serve as long-term incentive arrangements for key employees of EPCO by providing them a profits interest in one or more of the Employee Partnerships. At June 30, 2019, our share of the total unrecognized compensation cost related to the Employee Partnerships was $30.0 million, which we expect to recognize over a weighted-average period of 3.5 years.

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Note 13. Derivative Instruments, Hedging Activities and Fair Value Measurements

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

Interest Rate Hedging Activities

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

In May 2019, we entered into two 30-year forward-starting swaps in connection with the expected future issuance of senior notes. The following table summarizes our portfolio of these swaps at June 30, 2019:

Hedged Transaction	Number and Type of Derivatives Outstanding	Notional Amount	Expected Settlement Date	Average Rate Locked	Accounting Treatment
Future long-term debt offering	1 forward-starting swap	$75.0	9/2020	2.39%	Cash flow hedge
Future long-term debt offering	1 forward-starting swap	$75.0	4/2021	2.41%	Cash flow hedge

We sold swaptions related to our interest rate hedging activities that resulted in the recognition of $9.8 million of cash gains that were reflected as a reduction in interest expense for the first quarter of 2019.

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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 and basis swaps.

At June 30, 2019, our predominant commodity hedging strategies consisted of (i) hedging anticipated future purchases and sales of commodity products associated with transportation, storage and blending activities, (ii) hedging natural gas processing margins and (iii) hedging the fair value of commodity products held in inventory.

The following table summarizes our portfolio of commodity derivative instruments outstanding at June 30, 2019 (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 (billion cubic feet (“Bcf”))	25.9	n/a	Cash flow hedge
Forecasted sales of NGLs (million barrels (“MMBbls”))	4.2	n/a	Cash flow hedge
Octane enhancement:
Forecasted purchase of NGLs (MMBbls)	1.3	n/a	Cash flow hedge
Forecasted sales of octane enhancement products (MMBbls)	2.0	n/a	Cash flow hedge
Natural gas marketing:
Forecasted purchase of natural gas (Bcf)	3.7	n/a	Cash flow hedge
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)	55.0	2.8	Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products (MMBbls)	72.1	0.8	Cash flow hedge
NGLs inventory management activities (MMBbls)	0.6	n/a	Fair value hedge
Refined products marketing:
Refined products inventory management activities (MMBbls)	0.1	n/a	Fair value hedge
Crude oil marketing:
Forecasted purchases of crude oil (MMBbls)	19.2	n/a	Cash flow hedge
Forecasted sales of crude oil (MMBbls)	26.2	n/a	Cash flow hedge
Propylene marketing:
Forecasted sales of NGLs for propylene marketing activities (MMBbls)	0.3	n/a	Cash flow hedge
Derivatives not designated as hedging instruments:
Natural gas risk management activities (Bcf) (3)	47.5	0.1	Mark-to-market
NGL risk management activities (MMBbls) (3)	5.4	n/a	Mark-to-market
Refined products risk management activities (MMBbls) (3)	1.8	n/a	Mark-to-market
Crude oil risk management activities (MMBbls) (3)	39.0	1.6	Mark-to-market

(1)	Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes.
(2)	The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is December 2020, December 2019 and December 2020, respectively.
(3)	Reflects the use of derivative instruments to manage risks associated with transportation, processing and storage assets.

The carrying amount of our inventories subject to fair value hedges was $16.2 million and $50.2 million at June 30, 2019 and December 31, 2018, respectively.

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Tabular Presentation of Fair Value Amounts, and Gains and Losses on

Derivative Instruments and Related Hedged Items

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

	Asset Derivatives						Liability Derivatives
	June 30, 2019			December 31, 2018			June 30, 2019			December 31, 2018
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments
Interest rate derivatives	Other assets	$	–	Other assets	$	–	Other liabilities	$	5.2	Other liabilities	$	–
Commodity derivatives	Current assets	$	172.4	Current assets	$	138.5	Current liabilities	$	115.2	Current liabilities	$	115.0
Commodity derivatives	Other assets		4.9	Other assets		5.6	Other liabilities		7.6	Other liabilities		11.1
Total commodity derivatives		$	177.3		$	144.1		$	122.8		$	126.1
Total derivatives designated as hedging instruments		$	177.3		$	144.1		$	128.0		$	126.1

Derivatives not designated as hedging instruments
Commodity derivatives	Current assets	$	23.4	Current assets	$	15.9	Current liabilities	$	13.2	Current liabilities	$	33.2
Commodity derivatives	Other assets		1.6	Other assets		1.9	Other liabilities		1.0	Other liabilities		3.1
Total		$	25.0		$	17.8		$	14.2		$	36.3

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

	Offsetting of Financial Assets and Derivative Assets
	Gross Amounts 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 June 30, 2019:
Commodity derivatives		$	202.3		$	–		$	202.3		$	(137.7	)		$	(64.6	)		$	–		$	–
As of December 31, 2018:
Commodity derivatives		$	161.9		$	–		$	161.9		$	(158.6	)		$	–			$	–		$	3.3

	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 June 30, 2019:
Interest rate derivatives		$	5.2			–		$	5.2		$	–		$	–	$	–			$	5.2
Commodity derivatives			137.0		$	–			137.0			(137.7	)		–		0.2				(0.5	)
As of December 31, 2018:
Commodity derivatives		$	162.4		$	–		$	162.4		$	(158.6	)	$	–	$	(2.3	)		$	1.5

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Derivative assets and liabilities recorded on our Unaudited Condensed Consolidated Balance Sheets are presented on a gross-basis and determined at the individual transaction level. The tabular presentation above provides a means for comparing the gross amount of derivative assets and liabilities, excluding associated accounts payable and receivable, to the net amount that would likely be receivable or payable under a default scenario based on the existence of rights of offset in the respective derivative agreements. Any cash collateral paid or received is reflected in these tables, but only to the extent that it represents variation margins. Any amounts associated with derivative prepayments or initial margins that are not influenced by the derivative asset or liability amounts or those that are determined solely on their volumetric notional amounts are excluded from these tables.

The following tables present the effect of our derivative instruments designated as fair value hedges on our Unaudited Condensed Statements of Consolidated Operations for the periods indicated:

Derivatives in Fair Value Hedging Relationships	Location	Gain (Loss) Recognized in Income on Derivative
		For the Three Months Ended June 30,				For the Six Months Ended June 30,
		2019		2018		2019			2018
Interest rate derivatives	Interest expense	$	–	$	0.6	$	–		$	1.3
Commodity derivatives	Revenue		6.9		4.8		(1.6	)		4.6
Total		$	6.9	$	5.4	$	(1.6	)	$	5.9

Derivatives in Fair Value Hedging Relationships	Location	Gain (Loss) Recognized in Income on Hedged Item
		For the Three Months Ended June 30,						For the Six Months Ended June 30,
		2019			2018			2019		2018
Interest rate derivatives	Interest expense	$	–		$	(0.6	)	$	–	$	(1.4	)
Commodity derivatives	Revenue		(3.6	)		(4.9	)		6.3		(1.8	)
Total		$	(3.6	)	$	(5.5	)	$	6.3	$	(3.2	)

The following tables present the effect of our derivative instruments designated as cash flow hedges on our Unaudited Condensed Statements of Consolidated Operations and Unaudited Condensed Statements of Consolidated Comprehensive Income for the periods indicated:

Derivatives in Cash Flow Hedging Relationships	Change in Value Recognized in Other Comprehensive Income (Loss) on Derivative
	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
Interest rate derivatives	$	(5.2	)	$	3.5		$	(5.2	)	$	14.6
Commodity derivatives – Revenue (1)		84.3			(14.2	)		(2.4	)		(11.2	)
Commodity derivatives – Operating costs and expenses (1)		(2.8	)		0.6			(11.3	)		1.0
Total	$	76.3		$	(10.1	)	$	(18.9	)	$	4.4

(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.

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Derivatives in Cash Flow Hedging Relationships	Location	Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income
		For the Three Months Ended June 30,						For the Six Months Ended June 30,
		2019			2018			2019			2018
Interest rate derivatives	Interest expense	$	(9.2	)	$	(9.4	)	$	(18.4	)	$	(19.9	)
Commodity derivatives	Revenue		2.5			(39.4	)		67.8			(25.4	)
Commodity derivatives	Operating costs and expenses		(0.3	)		0.2			(7.3	)		0.7
Total		$	(7.0	)	$	(48.6	)	$	42.1		$	(44.6	)

Over the next twelve months, we expect to reclassify $38.4 million of losses attributable to interest rate derivative instruments from accumulated other comprehensive loss to earnings as an increase in interest expense. Likewise, we expect to reclassify $85.9 million of gains attributable to commodity derivative instruments from accumulated other comprehensive income to earnings, $88.6 million as an increase in revenue and $2.7 million as an increase in operating costs and expenses.

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

Derivatives Not Designated as Hedging Instruments	Location	Gain (Loss) Recognized in Income on Derivative
		For the Three Months Ended June 30,						For the Six Months Ended June 30,
		2019			2018			2019			2018
Commodity derivatives	Revenue	$	(20.2	)	$	(406.3	)	$	74.9		$	(559.8	)
Commodity derivatives	Operating costs and expenses		(4.8	)		–			(4.7	)		(1.5	)
Total		$	(25.0	)	$	(406.3	)	$	70.2		$	(561.3	)

The $70.2 million gain recognized in 2019 from derivatives not designated as hedging instruments (as noted in the preceding table) reflects $11.7 million of realized losses and $81.9 million of net unrealized mark-to-market gains. In the aggregate, our unrealized mark-to-market gain for the six months ended June 30, 2019 attributable to derivatives designated as fair value hedges and derivatives not designated as hedging instruments was $84.7 million.

Fair Value Measurements

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

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The values for commodity derivatives are presented before and after the application of Chicago Mercantile Exchange (“CME”) Rule 814, which deems that financial instruments cleared by the CME are settled daily in connection with variation margin payments. As a result of this exchange rule, CME-related derivatives are considered to have no fair value at the balance sheet date for financial reporting purposes; however, the derivatives remain outstanding and subject to future commodity price fluctuations until they are settled in accordance with their contractual terms. Derivative transactions cleared on exchanges other than the CME (e.g., the Intercontinental Exchange or ICE) continue to be reported on a gross basis.

	At June 30, 2019 Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total
Financial assets:
Commodity derivatives:
Value before application of CME Rule 814	$	62.7		$	339.4		$	6.3		$	408.4
Impact of CME Rule 814		(46.7	)		(154.2	)		(5.2	)		(206.1	)
Total commodity derivatives		16.0			185.2			1.1			202.3
Total	$	16.0		$	185.2		$	1.1		$	202.3

Financial liabilities:
Liquidity Option Agreement (see Note 15)	$	–		$	–		$	474.4		$	474.4
Interest rate derivatives		–			5.2			–			5.2
Commodity derivatives:
Value before application of CME Rule 814		77.6			253.4			22.6			353.6
Impact of CME Rule 814		(62.0	)		(138.3	)		(16.3	)		(216.6	)
Total commodity derivatives		15.6			115.1			6.3			137.0
Total	$	15.6		$	120.3		$	480.7		$	616.6

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

Financial liabilities:
Liquidity Option Agreement (see Note 15)	$	–		$	–		$	390.0		$	390.0
Commodity derivatives:
Value before application of CME Rule 814		85.5			291.2			21.4			398.1
Impact of CME Rule 814		(48.6	)		(172.9	)		(14.2	)		(235.7	)
Total commodity derivatives		36.9			118.3			7.2			162.4
Total	$	36.9		$	118.3		$	397.2		$	552.4

In the aggregate, the fair value of our commodity hedging portfolios at June 30, 2019 was a net derivative asset of $54.8 million prior to the impact of CME Rule 814.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table provides quantitative information regarding our recurring Level 3 fair value measurements for commodity derivatives at June 30, 2019:

	Fair Value
	Financial Assets		Financial Liabilities		Valuation Techniques	Unobservable Input	Range
Commodity derivatives – Crude oil	$	0.2	$	0.3	Discounted cash flow	Forward commodity prices	$57.62-$58.65/barrel
Commodity derivatives – Propane		–		1.7	Discounted cash flow	Forward commodity prices	$0.56-$0.62/gallon
Commodity derivatives – Natural gasoline		–		1.9	Discounted cash flow	Forward commodity prices	$1.11-$1.15/gallon
Commodity derivatives – Ethane		0.9		1.5	Discounted cash flow	Forward commodity prices	$0.17-$0.24/gallon
Commodity derivatives – Normal Butane		–		0.9	Discounted cash flow	Forward commodity prices	$0.62-$0.69/gallon
Total	$	1.1	$	6.3

With respect to commodity derivatives, we believe forward commodity prices are the most significant unobservable inputs in determining our Level 3 recurring fair value measurements at June 30, 2019. In general, changes in the price of the underlying commodity increases or decreases the fair value of a commodity derivative depending on whether the derivative was purchased or sold. We generally expect changes in the fair value of our derivative instruments to be offset by corresponding changes in the fair value of our hedged exposures.

The following table sets forth a reconciliation of changes in the fair values of our recurring Level 3 financial assets and liabilities on a combined basis for the periods indicated:

test		For the Six Months Ended June 30,
test	Location	2019			2018
Financial liability balance, net, January 1		$	(395.9	)	$	(332.7	)
Total gains (losses) included in:
Net income (1)	Revenue		3.1			(0.5	)
Net income	Other expense, net		(57.8	)		(7.5	)
Other comprehensive income (loss)	Commodity derivative instruments – changes in fair value of cash flow hedges		4.0			–
Settlements (1)	Revenue		(0.1	)		(1.2	)
Transfers out of Level 3			(0.2	)		–
Financial liability balance, net, March 31			(446.9	)		(341.9	)
Total gains (losses) included in:
Net income (1)	Revenue		(0.1	)		1.3
Net income	Other expense, net		(26.6	)		(8.9	)
Other comprehensive income (loss)	Commodity derivative instruments – changes in fair value of cash flow hedges		(2.9	)		–
Settlements (1)	Revenue		(3.1	)		0.5
Transfers out of Level 3			–			–
Financial liability balance, net, June 30		$	(479.6	)	$	(349.0	)

(1)

There were unrealized losses of $3.2 million and $0.2 million included in these amounts for the three and six months ended June 30, 2019, respectively. There were unrealized losses of $1.8 million and $0.1 million included in these amounts for the three and six months ended June 30, 2018, respectively.

Nonrecurring Fair Value Measurements

Non-cash asset impairment charges for the six months ended June 30, 2019 were $11.8 million compared to $16.8 million for the six months ended June 30, 2018. Charges for 2019 primarily relate to assets retired during the quarter whose operations have ceased. Impairment charges are a component of “Operating costs and expenses” on our Unaudited Condensed Statements of Consolidated Operations.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Other Fair Value Information

The carrying amounts of cash and cash equivalents (including restricted cash balances), accounts receivable, commercial paper notes and accounts payable approximate their fair values based on their short-term nature. The estimated total fair value of our fixed-rate debt obligations was $27.69 billion and $25.97 billion at June 30, 2019 and December 31, 2018, respectively. The aggregate carrying value of these debt obligations was $25.45 billion and $26.15 billion at June 30, 2019 and December 31, 2018, respectively. These values are primarily based on quoted market prices for such debt or debt of similar terms and maturities (Level 2) and our credit standing. Changes in market rates of interest affect the fair value of our fixed-rate debt. The carrying values of our variable-rate long-term debt obligations approximate their fair values since the associated interest rates are market-based. We do not have any long-term investments in debt or equity securities recorded at fair value.

Note 14. Related Party Transactions

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

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2019		2018		2019		2018
Revenues – related parties:
Unconsolidated affiliates	$	25.8	$	55.6	$	38.1	$	80.3
Costs and expenses – related parties:
EPCO and its privately held affiliates	$	267.2	$	260.2	$	540.1	$	516.9
Unconsolidated affiliates		95.3		148.0		218.6		241.4
Total	$	362.5	$	408.2	$	758.7	$	758.3

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

	June 30, 2019		December 31, 2018
Accounts receivable - related parties:
Unconsolidated affiliates	$	14.2	$	3.5

Accounts payable - related parties:
EPCO and its privately held affiliates	$	61.4	$	116.3
Unconsolidated affiliates		12.2		23.9
Total	$	73.6	$	140.2

We believe that the terms and provisions of our related party agreements are fair to us; however, such agreements and transactions may not be as favorable to us as we could have obtained from unaffiliated third parties.

Relationship with EPCO and Affiliates

We have an extensive and ongoing relationship with EPCO and its privately held affiliates (including Enterprise GP, our general partner), which are not a part of our consolidated group of companies.

At June 30, 2019, EPCO and its privately held affiliates (including Dan Duncan LLC and certain Duncan family trusts) beneficially owned the following limited partner interests in us:

Total Number of Units	Percentage of Total Units Outstanding
698,051,729	31.9%

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Of the total number of units held by EPCO and its privately held affiliates, 108,222,618 have been pledged as security under the credit facilities of EPCO and its privately held affiliates at June 30, 2019. These credit facilities contain customary and other events of default, including defaults by us and other affiliates of EPCO. An event of default, followed by a foreclosure on the pledged collateral, could ultimately result in a change in ownership of these units and affect the market price of EPD’s common units.

We and Enterprise GP are both separate legal entities apart from each other and apart from EPCO and its other affiliates, with assets and liabilities that are also separate from those of EPCO and its other affiliates. EPCO and its privately held affiliates depend on the cash distributions they receive from us and other investments to fund their other activities and to meet their debt obligations. During the six months ended June 30, 2019 and 2018, we paid EPCO and its privately held affiliates cash distributions totaling $593.7 million and $576.3 million, respectively.

From time-to-time, EPCO and its privately held affiliates elect to purchase additional common units under EPD’s DRIP and ATM program. During the six months ended June 30, 2019, privately held affiliates of EPCO reinvested $14 million through the DRIP. See Note 8 for additional information regarding the DRIP.

We have no employees. All of our operating functions and general and administrative support services are provided by employees of EPCO pursuant to the ASA or by other service providers. The following table presents our related party costs and expenses attributable to the ASA with EPCO for the periods indicated:

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2019		2018		2019		2018
Operating costs and expenses	$	233.6	$	228.0	$	472.7	$	451.0
General and administrative expenses		29.4		28.4		58.7		57.6
Total costs and expenses	$	263.0	$	256.4	$	531.4	$	508.6

Note 15. Commitments and Contingencies

Litigation

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

At June 30, 2019 and December 31, 2018, our accruals for litigation contingencies were $0.5 million and $0.5 million, respectively, and recorded in our Unaudited Condensed Consolidated Balance Sheets as a component of “Other current liabilities.”

Energy Transfer Matter

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

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

We filed our Brief of the Appellant in the Court of Appeals for the Fifth District of Dallas, Texas on March 30, 2015 and ETP filed its Brief of Appellees on June 29, 2015. We filed our Reply Brief of Appellant on September 18, 2015. Oral argument was conducted on April 20, 2016, and the case was then submitted to the Court of Appeals for its consideration. On July 18, 2017, a panel of the Dallas Court of Appeals issued a unanimous opinion reversing the trial court’s judgment as to all of ETP’s claims against us, rendering judgment that ETP take nothing on those claims, and affirming our counterclaim against ETP of $0.8 million, plus interest. On August 31, 2017, ETP filed a motion for rehearing before the Dallas Court of Appeals, which was denied on September 13, 2017. On December 27, 2017, ETP filed its Petition for Review with the Supreme Court of Texas and we filed our Response to the Petition for Review on February 26, 2018. On June 8, 2018, the Supreme Court of Texas requested that the parties file briefs on the merits, and the parties filed their respective submittals. On June 28, 2019, the Supreme Court of Texas requested oral argument, which has been scheduled for October 8, 2019.

We have not recorded a provision for this matter as management continues to believe that payment of damages by us in this case is not probable. We continue to monitor developments involving this matter.

PDH Litigation

In July 2013, we executed a contract with Foster Wheeler USA Corporation (“Foster Wheeler”) pursuant to which Foster Wheeler was to serve as the general contractor responsible for the engineering, procurement, construction and installation of our propane dehydrogenation (“PDH”) facility. In November 2014, Foster Wheeler was acquired by an affiliate of AMEC plc to form Amec Foster Wheeler plc, and Foster Wheeler is now known as Amec Foster Wheeler USA Corporation (“AFW”). In December 2015, Enterprise and AFW entered into a transition services agreement under which AFW was partially terminated from the PDH project. In December 2015, Enterprise engaged a second contractor, Optimized Process Designs LLC (“OPD”), to complete the construction and installation of the PDH facility.

On September 2, 2016, we terminated AFW for cause and filed a lawsuit in the 151st Judicial Civil District Court of Harris County, Texas against AFW and its parent company, Amec Foster Wheeler plc, asserting claims for breach of contract, breach of warranty, fraudulent inducement, string-along fraud, gross negligence, professional negligence, negligent misrepresentation and attorneys’ fees. We intend to diligently prosecute these claims and seek all direct, consequential, and exemplary damages to which we may be entitled.

Contractual Obligations

Scheduled Maturities of Debt

We have long-term and short-term payment obligations under debt agreements. In total, the principal amount of our consolidated debt obligations were $27.12 billion and $26.42 billion at June 30, 2019 and December 31, 2018, respectively. See Note 7 for additional information regarding our scheduled future maturities of debt principal.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Lease Accounting Matters

The following table presents information regarding our operating leases where we are the lessee at June 30, 2019:

Asset Category	ROU Asset Carrying Value (1)		Lease Liability Carrying Value (2)		Weighted- Average Remaining Term	Weighted- Average Discount Rate (3)
Storage and pipeline facilities	$	144.3	$	145.0	16 years	4.3%
Transportation equipment		56.2		58.7	4 years	3.6%
Office and warehouse space		27.1		25.8	3 years	3.5%
Total	$	227.6	$	229.5

(1)	ROU asset amounts are a component of “Other assets” on our consolidated balance sheet.
(2)	At June 30, 2019, lease liabilities of $38.6 million and $190.9 million were included within “Other current liabilities” and “Other liabilities,” respectively.
(3)	The discount rate for each category of assets represents the weighted average of either (i) the implicit rate applicable to the underlying leases (where determinable) or (ii) our incremental borrowing rate adjusted for collateralization (if the implicit rate is not determinable). In general, the discount rates are based on either (i) information available at the lease commencement date or (ii) January 1, 2019 for leases existing at the adoption date for ASC 842.

The following table disaggregates our operating lease expense for the periods indicated:

	For the Three Months Ended June 30, 2019		For the Six Months Ended June 30, 2019
Long-term operating leases:
Fixed lease expense	$	13.1	$	26.5
Variable lease expense		1.1		2.9
Subtotal operating lease expense		14.2		29.4
Short-term lease expense		11.7		23.5
Total operating lease expense	$	25.9	$	52.9

In total, operating lease expense was $25.9 million and $25.8 million for the three months ended June 30, 2019 and 2018, respectively. During the six months ended June 30, 2019 and 2018 operating lease expense was $52.9 million and $51.4 million, respectively. Operating lease expense represents less than 1% of “Operating costs and expenses” as presented on our consolidated statements of operations. Fixed lease expense is charged to earnings on a straight-line basis over the contractual term, with any variable lease payments expensed as incurred. Short-term lease expense is expensed as incurred.

We recognized $246.1 million in ROU assets and lease liabilities for long-term operating leases at January 1, 2019 in connection with the adoption of ASC 842. These amounts represented less than 1% of our total consolidated assets and liabilities, respectively, at the adoption date. On an undiscounted basis, our long-term operating lease obligations aggregated to $314.4 million at January 1, 2019.

Under ASC 842, lessors classify leases as either operating, direct financing or sales-type. We do not have any significant operating or direct financing leases. Our operating lease income for the three and six months ended June 30, 2019 was $2.4 million and $7.2 million, respectively, which represented less than 1% of our consolidated revenues. We do not have any sales-type leases.

Our operating lease commitments at June 30, 2019 did not differ materially from those reported in our 2018 Form 10-K.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Purchase Obligations

During the six months ended June 30, 2019, we entered into additional long-term purchase commitments for NGLs with third party suppliers. On a combined basis, these new agreements increased our estimated long-term purchase obligations by $3.6 billion, with $1.3 billion committed over the next five years and $2.3 billion thereafter. At June 30, 2019, our estimated long-term purchase obligations totaled $13.0 billion after reflecting the agreements added during the first six months of 2019 and those commitments that expired during the year. At December 31, 2018, our estimated long-term purchase obligations totaled $10.8 billion.

Liquidity Option Agreement

We entered into a put option agreement (the “Liquidity Option Agreement” or “Liquidity Option”) with Oiltanking Holding Americas, Inc. (“OTA”) and Marquard & Bahls AG (“M&B”), a German corporation and the ultimate parent company of OTA, in connection with the first step of the Oiltanking acquisition in 2014 (“Step 1”). Under the Liquidity Option Agreement, we granted M&B the option to sell to us 100% of the issued and outstanding capital stock of OTA at any time within a 90-day period commencing on February 1, 2020. If the Liquidity Option is exercised during this period, we would indirectly acquire the EPD common units then owned by OTA, currently 54,807,352 units, and assume all future income tax obligations of OTA associated with (i) owning common units encumbered by the entity-level taxes of a U.S. corporation and (ii) any associated net deferred taxes. If we assume net deferred tax liabilities that exceed the then current book value of the Liquidity Option liability at the exercise date, we will recognize expense for the difference.

The carrying value of the Liquidity Option Agreement, which is a component of “Other long-term liabilities” on our Unaudited Condensed Consolidated Balance Sheet, was $474.4 million and $390.0 million at June 30, 2019 and December 31, 2018, respectively. The fair value of the Liquidity Option, at any measurement date, represents the present value of estimated federal and state income tax payments that we believe a market participant would incur on the future taxable income of OTA. We expect that OTA’s taxable income would, in turn, be based on an allocation of our partnership’s taxable income to the common units held by OTA and reflect certain tax planning strategies we believe could be employed.

Changes in the fair value of the Liquidity Option are recognized in earnings as a component of other income (expense) on our Unaudited Condensed Statements of Consolidated Operations. Results for the three months ended June 30, 2019 and 2018 include $26.6 million and $8.9 million, respectively, of aggregate non-cash expense attributable to accretion and changes in management estimates regarding inputs to the valuation model. For the six months ended June 30, 2019 and 2018 this expense was $84.4 million and $16.4 million, respectively. Expense recognized during the first six months of 2019 is primarily due to a decrease in the applicable midstream industry weighted-average cost of capital, which is used as the discount factor in determining the present value of the liability, since December 31, 2018. The remainder of the inputs to the valuation model have not materially changed since those reported under Note 17 of the 2018 Form 10-K.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 16. Supplemental Cash Flow Information

The following table presents the net effect of changes in our operating accounts for the periods indicated:

	For the Six Months Ended June 30,
	2019			2018
Decrease (increase) in:
Accounts receivable – trade	$	(124.8	)	$	18.6
Accounts receivable – related parties		(10.6	)		(0.2	)
Inventories		(56.4	)		17.6
Prepaid and other current assets		(291.2	)		(82.4	)
Other assets		(12.4	)		(11.9	)
Increase (decrease) in:
Accounts payable – trade		60.0			112.1
Accounts payable – related parties		(21.0	)		(3.1	)
Accrued product payables		107.6			30.7
Accrued interest		(3.3	)		14.0
Other current liabilities		83.0			(306.4	)
Other liabilities		(62.9	)		(17.5	)
Net effect of changes in operating accounts	$	(332.0	)	$	(228.5	)

We incurred liabilities for construction in progress that had not been paid at June 30, 2019 and December 31, 2018 of $426.8 million and $567.6 million, respectively. Such amounts are not included under the caption “Capital expenditures” on the Unaudited Condensed Statements of Consolidated Cash Flows.

Acquisition of Delaware Processing

In March 2018, we acquired the remaining 50% member interest in our Delaware Basin Gas Processing LLC (“Delaware Processing”) joint venture for $150 million. As a result, Delaware Processing became our wholly-owned consolidated subsidiary. Upon acquisition of the remaining 50% member interest, our existing equity investment was remeasured to fair value resulting in the recognition of a non-cash $39.4 million gain during 2018.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 17. Condensed Consolidating Financial Information

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

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

EPO’s consolidated subsidiaries have no significant restrictions on their ability to pay distributions or make loans to EPD.

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Balance Sheet

June 30, 2019

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non- guarantor)		EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries		EPD (Guarantor)		Eliminations and Adjustments			Consolidated Total
ASSETS
Current assets:
Cash and cash equivalents and restricted cash	$	24.6	$	89.7	$	(7.2	)	$	107.1	$	0.2	$	–		$	107.3
Accounts receivable – trade, net		1,088.1		2,701.3		(1.8	)		3,787.6		–		–			3,787.6
Accounts receivable – related parties		286.6		903.0		(1,130.9	)		58.7		–		(44.5	)		14.2
Inventories		1,004.3		582.1		(0.3	)		1,586.1		–		–			1,586.1
Derivative assets		154.7		41.1		–			195.8		–		–			195.8
Prepaid and other current assets		275.4		323.3		(31.4	)		567.3		0.5		0.1			567.9
Total current assets		2,833.7		4,640.5		(1,171.6	)		6,302.6		0.7		(44.4	)		6,258.9
Property, plant and equipment, net		6,269.9		33,865.6		(46.4	)		40,089.1		–		–			40,089.1
Investments in unconsolidated affiliates		44,685.6		4,120.5		(46,154.0	)		2,652.1		24,957.1		(24,957.1	)		2,652.1
Intangible assets, net		648.4		2,897.7		(13.5	)		3,532.6		–		–			3,532.6
Goodwill		459.5		5,285.7		–			5,745.2		–		–			5,745.2
Other assets		387.3		278.0		(222.3	)		443.0		0.9		–			443.9
Total assets	$	55,284.4	$	51,088.0	$	(47,607.8	)	$	58,764.6	$	24,958.7	$	(25,001.5	)	$	58,721.8

LIABILITIES AND EQUITY
Current liabilities:
Current maturities of debt	$	500.0	$	–	$	–		$	500.0	$	–	$	–		$	500.0
Accounts payable – trade		335.5		750.2		(7.2	)		1,078.5		–		–			1,078.5
Accounts payable – related parties		1,013.4		205.1		(1,144.9	)		73.6		44.5		(44.5	)		73.6
Accrued product payables		1,369.1		2,247.9		(2.1	)		3,614.9		–		–			3,614.9
Accrued interest		392.3		0.8		(0.8	)		392.3		–		–			392.3
Derivative liabilities		106.6		21.8		–			128.4		–		–			128.4
Other current liabilities		127.5		378.9		(30.1	)		476.3		–		0.1			476.4
Total current liabilities		3,844.4		3,604.7		(1,185.1	)		6,264.0		44.5		(44.4	)		6,264.1
Long-term debt		26,370.3		14.7		–			26,385.0		–		–			26,385.0
Deferred tax liabilities		17.1		66.2		(1.0	)		82.3		–		2.3			84.6
Other long-term liabilities		145.7		614.5		(221.9	)		538.3		474.4		–			1,012.7
Commitments and contingencies
Equity:
Partners’ and other owners’ equity		24,906.9		46,721.2		(46,700.2	)		24,927.9		24,439.8		(24,927.9	)		24,439.8
Noncontrolling interests		–		66.7		500.4			567.1		–		(31.5	)		535.6
Total equity		24,906.9		46,787.9		(46,199.8	)		25,495.0		24,439.8		(24,959.4	)		24,975.4
Total liabilities and equity	$	55,284.4	$	51,088.0	$	(47,607.8	)	$	58,764.6	$	24,958.7	$	(25,001.5	)	$	58,721.8

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Balance Sheet

December 31, 2018

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

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

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Statement of Operations

For the Three Months Ended June 30, 2019

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			EPD (Guarantor)			Eliminations and Adjustments			Consolidated Total
Revenues	$	7,918.3		$	5,740.0		$	(5,382.0	)	$	8,276.3		$	–		$	–		$	8,276.3
Costs and expenses:
Operating costs and expenses		7,570.2			4,609.5			(5,378.8	)		6,800.9			–			–			6,800.9
General and administrative costs		9.4			41.2			1.2			51.8			0.7			–			52.5
Total costs and expenses		7,579.6			4,650.7			(5,377.6	)		6,852.7			0.7			–			6,853.4
Equity in income of unconsolidated affiliates		1,198.2			157.6			(1,218.4	)		137.4			1,242.0			(1,242.0	)		137.4
Operating income		1,536.9			1,246.9			(1,222.8	)		1,561.0			1,241.3			(1,242.0	)		1,560.3
Other income (expense):
Interest expense		(290.4	)		(2.5	)		2.8			(290.1	)		–			–			(290.1	)
Other, net		4.2			1.2			(2.8	)		2.6			(26.6	)		–			(24.0	)
Total other expense, net		(286.2	)		(1.3	)		–			(287.5	)		(26.6	)		–			(314.1	)
Income before income taxes		1,250.7			1,245.6			(1,222.8	)		1,273.5			1,214.7			(1,242.0	)		1,246.2
Provision for income taxes		(5.5	)		(3.9	)		–			(9.4	)		–			(0.3	)		(9.7	)
Net income		1,245.2			1,241.7			(1,222.8	)		1,264.1			1,214.7			(1,242.3	)		1,236.5
Net income attributable to noncontrolling interests		–			(1.6	)		(21.7	)		(23.3	)		–			1.5			(21.8	)
Net income attributable to entity	$	1,245.2		$	1,240.1		$	(1,244.5	)	$	1,240.8		$	1,214.7		$	(1,240.8	)	$	1,214.7

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Statement of Operations

For the Three Months Ended June 30, 2018

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			EPD (Guarantor)			Eliminations and Adjustments			Consolidated Total
Revenues	$	9,556.8		$	5,806.4		$	(6,895.7	)	$	8,467.5		$	–		$	–		$	8,467.5
Costs and expenses:
Operating costs and expenses		9,256.1			5,191.8			(6,895.9	)		7,552.0			–			–			7,552.0
General and administrative costs		8.0			42.0			0.6			50.6			0.8			–			51.4
Total costs and expenses		9,264.1			5,233.8			(6,895.3	)		7,602.6			0.8			–			7,603.4
Equity in income of unconsolidated affiliates		667.7			136.5			(681.9	)		122.3			683.5			(683.5	)		122.3
Operating income		960.4			709.1			(682.3	)		987.2			682.7			(683.5	)		986.4
Other income (expense):
Interest expense		(274.8	)		(2.6	)		2.8			(274.6	)		–			–			(274.6	)
Other, net		2.4			3.1			(2.8	)		2.7			(8.9	)		–			(6.2	)
Total other expense, net		(272.4	)		0.5			–			(271.9	)		(8.9	)		–			(280.8	)
Income before income taxes		688.0			709.6			(682.3	)		715.3			673.8			(683.5	)		705.6
Provision for income taxes		(6.2	)		(12.0	)		–			(18.2	)		–			(0.2	)		(18.4	)
Net income		681.8			697.6			(682.3	)		697.1			673.8			(683.7	)		687.2
Net income attributable to noncontrolling interests		–			(2.0	)		(12.7	)		(14.7	)		–			1.3			(13.4	)
Net income attributable to entity	$	681.8		$	695.6		$	(695.0	)	$	682.4		$	673.8		$	(682.4	)	$	673.8

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Statement of Operations

For the Six Months Ended June 30, 2019

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			EPD (Guarantor)			Eliminations and Adjustments			Consolidated Total
Revenues	$	17,396.1		$	11,379.6		$	(11,955.9	)	$	16,819.8		$	–		$	–		$	16,819.8
Costs and expenses:
Operating costs and expenses		16,719.7			9,049.6			(11,948.7	)		13,820.6			–			–			13,820.6
General and administrative costs		13.2			88.0			1.9			103.1			1.6			–			104.7
Total costs and expenses		16,732.9			9,137.6			(11,946.8	)		13,923.7			1.6			–			13,925.3
Equity in income of unconsolidated affiliates		2,475.0			329.7			(2,512.7	)		292.0			2,561.2			(2,561.2	)		292.0
Operating income		3,138.2			2,571.7			(2,521.8	)		3,188.1			2,559.6			(2,561.2	)		3,186.5
Other income (expense):
Interest expense		(567.7	)		(5.2	)		5.6			(567.3	)		–			–			(567.3	)
Other, net		7.3			2.4			(5.6	)		4.1			(84.4	)		–			(80.3	)
Total other expense, net		(560.4	)		(2.8	)		–			(563.2	)		(84.4	)		–			(647.6	)
Income before income taxes		2,577.8			2,568.9			(2,521.8	)		2,624.9			2,475.2			(2,561.2	)		2,538.9
Provision for income taxes		(9.7	)		(11.7	)		–			(21.4	)		–			(0.6	)		(22.0	)
Net income		2,568.1			2,557.2			(2,521.8	)		2,603.5			2,475.2			(2,561.8	)		2,516.9
Net income attributable to noncontrolling interests		–			(3.4	)		(41.1	)		(44.5	)		–			2.8			(41.7	)
Net income attributable to entity	$	2,568.1		$	2,553.8		$	(2,562.9	)	$	2,559.0		$	2,475.2		$	(2,559.0	)	$	2,475.2

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Statement of Operations

For the Six Months Ended June 30, 2018

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			EPD (Guarantor)			Eliminations and Adjustments			Consolidated Total
Revenues	$	19,874.6		$	12,215.3		$	(14,323.9	)	$	17,766.0		$	–		$	–		$	17,766.0
Costs and expenses:
Operating costs and expenses		19,236.7			10,862.1			(14,324.1	)		15,774.7			–			–			15,774.7
General and administrative costs		13.4			88.7			0.6			102.7			1.7			–			104.4
Total costs and expenses		19,250.1			10,950.8			(14,323.5	)		15,877.4			1.7			–			15,879.1
Equity in income of unconsolidated affiliates		1,498.7			291.0			(1,551.7	)		238.0			1,592.6			(1,592.6	)		238.0
Operating income		2,123.2			1,555.5			(1,552.1	)		2,126.6			1,590.9			(1,592.6	)		2,124.9
Other income (expense):
Interest expense		(527.0	)		(5.1	)		5.4			(526.7	)		–			–			(526.7	)
Other, net		5.2			40.6			(5.4	)		40.4			(16.4	)		–			24.0
Total other expense, net		(521.8	)		35.5			–			(486.3	)		(16.4	)		–			(502.7	)
Income before income taxes		1,601.4			1,591.0			(1,552.1	)		1,640.3			1,574.5			(1,592.6	)		1,622.2
Provision for income taxes		(11.6	)		(11.4	)		–			(23.0	)		–			(0.5	)		(23.5	)
Net income		1,589.8			1,579.6			(1,552.1	)		1,617.3			1,574.5			(1,593.1	)		1,598.7
Net income attributable to noncontrolling interests		–			(3.7	)		(23.1	)		(26.8	)		–			2.6			(24.2	)
Net income attributable to entity	$	1,589.8		$	1,575.9		$	(1,575.2	)	$	1,590.5		$	1,574.5		$	(1,590.5	)	$	1,574.5

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Statement of Comprehensive Income

For the Three Months Ended June 30, 2019

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			EPD (Guarantor)		Eliminations and Adjustments			Consolidated Total
Comprehensive income	$	1,295.7	$	1,274.5		$	(1,222.8	)	$	1,347.4		$	1,298.0	$	(1,325.6	)	$	1,319.8
Comprehensive income attributable to noncontrolling interests		–		(1.6	)		(21.7	)		(23.3	)		–		1.5			(21.8	)
Comprehensive income attributable to entity	$	1,295.7	$	1,272.9		$	(1,244.5	)	$	1,324.1		$	1,298.0	$	(1,324.1	)	$	1,298.0

Unaudited Condensed Consolidating Statement of Comprehensive Income

For the Three Months Ended June 30, 2018

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			EPD (Guarantor)		Eliminations and Adjustments			Consolidated Total
Comprehensive income	$	695.2	$	721.7		$	(681.7	)	$	735.2		$	711.8	$	(721.8	)	$	725.2
Comprehensive income attributable to noncontrolling interests		–		(2.0	)		(12.7	)		(14.7	)		–		1.3			(13.4	)
Comprehensive income attributable to entity	$	695.2	$	719.7		$	(694.4	)	$	720.5		$	711.8	$	(720.5	)	$	711.8

Unaudited Condensed Consolidating Statement of Comprehensive Income

For the Six Months Ended June 30, 2019

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			EPD (Guarantor)		Eliminations and Adjustments			Consolidated Total
Comprehensive income	$	2,589.9	$	2,473.8		$	(2,521.8	)	$	2,541.9		$	2,413.6	$	(2,500.2	)	$	2,455.3
Comprehensive income attributable to noncontrolling interests		–		(3.4	)		(41.1	)		(44.5	)		–		2.8			(41.7	)
Comprehensive income attributable to entity	$	2,589.9	$	2,470.4		$	(2,562.9	)	$	2,497.4		$	2,413.6	$	(2,497.4	)	$	2,413.6

Unaudited Condensed Consolidating Statement of Comprehensive Income

For the Six Months Ended June 30, 2018

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			EPD (Guarantor)		Eliminations and Adjustments			Consolidated Total
Comprehensive income	$	1,614.1	$	1,603.2		$	(1,551.5	)	$	1,665.8		$	1,623.0	$	(1,641.6	)	$	1,647.2
Comprehensive income attributable to noncontrolling interests		–		(3.7	)		(23.1	)		(26.8	)		–		2.6			(24.2	)
Comprehensive income attributable to entity	$	1,614.1	$	1,599.5		$	(1,574.6	)	$	1,639.0		$	1,623.0	$	(1,639.0	)	$	1,623.0

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Statement of Cash Flows

For the Six Months Ended June 30, 2019

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			EPD (Guarantor)			Eliminations and Adjustments			Consolidated Total
Operating activities:
Net income	$	2,568.1		$	2,557.2		$	(2,521.8	)	$	2,603.5		$	2,475.2		$	(2,561.8	)	$	2,516.9
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		153.0			810.6			(0.5	)		963.1			–			–			963.1
Equity in income of unconsolidated affiliates		(2,475.0	)		(329.7	)		2,512.7			(292.0	)		(2,561.2	)		2,561.2			(292.0	)
Distributions received on earnings from unconsolidated affiliates		742.1			163.8			(614.8	)		291.1			2,021.2			(2,021.2	)		291.1
Net effect of changes in operating accounts and other operating activities		1,246.9			(1,718.2	)		43.9			(427.4	)		131.9			0.1			(295.4	)
Net cash flows provided by operating activities		2,235.1			1,483.7			(580.5	)		3,138.3			2,067.1			(2,021.7	)		3,183.7
Investing activities:
Capital expenditures		(388.6	)		(1,864.3	)		(7.9	)		(2,260.8	)		–			–			(2,260.8	)
Cash used for business combination, net of cash received		–			–			–			–			–			–			–
Proceeds from asset sales		0.8			15.3			–			16.1			–			–			16.1
Other investing activities		(1,014.8	)		(1.9	)		974.9			(41.8	)		(119.3	)		119.3			(41.8	)
Cash used in investing activities		(1,402.6	)		(1,850.9	)		967.0			(2,286.5	)		(119.3	)		119.3			(2,286.5	)
Financing activities:
Borrowings under debt agreements		40,318.1			–			–			40,318.1			–			–			40,318.1
Repayments of debt		(39,617.2	)		(0.1	)		–			(39,617.3	)		–			–			(39,617.3	)
Cash distributions paid to owners		(2,021.2	)		(679.8	)		679.8			(2,021.2	)		(1,907.9	)		2,021.2			(1,907.9	)
Cash payments made in connection with DERs		–			–			–			–			(10.5	)		–			(10.5	)
Cash distributions paid to noncontrolling interests		–			(4.9	)		(42.5	)		(47.4	)		–			0.5			(46.9	)
Cash contributions from noncontrolling interests		–			–			99.6			99.6			–			–			99.6
Net cash proceeds from issuance of common units		–			–			–			–			82.2			–			82.2
Common units acquired in connection with buyback program		–			–			–			–			(81.1	)		–			(81.1	)
Cash contributions from owners		119.3			1,097.0			(1,097.0	)		119.3			–			(119.3	)		–
Other financing activities		(0.3	)		(5.6	)		–			(5.9	)		(30.3	)		–			(36.2	)
Cash provided by (used in) financing activities		(1,201.3	)		406.6			(360.1	)		(1,154.8	)		(1,947.6	)		1,902.4			(1,200.0	)
Net change in cash and cash equivalents, including restricted cash		(368.8	)		39.4			26.4			(303.0	)		0.2			–			(302.8	)
Cash and cash equivalents, including restricted cash, at beginning of period		393.4			50.3			(33.6	)		410.1			–			–			410.1
Cash and cash equivalents, including restricted cash, at end of period	$	24.6		$	89.7		$	(7.2	)	$	107.1		$	0.2		$	–		$	107.3

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Statement of Cash Flows

For the Six Months Ended June 30, 2018

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			EPD (Guarantor)			Eliminations and Adjustments			Consolidated Total
Operating activities:
Net income	$	1,589.8		$	1,579.6		$	(1,552.1	)	$	1,617.3		$	1,574.5		$	(1,593.1	)	$	1,598.7
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		129.3			744.7			(0.2	)		873.8			–			–			873.8
Equity in income of unconsolidated affiliates		(1,498.7	)		(291.0	)		1,551.7			(238.0	)		(1,592.6	)		1,592.6			(238.0	)
Distributions received on earnings from unconsolidated affiliates		609.5			136.3			(518.2	)		227.6			1,891.4			(1,891.4	)		227.6
Net effect of changes in operating accounts and other operating activities		1,405.7			(1,229.3	)		3.0			179.4			56.3			–			235.7
Net cash flows provided by operating activities		2,235.6			940.3			(515.8	)		2,660.1			1,929.6			(1,891.9	)		2,697.8
Investing activities:
Capital expenditures		(460.7	)		(1,405.2	)		–			(1,865.9	)		(55.2	)		–			(1,921.1	)
Cash used for business combination, net of cash received		–			(149.7	)		–			(149.7	)		–			–			(149.7	)
Proceeds from asset sales		0.4			2.2			–			2.6			–			–			2.6
Other investing activities		(1,024.5	)		160.4			842.7			(21.4	)		(253.7	)		253.7			(21.4	)
Cash used in investing activities		(1,484.8	)		(1,392.3	)		842.7			(2,034.4	)		(308.9	)		253.7			(2,089.6	)
Financing activities:
Borrowings under debt agreements		38,566.4			11.6			(11.6	)		38,566.4			–			–			38,566.4
Repayments of debt		(37,436.6	)		(0.4	)		–			(37,437.0	)		–			–			(37,437.0	)
Cash distributions paid to owners		(1,891.4	)		(727.8	)		727.8			(1,891.4	)		(1,847.3	)		1,891.4			(1,847.3	)
Cash payments made in connection with DERs		–			–			–			–			(8.6	)		–			(8.6	)
Cash distributions paid to noncontrolling interests		–			(4.3	)		(24.5	)		(28.8	)		–			0.5			(28.3	)
Cash contributions from noncontrolling interests		–			–			206.9			206.9			–			–			206.9
Net cash proceeds from issuance of common units		–			–			–			–			261.0			–			261.0
Cash contributions from owners		253.7			1,223.1			(1,223.1	)		253.7			–			(253.7	)		–
Other financing activities		(24.3	)		–			–			(24.3	)		(25.8	)		–			(50.1	)
Cash provided by (used in) financing activities		(532.2	)		502.2			(324.5	)		(354.5	)		(1,620.7	)		1,638.2			(337.0	)
Net change in cash and cash equivalents, including restricted cash		218.6			50.2			2.4			271.2			–			–			271.2
Cash and cash equivalents, including restricted cash, at beginning of period		65.2			31.5			(26.4	)		70.3			–			–			70.3
Cash and cash equivalents, including restricted cash, at end of period	$	283.8		$	81.7		$	(24.0	)	$	341.5		$	–		$	–		$	341.5

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS.

For the Three and Six Months Ended June 30, 2019 and 2018

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, 2018 (the “2018 Form 10-K”), as filed on March 1, 2019 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

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 second quarter of 2019 compared to the second quarter of 2018. Likewise, the phrase “period-to-period” means the six months ended June 30, 2019 compared to the six months ended June 30, 2018.

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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 2018 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

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 49,200 miles of pipelines; 260 MMBbls of storage capacity for NGLs, crude oil, petrochemicals and refined products; and 14 Bcf of natural gas storage capacity.

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 Announces Final Investment Decision Regarding Gulf of Mexico Offshore Crude Oil Terminal;

Signs Long-Term Agreement with Chevron to Support Development of Offshore Terminal

In July 2019, we announced long-term agreements with Chevron U.S.A. Inc. (“Chevron”) that support the development of our Sea Port Oil Terminal (“SPOT”) in the Gulf of Mexico. Construction of SPOT remains subject to obtaining the required approvals and licenses from the federal Maritime Administration, which is currently reviewing our SPOT application. The long-term agreements with Chevron support our final investment decision in SPOT, subject to receiving the requisite governmental permits.

The SPOT project consists of onshore and offshore facilities, including a fixed platform located approximately 30 nautical miles off the Brazoria County, Texas coast in approximately 115 feet of water. SPOT is designed to load Very Large Crude Carriers (“VLCCs”) at rates of approximately 85,000 barrels per hour. We believe that SPOT’s design meets or exceeds federal requirements for such facilities and, unlike existing and other proposed offshore terminals, is designed with a vapor control system to minimize emissions. SPOT would provide customers with an integrated solution that leverages our extensive supply, storage and distribution network along the Gulf Coast, with access to approximately 6 MMBbls of crude oil supply and more than 300 MMBbls of storage.

We expect that U.S. crude oil exports will increase from approximately 3 MMBPD currently to more than 8 MMBPD by 2025, as production from domestic shale basins continues to increase. SPOT would initially provide up to 2 MMBPD of this capacity and be essential to balancing the market and meeting global demand for U.S. production.

Enterprise Announces Pipeline Transportation, Storage and Marine Services Agreements with Chevron

In July 2019, we announced the execution of long-term agreements for crude oil transportation, storage and marine terminal services with Chevron. These agreements, along with other customer agreements, support expansion of our crude oil pipeline system from the Permian Basin to our ECHO terminal by approximately 450 MBPD. The agreements also provide for storage at our ECHO terminal, which has a total capacity of 8.3 MMBbls and connects to all refiners in the Houston, Pasadena, Texas City and Beaumont/Port Arthur, Texas areas. These expansion projects are expected to be placed into service during the third quarter of 2020.

Altus Acquires 33% Equity Interest in Shin Oak NGL Pipeline from Enterprise

In May 2018, we granted Apache Corporation (“Apache”) an option to acquire up to a 33% equity interest in our subsidiary that owns the Shin Oak NGL Pipeline, which entered limited commercial service in February 2019. In November 2018, Apache contributed the Shin Oak option to Altus Midstream Company (“Altus”), which is majority-owned by Apache. In July 2019, Altus exercised the option and acquired a 33% equity interest in our subsidiary that owns the pipeline (effective July 31, 2019). As a result, we received a $440.7 million cash payment from Altus, which will be reflected as a contribution from noncontrolling interests as presented on our Unaudited Condensed Statements of Consolidated Cash Flows for the three and nine months ended September 30, 2019.

In February 2019, the 24-inch diameter mainline segment of the 658-mile Shin Oak NGL Pipeline from Orla, Texas to Mont Belvieu was placed into limited commercial service with an initial transportation capacity of 250 MBPD. The related 20-inch diameter Waha lateral was completed during the second quarter of 2019. Supported by long-term customer commitments, the Shin Oak NGL Pipeline will ultimately provide up to 550 MBPD of transportation capacity, which is expected to be available in the fourth quarter of 2019.

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Enterprise Begins Service at Orla III; Update on Mentone Plant

In July 2019, we announced that the third processing train (“Orla III”) at our Orla cryogenic natural gas processing plant had commenced operations. Completion of Orla III increased our natural gas processing capacity at Orla to 900 MMcf/d and our equity NGL production rate in excess of 140 MBPD. Overall, we now have the capability to process up to 1.3 Bcf/d of natural gas and produce approximately 200 MBPD of NGLs in the Delaware Basin.

In October 2018, we announced that construction of our Mentone cryogenic natural gas processing plant had commenced. The Mentone plant, which is located in Loving County, Texas, is expected to have the capacity to process 300 MMcf/d of natural gas and extract more than 40 MBPD of NGLs. The project is on schedule for completion in the first quarter of 2020 and is supported by a long-term acreage dedication agreement. In addition, we are actively negotiating contracts with producers to underwrite additional capacity at Mentone. When the Mentone plant is completed and placed into service, we expect to have an aggregate 1.6 Bcf/d of natural gas processing capacity and approximately 250 MBPD of NGL production from our processing plants in the Delaware Basin.

Expansion Projects at Enterprise Hydrocarbons Terminal (“EHT”)

We estimate that exports of U.S. crude oil will increase from 3 MMBPD to 8 MMBPD and that LPG exports will double from 1.4 MMBPD to 2.8 MMBPD by 2025. Much of this growth is being driven by increasing production from the Permian Basin. In response to these trends, we announced in July 2019 three new expansion projects at EHT, located on the Houston Ship Channel, that will increase our capacity to load LPG, polymer grade propylene (“PGP”) and crude oil at the terminal.

We are adding an eighth deep-water ship dock at EHT that is expected to increase our crude oil loading capacity by 840 MBPD, thereby increasing our overall nameplate crude oil loading capacity at EHT to 2.75 MMBPD, or nearly 83 MMBbls per month. The new dock is designed to accommodate a Suezmax vessel, which is the largest ship class that can navigate the Houston Ship Channel, and is scheduled to be placed into service during the fourth quarter of 2020.

Our current nameplate loading capacity for LPG at EHT is approximately 660 MBPD, with an additional 175 MBPD of loading capacity expected to be placed into service during late third quarter of 2019. The expansion project announced in July 2019 is expected to increase our LPG loading capacity at EHT by an additional 260 MBPD and be placed into service during the third quarter of 2020. When this latest expansion project is completed, EHT will have a nameplate LPG loading capacity of approximately 1.1 MMBPD, or 33 MMBbls per month.

Our current loading capacity at EHT for PGP is approximately 2,500 barrels per hour, or 60 MBPD, of semi-refrigerated product. In response to record international demand for PGP, we will expand our export capabilities at EHT to accommodate an incremental 2,800 barrels per hour, or approximately 67 MBPD, of semi- or fully-refrigerated PGP. With the addition of fully refrigerated volumes, this expansion project will enable EHT to co-load fully refrigerated PGP and LPG volumes onto the same vessel. Our PGP export expansion project is expected to be placed into service during the fourth quarter of 2020.

Enterprise to Extend Ethylene Pipeline Network

In May 2019, we announced plans to expand our ethylene pipeline and logistics system by constructing the Baymark ethylene pipeline in South Texas, which is a leading growth area for new ethylene crackers and related facilities. The Baymark pipeline will originate in the Bayport, Texas area of southeast Harris County and extend approximately 90 miles to Markham, Texas in Matagorda County. The pipeline is supported by long-term customer commitments and is scheduled to begin service in the fourth quarter of 2020. We will be the majority owner and operator of the new pipeline.

The Baymark pipeline will feature access to a high-capacity ethylene storage well that is under development at our Mont Belvieu complex, along with connectivity to our ethylene export terminal currently under construction at Morgan’s Point. The storage well is expected to be completed in the third quarter of 2019 and have a capacity of 600 million pounds of ethylene. Our ethylene export terminal at Morgan’s Point will have the capacity to export approximately 2.2 billion pounds of ethylene per year and is expected to begin service in the fourth quarter of 2019.

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Enterprise Begins Full Service on Midland-to-ECHO 2 Pipeline System

In April 2019, our Midland-to-ECHO 2 Pipeline System, which provides us with approximately 200 MBPD of incremental crude oil transportation capacity from the Permian Basin to markets in the Houston area, was placed into full service. The pipeline had been in limited commercial service since February 2019. The Midland-to-ECHO 2 Pipeline System originates at our Midland terminal and extends 440 miles to our Sealy storage terminal, with volumes arriving at Sealy transported to our ECHO terminal using the Rancho II pipeline, which is a component of our South Texas Crude Oil Pipeline System. We own and operate the Midland-to-ECHO 2 Pipeline System.

We converted a portion of our Seminole NGL Pipeline system from NGL service to crude oil service to create the Midland-to-Sealy segment of the Midland-to-ECHO 2 Pipeline System. The conversion project was supported by a 10.75-year transportation contract with firm demand fees. We have the ability to convert this pipeline back to NGL service should market and physical takeaway conditions warrant.

Enterprise Announces $2 Billion Unit Buyback Program

Enterprise Provides 2019 Distribution Guidance

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

On July 9, 2019, we announced that the Board declared a cash distribution of $0.4400 per common unit with respect to the second quarter of 2019. This distribution will be paid on August 13, 2019 to unitholders of record as of the close of business on July 31, 2019.

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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	Indicative Gas
	Natural			Normal		Natural	Grade	Grade	Processing
	Gas,	Ethane,	Propane,	Butane,	Isobutane,	Gasoline,	Propylene,	Propylene,	Gross Spread
	$/MMBtu	$/gallon	$/gallon	$/gallon	$/gallon	$/gallon	$/pound	$/pound	$/gallon
	(1)	(2)	(2)	(2)	(2)	(2)	(3)	(3)	(4)
2018 by quarter:
1st Quarter	$3.01	$0.25	$0.85	$0.96	$1.00	$1.41	$0.53	$0.33	$0.40
2nd Quarter	$2.80	$0.29	$0.87	$1.00	$1.20	$1.53	$0.52	$0.37	$0.47
3rd Quarter	$2.91	$0.43	$0.99	$1.21	$1.25	$1.54	$0.60	$0.45	$0.58
4th Quarter	$3.65	$0.35	$0.79	$0.91	$0.94	$1.22	$0.51	$0.35	$0.34
2018 Averages	$3.09	$0.33	$0.88	$1.02	$1.10	$1.43	$0.54	$0.38	$0.45

2019 by quarter:
1st Quarter	$3.15	$0.30	$0.67	$0.82	$0.85	$1.16	$0.38	$0.24	$0.31
2nd Quarter	$2.64	$0.21	$0.55	$0.63	$0.65	$1.21	$0.37	$0.24	$0.25
2019 Averages	$2.90	$0.26	$0.61	$0.73	$0.75	$1.19	$0.38	$0.24	$0.28

(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.
(4)	The “Indicative Gas Processing Spread” represents a generic estimate of the gross economic benefit from extracting NGLs from natural gas production based on certain pricing assumptions. Specifically, it is the amount by which the assumed economic value of a composite gallon of NGLs at Mont Belvieu, Texas exceeds the value of the equivalent amount of energy in natural gas at Henry Hub, Louisiana (as presented in the table above). The indicative spread does not consider the operating costs incurred by a natural gas processing plant to extract the NGLs nor the transportation and fractionation costs to deliver the NGLs to market. In addition, the actual gas processing spread earned at each plant is determined by regional pricing and extraction dynamics. As presented in the table above, the indicative spread assumes that a gallon of NGLs is comprised of 47% ethane, 28% propane, 9% normal butane, 6% isobutane and 10% natural gasoline. The value of an equivalent amount of energy in natural gas to one gallon of NGLs is assumed to be 8.4% of the price of a MMBtu of natural gas at Henry Hub.

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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)
2018 by quarter:
1st Quarter	$62.87	$62.51	$65.47	$65.79
2nd Quarter	$67.88	$59.93	$72.38	$72.97
3rd Quarter	$69.50	$55.28	$73.67	$74.28
4th Quarter	$58.81	$53.64	$66.34	$66.20
2018 Averages	$64.77	$57.84	$69.47	$69.81

2019 by quarter:
1st Quarter	$54.90	$53.70	$61.19	$62.35
2nd Quarter	$59.81	$57.62	$66.47	$67.07
2019 Averages	$57.36	$55.66	$63.83	$64.71

(1)	WTI prices are based on commercial index prices at Cushing, Oklahoma as measured by the NYMEX.
(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, which fluctuate for a variety of reasons including supply and demand imbalances and geopolitical tensions. The weighted-average indicative market price for NGLs was $0.47 per gallon in the second quarter of 2019 versus $0.69 per gallon during the second quarter of 2018. Likewise, the weighted-average indicative market price for NGLs was $0.52 per gallon during the six months ended June 30, 2019 compared to $0.67 per gallon during the same period in 2018.

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 13 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.

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Income Statement Highlights

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

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
Revenues	$	8,276.3		$	8,467.5		$	16,819.8		$	17,766.0
Costs and expenses:
Operating costs and expenses:
Cost of sales		5,609.4			6,391.9			11,445.0			13,532.3
Other operating costs and expenses		723.8			719.8			1,452.6			1,407.4
Depreciation, amortization and accretion expenses		462.8			425.3			913.7			819.6
Net gains attributable to asset sales		(2.1	)		(0.9	)		(2.5	)		(1.4	)
Asset impairment and related charges		7.0			15.9			11.8			16.8
Total operating costs and expenses		6,800.9			7,552.0			13,820.6			15,774.7
General and administrative costs		52.5			51.4			104.7			104.4
Total costs and expenses		6,853.4			7,603.4			13,925.3			15,879.1
Equity in income of unconsolidated affiliates		137.4			122.3			292.0			238.0
Operating income		1,560.3			986.4			3,186.5			2,124.9
Interest expense		(290.1	)		(274.6	)		(567.3	)		(526.7	)
Change in fair market value of Liquidity Option Agreement		(26.6	)		(8.9	)		(84.4	)		(16.4	)
Gain on step acquisition of unconsolidated affiliate		–			2.4			–			39.4
Other, net		2.6			0.3			4.1			1.0
Provision for income taxes		(9.7	)		(18.4	)		(22.0	)		(23.5	)
Net income		1,236.5			687.2			2,516.9			1,598.7
Net income attributable to noncontrolling interests		(21.8	)		(13.4	)		(41.7	)		(24.2	)
Net income attributable to limited partners	$	1,214.7		$	673.8		$	2,475.2		$	1,574.5

Revenues

The following table presents each business segment’s contribution to consolidated revenues for the periods indicated (dollars in millions):

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2019		2018		2019		2018
NGL Pipelines & Services:
Sales of NGLs and related products	$	2,659.4	$	2,610.9	$	5,330.6	$	5,426.3
Midstream services		625.3		662.8		1,268.5		1,260.7
Total		3,284.7		3,273.7		6,599.1		6,687.0
Crude Oil Pipelines & Services:
Sales of crude oil		2,531.7		2,532.2		4,860.1		5,873.9
Midstream services		334.9		249.0		613.8		478.2
Total		2,866.6		2,781.2		5,473.9		6,352.1
Natural Gas Pipelines & Services:
Sales of natural gas		531.4		532.5		1,187.1		1,092.5
Midstream services		287.9		260.3		559.7		505.1
Total		819.3		792.8		1,746.8		1,597.6
Petrochemical & Refined Products Services:
Sales of petrochemicals and refined products		1,087.7		1,413.4		2,568.3		2,702.7
Midstream services		218.0		206.4		431.7		426.6
Total		1,305.7		1,619.8		3,000.0		3,129.3
Total consolidated revenues	$	8,276.3	$	8,467.5	$	16,819.8	$	17,766.0

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Second Quarter of 2019 Compared to Second Quarter of 2018. Total revenues for the second quarter of 2019 decreased $191.2 million when compared to the second quarter of 2018 primarily due to a net $278.8 million decrease in marketing revenues. Revenues from the marketing of petrochemicals and refined products decreased $325.7 million quarter-to-quarter primarily due to lower sales margins, which accounted for a $212.2 million decrease, and lower sales volumes, which resulted in an additional $113.5 million decrease. Revenues from the marketing of NGLs increased a net $48.5 million quarter-to-quarter primarily due to higher sales volumes, which accounted for a $478.5 million increase, partially offset by lower sales margins, which resulted in a $430.0 million decrease.

Revenues from midstream services for the second quarter of 2019 increased $87.6 million when compared to the second quarter of 2018. Midstream service revenues from our pipeline assets increased $97.7 million quarter-to-quarter primarily due to strong demand for transportation services in Texas, including on our Midland-to-ECHO 1 and 2 Pipeline Systems, which contributed a combined $64.7 million increase. Storage revenues increased $18.2 million quarter-to-quarter primarily at our Mont Belvieu storage complex. NGL fractionation revenues increased $12.3 million quarter-to-quarter primarily due to higher fractionation volumes at our Mont Belvieu NGL fractionation complex. Terminal revenues increased $11.9 million quarter-to-quarter primarily due to an increase in loading volumes at EHT. Midstream service revenues from our natural gas processing plants decreased $59.5 million quarter-to-quarter primarily due to lower processing fees, partially offset by contributions from our Orla plant, the first two processing trains of which commenced operations in May and October 2018, respectively, and generated $59.6 million of revenue.

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018. Total revenues for the six months ended June 30, 2019 decreased $946.2 million when compared to the six months ended June 30, 2018 primarily due to a $1.15 billion decrease in marketing revenues. Revenues from the marketing of crude oil decreased a net $1.01 billion period-to-period primarily due to lower sales volumes, which accounted for a $1.28 billion decrease, partially offset by higher sales margins, which resulted in a $268.7 million increase. Revenues from the marketing of petrochemicals and refined products decreased a net $134.4 million period-to-period primarily due to lower sales margins, which resulted in a $451.7 million decrease, partially offset by higher sales volumes, which accounted for a $317.3 million increase.

Revenues from midstream services for the six months ended June 30, 2019 increased $203.1 million when compared to the six months ended June 30, 2018. Midstream service revenues from our pipeline assets increased $186.4 million period-to-period primarily due to strong demand for transportation services in Texas and on the Appalachia-to-Texas Express (“ATEX”) pipeline. Our Midland-to-ECHO 1 and 2 Pipeline Systems, contributed a combined $114.3 million of this increase. NGL fractionation revenues increased $35.6 million period-to-period primarily due to higher fractionation volumes at our Mont Belvieu NGL fractionation complex. Storage revenues increased $30.4 million period-to-period primarily at our Mont Belvieu storage complex. Terminal revenues increased $17.0 million period-to-period primarily due to an increase in loading volumes at EHT. Midstream service revenues from our natural gas processing plants decreased $80.3 million period-to-period primarily due to lower processing fees, partially offset by contributions from our Orla plant, which accounted for a $109.0 million increase in revenues.

Operating costs and expenses

Second Quarter of 2019 Compared to Second Quarter of 2018. Total operating costs and expenses for the second quarter of 2019 decreased $751.1 million when compared to the second quarter of 2018 primarily due to lower cost of sales. The cost of sales associated with our marketing of crude oil and petrochemicals and refined products decreased $730.5 million quarter-to-quarter primarily due to lower purchase prices, which accounted for a $397.4 million decrease, and lower sales volumes, which accounted for an additional $333.1 million decrease.

Depreciation, amortization and accretion expense increased $37.5 million quarter-to-quarter primarily due to assets placed into full or limited service since the second quarter of 2018 (e.g., the Shin Oak NGL Pipeline and Midland-to-ECHO 2 Pipeline System). Non-cash asset impairment charges decreased $8.9 million quarter-to-quarter.

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018. Total operating costs and expenses for the six months ended June 30, 2019 decreased $1.95 billion when compared to the six months ended June 30, 2018 primarily due to lower cost of sales. The cost of sales associated with our marketing of crude oil decreased $1.75 billion period-to-period primarily due to lower sales volumes, which accounted for a $1.05 billion decrease, and lower

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purchase prices, which accounted for an additional $697.2 million decrease. The cost of sales associated with our marketing of petrochemicals and refined products decreased a net $125.6 million period-to-period primarily due to lower purchase prices, which accounted for a $393.8 million decrease, partially offset by higher sales volumes, which accounted for a $268.2 million increase.

Other operating costs and expenses for the six months ended June 30, 2019 increased a net $45.2 million when compared to the six months ended June 30, 2018 primarily due to higher maintenance and chemical expenses, ad valorem taxes, and employee compensation costs of $77.8 million. These costs were partially offset by $33.9 million of expense in the six months ended June 30, 2018 in connection with our earnings allocation arrangement with an affiliate of Western Midstream Partners, LP (“Western”) involving the Midland-to-ECHO 1 Pipeline System.

Depreciation, amortization and accretion expense increased $94.1 million period-to-period primarily due to assets placed into full or limited service since the second quarter of 2018. Non-cash asset impairment charges decreased $5.0 million period-to-period.

General and administrative costs

General and administrative costs for the three and six months ended June 30, 2019 increased $1.1 million and $0.3 million, respectively, when compared to the same periods in 2018.

Equity in income of unconsolidated affiliates

Equity income from our unconsolidated affiliates for the three and six months ended June 30, 2019 increased $15.1 million and $54.0 million, respectively, when compared to the same periods in 2018 primarily due to increases in earnings from our investments in crude oil pipelines.

Operating income

Operating income for the three and six months ended June 30, 2019 increased $573.9 million and $1.06 billion, respectively, when compared to the same periods in 2018 due to the previously described quarter-to-quarter and period-to-period changes in revenues, operating costs and expenses, general and administrative costs and equity in income of unconsolidated affiliates.

Interest expense

The following table presents the components of our consolidated interest expense for the periods indicated (dollars in millions):

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
Interest charged on debt principal outstanding	$	307.4		$	297.8		$	614.9		$	589.8
Impact of interest rate hedging program, including related amortization (1)		8.7			(2.5	)		7.6			1.2
Interest costs capitalized in connection with construction projects (2)		(32.8	)		(27.1	)		(69.0	)		(85.3	)
Other (3)		6.8			6.4			13.8			21.0
Total	$	290.1		$	274.6		$	567.3		$	526.7

(1)	Amount presented for the six months ended June 30, 2019 includes $9.8 million of swaption premium income. We did not recognize any swaption premium income for the three months ended June 30, 2019. Amount presented for the three and six months ended June 30, 2018 includes $11.8 million and $19.0 million, respectively, 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 six months ended June 30, 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.

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Interest charged on debt principal outstanding, which is the primary driver of interest expense, increased a net $9.6 million quarter-to-quarter primarily due to increased debt principal amounts outstanding during the second quarter of 2019, which accounted for an $11.5 million increase, partially offset by the effect of lower overall interest rates during the second quarter of 2019, which accounted for a $1.9 million decrease. Our weighted-average debt principal balance for the second quarter of 2019 was $27.1 billion compared to $25.97 billion for the second quarter of 2018.

For the six months ended June 30, 2019, interest charged on debt principal outstanding increased a net $25.1 million period-to-period primarily due to increased debt principal amounts outstanding during the six months ended June 30, 2019, which accounted for a $29.3 million increase, partially offset by the effect of lower overall interest rates during the six months ended June 30, 2019, which accounted for a $4.2 million decrease. Our weighted-average debt principal balance for the six months ended June 30, 2019 was $26.9 billion compared to $25.6 billion for the six months ended June 30, 2018.

In general, our debt principal balances have increased over time due to the partial debt financing of our capital investments. For additional information regarding our debt obligations, see Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report. For a discussion of our capital projects, see “Capital Investments” within this Part I, Item 2.

Change in fair value of Liquidity Option Agreement

We recognize non-cash expense associated with accretion and changes in management estimates that affect our valuation of the Liquidity Option Agreement. For the three and six months ended June 30, 2019, expense resulting from changes in fair value of the Liquidity Option Agreement increased $17.7 million and $68.0 million, respectively, when compared to the same periods in 2018. Expense recognized during the first six months of 2019 is primarily due a decrease in the applicable midstream industry weighted-average cost of capital, which is used as the discount factor in determining the present value of the liability, since December 31, 2018. For additional information regarding the Liquidity Option Agreement, see Note 15 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

Gain on step acquisition of unconsolidated affiliate

Upon our acquisition of the remaining 50% member interest in Delaware Basin Gas Processing LLC (“Delaware Processing”) in March 2018, our existing equity investment in Delaware Processing was remeasured to fair value resulting in the recognition of a non-cash gain of $39.4 million for the six months ended June 30, 2018.

Income taxes

Provision for income taxes primarily reflects our state tax obligations under the Revised Texas Franchise Tax (the “Texas Margin Tax”). Our provision for income taxes for the three and six months ended June 30, 2019 decreased $8.7 million and $1.5 million, respectively, when compared to the same periods in 2018. Our partnership is not subject to U.S. federal income tax; however, our partners are individually responsible for paying federal income tax on their share of our taxable income.

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Business Segment Highlights

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 June 30,					For the Six Months Ended June 30,
	2019			2018		2019			2018
Gross operating margin by segment:
NGL Pipelines & Services	$	966.3		$	913.7	$	1,925.5		$	1,798.6
Crude Oil Pipelines & Services		513.2			52.8		1,175.5			272.8
Natural Gas Pipelines & Services		301.8			213.4		566.1			411.3
Petrochemical & Refined Products Services		304.9			281.8		547.5			553.7
Total segment gross operating margin (1)		2,086.2			1,461.7		4,214.6			3,036.4
Net adjustment for shipper make-up rights		(5.7	)		16.4		(0.4	)		27.9
Total gross operating margin (non-GAAP)	$	2,080.5		$	1,478.1	$	4,214.2		$	3,064.3

(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. Our calculation of gross operating margin may or may not be comparable to similarly titled measures used by other companies. Segment gross operating margin 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 “Income Statement Highlights” within this Part I, 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 June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
Operating income (GAAP)	$	1,560.3		$	986.4		$	3,186.5		$	2,124.9
Adjustments to reconcile operating income to total gross operating margin (addition or subtraction indicated by sign):
Depreciation, amortization and accretion expense in operating costs and expenses		462.8			425.3			913.7			819.6
Asset impairment and related charges in operating costs and expenses		7.0			15.9			11.8			16.8
Net gains attributable to asset sales in operating costs and expenses		(2.1	)		(0.9	)		(2.5	)		(1.4	)
General and administrative costs		52.5			51.4			104.7			104.4
Total gross operating margin (non-GAAP)	$	2,080.5		$	1,478.1		$	4,214.2		$	3,064.3

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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In March 2019, a fire occurred at a tank farm owned by a third party, Intercontinental Terminals Company (“ITC”), that is located on the Houston Ship Channel. The resulting fire lasted for several days and the channel was temporarily closed to regular ship and barge traffic for more than one week due to fire-related contamination of the waterway. Once the issues were mitigated, traffic on the Houston Ship Channel returned to normal levels in early April 2019. The Houston Ship Channel also experienced several periods of delays and restrictions due to fog in the first quarter of 2019. We estimate that gross operating margin for the first quarter of 2019 was reduced by approximately $40 million related to the impact of these events; however, substantially all of this gross operating margin was recovered in the second quarter of 2019 as delayed ships and barges were rescheduled.

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 June 30,				For the Six Months Ended June 30,
	2019		2018		2019		2018
Segment gross operating margin:
Natural gas processing and related NGL marketing activities	$	248.6	$	309.7	$	541.3	$	558.2
NGL pipelines, storage and terminals		588.7		465.4		1,146.0		974.7
NGL fractionation		129.0		138.6		238.2		265.7
Total	$	966.3	$	913.7	$	1,925.5	$	1,798.6

Selected volumetric data:
Equity NGL production (MBPD) (1)		144		164		150		164
Fee-based natural gas processing (MMcf/d) (2)		5,233		4,624		5,266		4,554
NGL pipeline transportation volumes (MBPD)		3,587		3,408		3,523		3,347
NGL marine terminal volumes (MBPD)		625		597		584		586
NGL fractionation volumes (MBPD)		1,000		927		984		907

(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

Second Quarter of 2019 Compared to Second Quarter of 2018. Gross operating margin from natural gas processing and related NGL marketing activities for the second quarter of 2019 decreased $61.1 million when compared to the second quarter of 2018. Gross operating margin from our Meeker, Pioneer and Chaco natural gas processing plants decreased $43.7 million quarter-to-quarter primarily due to lower average processing margins. On a combined basis, fee-based natural gas processing volumes at these plants increased 97 MMcf/d and equity NGL production volumes decreased 16 MBPD quarter-to-quarter. Gross operating margin from our NGL marketing activities decreased a net $18.5 million quarter-to-quarter primarily due to lower average sales margins, which accounted for a $59.7 million decrease, partially offset by higher sales volumes, which accounted for a $41.1 million increase. Results from marketing strategies that optimize our export, plant and storage assets decreased a combined $24.0 million quarter-to-quarter, partially offset by a $13.0 million increase in earnings related to the optimization of our transportation assets. In addition, results from NGL marketing decreased $7.5 million quarter-to-quarter due to non-cash, mark-to-market activity.

Gross operating margin from our Permian Basin natural gas processing plants increased a net $5.3 million quarter-to-quarter primarily due to higher fee-based processing volumes, which accounted for a $15.9 million increase, partially offset by lower average processing fees, which accounted for a $9.6 million decrease. Fee-based processing volumes at our Permian Basin natural gas processing plants increased 385 MMcf/d quarter-to-quarter primarily due to our Orla natural gas processing facility, which commenced operations at its first and second processing trains in May and October 2018, respectively.

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Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018. Gross operating margin from natural gas processing and related NGL marketing activities for the six months ended June 30, 2019 decreased $16.9 million when compared to the six months ended June 30, 2018.

Gross operating margin from our Rockies natural gas processing plants (including Meeker, Pioneer and Chaco) decreased a combined $61.1 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $48.3 million decrease, and lower deficiency and processing fees, which accounted for an additional $12.7 million decrease. On a combined basis, fee-based natural gas processing volumes at these plants increased 119 MMcf/d and equity NGL production volumes decreased 18 MBPD period-to-period.

Gross operating margin from our NGL marketing activities increased a net $6.2 million period-to-period primarily due to higher sales volumes, which accounted for a $37.3 million increase, partially offset by lower average sales margins, which accounted for a $31.8 million decrease. Results from marketing strategies that optimize our transportation assets increased $43.8 million period-to-period, partially offset by lower earnings from the optimization of our storage and plant assets, which accounted for a combined decrease of $31.2 million. In addition, results from NGL marketing decreased $3.8 million period-to-period due to non-cash, mark-to-market activity.

Gross operating margin from our Permian Basin natural gas processing plants increased $24.5 million period-to-period primarily due to higher fee-based processing volumes. Fee-based processing volumes at our Permian Basin natural gas processing plants increased 390 MMcf/d period-to-period primarily due to the start-up of our Orla natural gas processing facility. Gross operating margin from our South Texas natural gas processing plants increased $12.5 million period-to-period primarily due to higher deficiency fees. Fee-based natural gas processing volumes and equity NGL production at our South Texas plants decreased 207 MMcf/d and 15 MBPD, respectively. Gross operating margin at our BTA Processing Plants increased $5.7 million primarily due to higher average processing margins.

NGL pipelines, storage and terminals

Second Quarter of 2019 Compared to Second Quarter of 2018. Gross operating margin from our NGL pipelines, storage and terminal assets during the second quarter of 2019 increased $123.3 million when compared to the second quarter of 2018.

Gross operating margin from our underground storage facilities at the Mont Belvieu hub increased $37.7 million quarter-to-quarter primarily due to higher throughput and handling fees, which accounted for a $22.4 million increase, and higher storage fees, which accounted for an additional $10.4 million increase.

The Shin Oak NGL Pipeline, which was placed into limited commercial service in February 2019, contributed $35.2 million to gross operating margin for the second quarter of 2019. The Shin Oak NGL pipeline has been operating at or near its current transportation capacity of 250 MBPD, which includes offloads from affiliate pipelines and 120 MBPD of direct tariff movements for the second quarter of 2019. Gross operating margin from our Chaparral NGL Pipeline increased $10.0 million quarter-to-quarter primarily due to higher transportation volumes of 43 MBPD.

Gross operating margin from our Dixie Pipeline and related terminals increased a combined $15.5 million quarter-to-quarter primarily due to lower maintenance and other operating costs, which accounted for a $9.6 million increase, and higher transportation volumes of 46 MBPD, which accounted for an additional $4.9 million increase, resulting from a capacity expansion project. Gross operating margin from our South Louisiana NGL Pipeline System increased $6.4 million quarter-to-quarter primarily due to an 85 MBPD increase in transportation volumes. Gross operating margin from our Aegis Pipeline increased $5.0 million quarter-to-quarter primarily due to higher transportation volumes of 13 MBPD.

Gross operating margin from EHT increased $11.3 million quarter-to-quarter primarily due to higher LPG export volumes, which increased 63 MBPD. Loading volumes at EHT rebounded during the second quarter of 2019 from the adverse effects of temporary closures and restrictions that impacted the Houston Ship Channel during the first quarter of 2019.

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Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018. Gross operating margin from our NGL pipelines, storage and terminal assets during the six months ended June 30, 2019 increased $171.3 million when compared to the six months ended June 30, 2018.

Gross operating margin from our Mont Belvieu storage facility increased $66.2 million period-to-period primarily due to higher throughput and handling fees, which accounted for a $48.3 million increase, and higher storage fees, which accounted for an additional $16.3 million increase.

The Shin Oak NGL Pipeline contributed $43.2 million to gross operating margin for the six months ended June 30, 2019. The Shin Oak NGL pipeline has been operating at near its current transportation capacity of 250 MBPD, which

includes offloads from affiliate pipelines and 110 MBPD of direct tariff movements since being placed into limited commercial service in February 2019.

Gross operating margin from our Dixie Pipeline and related terminals increased a combined $14.9 million period-to-period primarily due to lower maintenance and other operating costs, which accounted for a $10.7 million increase, and higher transportation volumes of 17 MBPD, which accounted for an additional $2.8 million increase. Gross operating margin from our South Louisiana NGL Pipeline System increased $9.6 million period-to-period primarily due to a 77 MBPD increase in transportation volumes.

Gross operating margin from EHT increased $5.9 million period-to-period primarily due to higher average loading fees, which accounted for a $2.5 million increase, and higher LPG exports of 8 MBPD, which accounted for an additional $1.4 million increase.

NGL fractionation

Second Quarter of 2019 Compared to Second Quarter of 2018. Gross operating margin from NGL fractionation for the second quarter of 2019 decreased $9.6 million when compared to the second quarter of 2018.

Gross operating margin from our South Texas NGL fractionators decreased $6.3 million quarter-to-quarter primarily due to major maintenance activities initiated at our Shoup fractionator during the second quarter of 2019. NGL fractionation volumes at our South Texas NGL fractionators decreased 8 MBPD quarter-to-quarter. Gross operating margin at our Hobbs NGL fractionator decreased $3.7 million quarter-to-quarter primarily due to lower volumes, which decreased 4 MBPD. Gross operating margin from our Mont Belvieu NGL fractionation complex increased $3.0 million quarter-to-quarter primarily due to higher fractionation volumes, which increased 41 MBPD (net to our interest) primarily due to the start-up of our ninth NGL fractionator in May 2018.

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018. Gross operating margin from NGL fractionation for the six months ended June 30, 2019 decreased $27.5 million when compared to the six months ended June 30, 2018. Gross operating margin at our Hobbs NGL fractionator decreased $24.8 million period-to-period primarily due to the costs of major maintenance activities completed in February 2019, which accounted for a $13.7 million decrease, and associated lower fractionation volumes, which accounted for an additional $11.1 million decrease. NGL fractionation volumes at Hobbs decreased 12 MBPD period-to-period. Gross operating margin at our South Texas NGL fractionators decreased $4.8 million period-to-period primarily due to major maintenance activities initiated at our Shoup fractionator during the second quarter of 2019. NGL fractionation volumes at our South Texas NGL fractionators decreased 2 MBPD period-to-period.

Gross operating margin from our Mont Belvieu NGL fractionation complex increased $7.1 million period-to-period primarily due to higher fractionation volumes, which increased 50 MBPD (net to our interest) primarily due to the start-up of our ninth NGL fractionator in May 2018. Our Tebone NGL fractionator, which was restarted in February 2019 in light of regional demand for fractionation services, contributed 17 MBPD of fractionation volumes during the six months ended June 30, 2019 results. Gross operating margin from Tebone for the six months ended June 30, 2019 was a loss of $3.0 million primarily due to start-up expenses.

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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 June 30,					For the Six Months Ended June 30,
	2019		2018			2019		2018
Midland-to-ECHO 1 Pipeline System and related business activities, excluding associated non-cash mark-to-market results	$	109.6	$	87.9		$	209.4	$	147.8
Mark-to-market gain (loss) attributable to the Midland-to-ECHO 1 Pipeline System		14.0		(309.9	)		81.2		(423.9	)
Total Midland-to-ECHO 1 Pipeline System and related business activities		123.6		(222.0	)		290.6		(276.1	)
Other crude oil pipelines, terminals and related marketing results		389.6		274.8			884.9		548.9
Segment gross operating margin	$	513.2	$	52.8		$	1,175.5	$	272.8

Selected volumetric data:
Crude oil pipeline transportation volumes (MBPD)		2,378		2,002			2,310		1,998
Crude oil marine terminal volumes (MBPD)		985		802			935		718

Second Quarter of 2019 Compared to Second Quarter of 2018. Gross operating margin from our Crude Oil Pipelines & Services segment for the second quarter of 2019 increased $460.4 million when compared to the second quarter of 2018.

Gross operating margin from our Midland-to-ECHO 1 Pipeline System and related business activities increased $345.6 million quarter-to-quarter primarily due to changes in non-cash mark-to-market earnings, which were a $14.0 million benefit in the second quarter of 2019 compared to a $309.9 million loss in the second quarter of 2018. Gross operating margin for the second quarter of 2018 was also reduced by $9.8 million in connection with the expected allocation of pipeline earnings to Western upon closing of their acquisition of a 20% ownership interest in Whitethorn Pipeline Company LLC (“Whitethorn”), which owns a majority of the Midland-to-ECHO 1 Pipeline System. Western acquired its interest in Whitethorn in June 2018. Transportation volumes for the Midland-to-ECHO 1 Pipeline System increased 47 MBPD quarter-to-quarter (net to our interest).

Mark-to-market earnings attributable to the Midland-to-ECHO 1 Pipeline System are associated with the hedging of crude oil market price differentials (basis spreads) between the Midland and Houston area markets. These hedges, which were entered into throughout 2017, served to lock in a positive per barrel 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 volume hedged 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 on the Midland-to-ECHO 1 Pipeline System as customer commitment volumes ramp up to peak levels. The mark-to-market loss for the second quarter of 2018 reflected an increase in the basis spread between the Midland and Houston markets since March 31, 2018 to an average of $14.83 per barrel through 2020 relative to our average hedged amount of $2.62 per barrel across these same periods (as of June 30, 2018). The mark-to-market gain for the second quarter of 2019 reflects a decrease in the basis spread between the Midland and Houston markets since March 31, 2019 to an average of $3.57 per barrel through 2020 relative to our average hedged amount of $2.73 per barrel across these same periods (as of June 30, 2019).

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 would convert that physical margin to the average $2.73 per barrel spread of the financial hedges. The basis spread between the Midland and Houston markets continues to fluctuate. For information regarding our commodity hedging activities, see Note 13 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

Gross operating margin from other crude oil marketing activities increased $18.3 million quarter-to-quarter primarily due to higher average sales margins.

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Gross operating margin from our Midland-to-ECHO 2 Pipeline System, which commenced full commercial service during the second quarter of 2019, was $28.1 million on transportation volumes of 209 MBPD. Gross operating margin from our West Texas System and equity investment in the Eagle Ford Crude Oil Pipeline System increased a combined $23.8 million quarter-to-quarter primarily due to higher transportation volumes of 95 MBPD (net to our interest).

Gross operating margin from our equity investment in the Seaway Pipeline increased $20.4 million quarter-to-quarter primarily due to higher transportation fees, which accounted for a $23.1 million increase, and higher transportation volumes, which accounted for an additional $14.8 million increase, partially offset by higher operating costs, which accounted for a $15.7 million decrease. Transportation volumes on the Seaway Pipeline increased 88 MBPD quarter-to-quarter (net to our interest) primarily due to an expansion of the Longhaul System that was completed in the first quarter of 2019. Volumes at Seaway’s Texas City and Freeport marine terminals decreased a combined 89 MBPD (net to our interest) quarter-to-quarter.

Lastly, gross operating margin from crude oil activities at EHT increased $23.3 million quarter-to-quarter primarily due to higher net export volumes of 261 MBPD. Loading volumes at EHT rebounded during the second quarter of 2019 from the adverse effects of temporary closures and restrictions that impacted the Houston Ship Channel during the first quarter of 2019.

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018. Gross operating margin from our Crude Oil Pipelines & Services segment for the six months ended June 30, 2019 increased $902.7 million when compared to the six months ended June 30, 2018.

Gross operating margin from our Midland-to-ECHO 1 Pipeline System and related business activities increased $566.7 million period-to-period primarily due to changes in non-cash mark-to-market earnings, which were an $81.2 million benefit in the six months ended June 30, 2019 compared to a $423.9 million loss in the six months ended June 30, 2018. As discussed earlier, mark-to-market earnings attributable to the Midland-to-ECHO 1 Pipeline System are associated with the hedging of crude oil market price differentials (basis spreads) between the Midland and Houston area markets. Gross operating margin for the six months ended June 30, 2018 was also reduced by $33.9 million in connection with the expected allocation of pipeline earnings to Western upon closing of their acquisition of a 20% ownership interest in Whitethorn in June 2018. Transportation volumes for the Midland-to-ECHO 1 Pipeline System increased 53 MBPD period-to-period (net to our interest).

Gross operating margin from other crude oil marketing activities increased $150.8 million primarily due to higher average sales margins, which accounted for a $102.8 million increase, and higher non-cash mark-to-market earnings, which accounted for an additional $47.6 million increase. Non-cash mark-to-market earnings for this business was a gain of $4.0 million during the six months ended June 30, 2019 compared to a loss of $43.6 million during the six months ended June 30, 2018. The higher crude oil marketing earnings relate to higher market price differentials for crude oil between the Permian Basin region, Cushing hub and Gulf Coast markets.

Gross operating margin from our West Texas System and equity investment in the Eagle Ford Crude Oil Pipeline System increased a combined $51.3 million period-to-period primarily due to higher transportation volumes of 74 MBPD (net to our interest). Gross operating margin from our Midland-to-ECHO 2 Pipeline System was $45.5 million on transportation volumes of 185 MBPD.

Gross operating margin from our equity investment in the Seaway Pipeline increased $42.8 million period-to-period primarily due to higher transportation volumes, which accounted for an additional $35.1 million increase, and higher transportation fees, which accounted for a $33.6 million increase, partially offset by higher operating costs, which accounted for a $25.9 million decrease. Transportation volumes on the Seaway Pipeline increased 47 MBPD period-to-period (net to our interest). Volumes at Seaway’s Texas City and Freeport marine terminals decreased a combined 55 MBPD (net to our interest) period-to-period.

Lastly, gross operating margin from crude oil activities at EHT increased $32.9 million period-to-period primarily due to higher net export volumes of 261 MBPD.

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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 June 30,				For the Six Months Ended June 30,
	2019		2018		2019		2018
Segment gross operating margin	$	301.8	$	213.4	$	566.1	$	411.3

Selected volumetric data:
Natural gas pipeline transportation volumes (BBtus/d)		14,467		13,709		14,333		13,367

Second Quarter of 2019 Compared to Second Quarter of 2018. Gross operating margin from our Natural Gas Pipelines & Services segment for the second quarter of 2019 increased $88.4 million when compared to the second quarter of 2018. Gross operating margin from our natural gas marketing activities increased $59.0 million quarter-to-quarter primarily due to higher average sales margins, which accounted for $56.4 million of the increase.

Gross operating margin from our Texas Intrastate System increased $33.6 million quarter-to-quarter primarily due to higher capacity reservation fees. Transportation volumes on our Texas Intrastate System increased 165 BBtus/d quarter-to-quarter due in part to a capacity expansion project on the North Texas segment completed in the first quarter of 2019. Gross operating margin from our Acadian Gas System increased $10.3 million quarter-to-quarter primarily due to a legal settlement, which accounted for $11.2 million of the increase. Gross operating margin from our San Juan Gathering System decreased $7.3 million quarter-to-quarter primarily due to a 131 BBtus/d decrease in gathering volumes, which accounted for a $4.4 million decrease, and lower condensate sales, which accounted for an additional $2.0 million decrease. Gross operating margin from our Permian Basin Gathering System decreased $0.8 million quarter-to-quarter primarily due to higher operating costs, which accounted for a $4.4 million decrease, partially offset by the effect of higher gathering and condensate volumes, which accounted for a combined $3.6 million increase. Gathering volumes for the Permian Basin system increased 344 BBtus/d quarter-to-quarter.

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018. Gross operating margin from our Natural Gas Pipelines & Services segment for the six months ended June 30, 2019 increased $154.8 million when compared to the six months ended June 30, 2018. Gross operating margin from our natural gas marketing activities increased $93.0 million period-to-period primarily due to higher average sales margins, which accounted for $81.2 million of the increase.

Gross operating margin from our Texas Intrastate System increased $56.8 million period-to-period primarily due to higher capacity reservation fees. Transportation volumes on our Texas Intrastate System increased 221 BBtus/d. Gross operating margin from our Acadian Gas System increased $12.4 million period-to-period primarily due to the aforementioned legal settlement, which accounted for $11.2 million of the increase. Gross operating margin from our Haynesville Gathering System increased $11.6 million period-to-period primarily due to higher gathering and compression fee revenues. Natural gas gathering volumes on the Haynesville Gathering System increased 271 BBtus/d period-to-period. Gross operating margin from our Permian Basin Gathering System increased $6.8 million period-to-period primarily due to a 415 BBtus/d increase in gathering volumes. Gross operating margin from our San Juan Gathering System decreased $12.1 million primarily due to a 127 BBtus/d decrease in gathering volumes, which accounted for a $6.1 million decrease, and lower condensate sales, which accounted for an additional $3.4 million decrease.

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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 June 30,				For the Six Months Ended June 30,
	2019		2018		2019		2018
Segment gross operating margin:
Propylene production and related marketing activities	$	133.7	$	126.5	$	236.0	$	255.9
Butane isomerization and related DIB operations		21.2		26.1		45.2		50.8
Octane enhancement and related operations		52.5		49.5		76.8		81.9
Refined products pipelines and related activities		85.3		72.1		167.2		153.0
Marine transportation and other		12.2		7.6		22.3		12.1
Total	$	304.9	$	281.8	$	547.5	$	553.7

Selected volumetric data:
Propylene production volumes (MBPD)		104		100		97		98
Butane isomerization volumes (MBPD)		109		116		110		115
Standalone DIB processing volumes (MBPD)		96		89		94		83
Octane additive and related plant production volumes (MBPD)		29		30		28		28
Pipeline transportation volumes, primarily refined products and petrochemicals (MBPD)		672		771		740		810
Refined products and petrochemical marine terminal volumes (MBPD)		396		350		367		359

Propylene production and related marketing activities

Second Quarter of 2019 Compared to Second Quarter of 2018. Gross operating margin from propylene production and related marketing activities for the second quarter of 2019 increased $7.2 million when compared to the second quarter of 2018. Gross operating margin from our Mont Belvieu propylene splitters increased a net $6.3 million quarter-to-quarter primarily due to higher propylene sales volumes, which accounted for a $26.0 million increase, partially offset by lower average sales margins, which accounted for a $14.9 million decrease, and lower average propylene fractionation fees, which accounted for an additional $5.7 million decrease. Propylene production volumes from our splitter units and PDH facility increased a combined 4 MBPD quarter-to-quarter.

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018. Gross operating margin from propylene production and related marketing activities for the six months ended June 30, 2019 decreased $19.9 million when compared to the six months ended June 30, 2018. Gross operating margin from our Mont Belvieu propylene splitters decreased a net $44.4 million period-to-period primarily due to lower average propylene sales margins, which accounted for a $49.2 million decrease, and lower average propylene fractionation fees, which accounted for an additional $20.6 million decrease, partially offset by higher sales volumes, which accounted for an increase of $26.9 million. Gross operating margin from our PDH facility, which commenced commercial operations in April 2018, increased $21.7 million period-to-period.

Butane isomerization and related DIB operations

Second Quarter of 2019 Compared to Second Quarter of 2018. Gross operating margin from butane isomerization and deisobutanizer (“DIB”) operations for the second quarter of 2019 decreased $4.9 million when compared to the second quarter of 2018 primarily due to lower average by-product sales prices.

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018. Gross operating margin from butane isomerization and DIB operations for the six months ended June 30, 2019 decreased $5.6 million when compared to the six months ended June 30, 2018 primarily due to lower average by-product sales prices.

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Octane enhancement and related operations

Second Quarter of 2019 Compared to Second Quarter of 2018. Gross operating margin from our octane enhancement facility and high purity isobutylene plant for the second quarter of 2019 increased $3.0 million when compared to the second quarter of 2018 primarily due to higher plant sales volumes.

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018. Gross operating margin from our octane enhancement facility and high purity isobutylene plant for the six months ended June 30, 2019 decreased a net $5.1 million when compared to the six months ended June 30, 2018 primarily due to lower plant sales volumes, which accounted for a $9.0 million decrease, partially offset by higher average sales margins, which accounted for a $5.7 million increase. In addition, we incurred $1.8 million of expense during the six months ended June 30, 2019 in connection with the pre-commissioning activities of our isobutane dehydrogenation (“iBDH”) facility, which is under construction and expected to be placed into commercial service during the fourth quarter of 2019.

Refined products pipelines and related activities

Second Quarter of 2019 Compared to Second Quarter of 2018. Gross operating margin from refined products pipelines and related marketing activities for the second quarter of 2019 increased $13.2 million when compared to the second quarter of 2018. Gross operating margin from our refined products marketing activities increased a net $7.9 million quarter-to-quarter primarily due to higher average sales margin, which accounted for a $14.0 million increase, partially offset by lower sales volumes, which accounted for a $6.8 million decrease. Gross operating margin from our TE Products Pipeline increased $7.0 million quarter-to-quarter primarily due to higher deficiency fee revenues. Transportation volumes on our TE Products Pipeline decreased 104 MBPD quarter-to-quarter.

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018. Gross operating margin from refined products pipelines and related marketing activities for the six months ended June 30, 2019 increased $14.2 million when compared to the six months ended June 30, 2018. Gross operating margin from our refined products marketing activities increased $7.6 million period-to-period primarily due to higher average sales margin. Gross operating margin from our TE Products Pipeline increased $6.0 million period-to-period primarily due to higher deficiency fee revenues. Transportation volumes on our TE Products Pipeline decreased 63 MBPD period-to-period.

Marine transportation and other

Second Quarter of 2019 Compared to Second Quarter of 2018. Gross operating margin from marine transportation for the second quarter of 2019 increased $4.6 million when compared to the second quarter of 2018 primarily due to higher fees and utilization rates quarter-to-quarter.

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018. Gross operating margin from marine transportation for the six months ended June 30, 2019 increased $10.2 million when compared to the six months ended June 30, 2018 primarily due to higher fees and utilization rates period-to-period.

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 June 30, 2019, we had $4.68 billion of consolidated liquidity, which was comprised of $4.57 billion of available borrowing capacity under EPO’s revolving credit facilities and $107.3 million of unrestricted cash on hand.

We may issue equity and debt securities to assist us in meeting our future funding and liquidity requirements, including those related to capital investments. We have a universal shelf registration statement (the “2019 Shelf”) on file with the SEC which allows EPD and EPO (each on a standalone basis) to issue an unlimited amount of equity and debt securities, respectively. The 2019 Shelf replaced our prior universal shelf registration statement, which expired in May 2019.

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Common Unit Repurchases under 2019 Buyback Program

In January 2019, the Board approved the 2019 Buyback Program, which authorized the partnership to repurchase up to $2.0 billion of EPD’s common units. For additional information regarding the 2019 Buyback Program, see “Significant Recent Developments” within this Part I, Item 2.

Consolidated Debt

Issuance of $2.5 Billion of Senior Notes in July 2019

Senior Notes YY were issued at 99.955% of their principal amount and have a fixed interest rate of 3.125% per year. Senior Notes ZZ were issued at 99.792% of their principal amount and have a fixed interest rate of 4.20% per year. EPD has guaranteed the senior notes through an unconditional guarantee on an unsecured and unsubordinated basis. After taking into account EPO’s issuance of Senior Notes YY and Senior Notes ZZ in July 2019 and the expected use of net proceeds, the following table presents the scheduled contractual maturities of principal amounts of our consolidated debt obligations for the next five years and in total thereafter:

			Scheduled Maturities of Debt
	Total		Remainder of 2019		2020		2021		2022		2023		Thereafter
Principal amount of senior and junior debt obligations at June 30, 2019	$	27,121.4	$	--	$	1,500.0	$	1,325.0	$	1,400.0	$	1,250.0	$	21,646.4

Long-term and current maturities of debt reflect the classification of such obligations at June 30, 2019 after taking into consideration EPO’s issuance of senior notes in July 2019.

Partial Retirement of Junior Subordinated Notes During Second Quarter of 2019

Expected Renewal of 364-Day Revolving Credit Agreement

EPO’s 364-Day Revolving Credit Agreement is scheduled to mature in September 2019. As a result, EPO expects to renew this credit agreement during the third quarter of 2019. At June 30, 2019, there were no principal amounts outstanding under the 364-Day Revolving Credit Agreement.

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.

Credit Ratings

At August 9, 2019, 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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Issuance of Common Units under DRIP and EUPP

EPD issued and delivered a combined 2,897,990 common units in the six months ended June 30, 2019 in connection with its distribution reinvestment plan (“DRIP”) and employee unit purchase plan (“EUPP”). In total, the net cash proceeds EPD received from these issuances was $82.2 million.

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

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 Six Months Ended June 30,
	2019		2018
Net cash flows provided by operating activities	$	3,183.7	$	2,697.8
Cash used in investing activities		2,286.5		2,089.6
Cash used in financing activities		1,200.0		337.0

Net cash flows provided by operating activities are largely dependent on earnings from our consolidated business activities. Changes in energy commodity prices may impact the demand for natural gas, NGLs, crude oil, petrochemical and refined products, which could impact sales of our products and the demand for our midstream services. Changes in demand for our products and services 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 activities and long-term take-or-pay agreements. For a more complete discussion of these and other risk factors pertinent to our business, see Part I, Item 1A of the 2018 Form 10-K.

The following information highlights primary drivers of the period-to-period fluctuations in our consolidated cash flow amounts:

Operating activities

Net cash flows provided by operating activities for the six months ended June 30, 2019 increased a net $485.9 million when compared to the six months ended June 30, 2018 primarily due to:

•

a $525.9 million period-to-period increase resulting from higher partnership earnings in the six months ended June 30, 2019 when compared to the six months ended June 30, 2018 (after adjusting for our $918.2 million period-to-period increase in net income attributable to changes in the non-cash items identified on our Unaudited Condensed Statements of Consolidated Cash Flows); and

•

a $63.5 million period-to-period increase in cash distributions received on earnings from unconsolidated affiliates attributable to our investments in NGL and crude oil pipeline joint ventures; partially offset by

•

a $103.5 million period-to-period decrease primarily due to the timing of cash receipts and payments related to operations.

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For information regarding significant 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 six months ended June 30, 2019 increased a net $196.9 million when compared to the six months ended June 30, 2018 primarily due to:

•

a $339.7 million period-to-period increase in expenditures for consolidated property, plant and equipment (see “Capital Investments” within this Part I, Item 2 for additional information); partially offset by

•

a $149.7 million decrease period-to-period in net cash used for business combinations. We used $150.6 million during 2018 to acquire a 50% equity interest in Delaware Processing.

Financing activities

Cash used in financing activities for the six months ended June 30, 2019 increased $863.0 million when compared to the six months ended June 30, 2018 primarily due to:

•

a net $428.6 million period-to-period decrease in net cash inflows from debt. In the six months ended June 30, 2019, we issued $1.42 billion principal amount of short-term notes under EPO’s commercial paper program, partially offset by the repayment or repurchase of $724.2 million principal amount of senior and junior subordinated notes. In the six months ended June 30, 2018, we issued $2.7 billion aggregate principal amount of senior notes and junior subordinated notes and $214.3 million of short-term notes under EPO’s commercial paper program, partially offset by the repayment of $1.78 billion in principal amount of senior and junior subordinated notes;

•

a $178.8 million period-to-period decrease in net cash proceeds from the issuance of common units in connection with EPD’s DRIP and EUPP;

•

a $107.3 million period-to-period decrease in cash contributions from noncontrolling interests. In June 2019, an affiliate of American Midstream, LP acquired a noncontrolling 25% equity interest in our consolidated subsidiary that owns the Pascagoula natural gas processing plant for $36.0 million in cash. In June 2018, Western acquired a noncontrolling 20% equity interest in our consolidated subsidiary that owns the Midland-to-ECHO 1 Pipeline System for $189.6 million in cash. In addition, contributions for the construction of our jointly-owned ethylene export facility increased $39.5 million period-to-period;

•

the use of $81.1 million in the six months ended June 30, 2019 to acquire 2,909,128 common units under the 2019 Buyback Program; and

•

a $60.6 million increase period-to-period in cash distributions paid to limited partners primarily due to an increase in the quarterly cash distribution rate per unit.

Non-GAAP Cash Flow Measures

Distributable Cash Flow

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 those for capital expenditures, debt service, working capital, operating expenses, common unit repurchases, commitments and contingencies and other 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 (“DCF”), which is a non-GAAP cash flow measure. DCF is an important 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 our declared quarterly cash distributions. DCF is also a quantitative standard used by the investment community with respect to publicly traded partnerships since the value

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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 DCF we generate to the cash distributions we expect to pay our partners. Using this metric, management computes our distribution coverage ratio. Our calculation of DCF may or may not be comparable to similarly titled measures used by other companies.

Based on the level of available cash each quarter, 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 DCF 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 Part I, Item 2.

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

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
Net income attributable to limited partners (GAAP) (1)	$	1,214.7		$	673.8		$	2,475.2		$	1,574.5
Adjustments to net income attributable to limited partners to derive DCF (addition or subtraction indicated by sign):
Depreciation, amortization and accretion expenses		488.6			447.9			963.1			873.8
Cash distributions received from unconsolidated affiliates (2)		171.0			131.1			314.5			253.5
Equity in income of unconsolidated affiliates		(137.4	)		(122.3	)		(292.0	)		(238.0	)
Change in fair market value of derivative instruments		12.5			322.1			(83.8	)		459.0
Change in fair value of Liquidity Option Agreement		26.6			8.9			84.4			16.4
Gain on step acquisition of unconsolidated affiliate		–			(2.4	)		–			(39.4	)
Sustaining capital expenditures (3)		(80.1	)		(72.8	)		(141.7	)		(139.1	)
Other, net		12.1			32.6			15.0			41.1
Subtotal DCF, before proceeds from asset sales and monetization of interest rate derivative instruments accounted for as cash flow hedges	$	1,708.0		$	1,418.9		$	3,334.7		$	2,801.8
Proceeds from asset sales		14.4			1.5			16.1			2.6
Monetization of interest rate derivative instruments accounted for as cash flow hedges		–			–			–			1.5
DCF (non-GAAP)	$	1,722.4		$	1,420.4		$	3,350.8		$	2,805.9

Cash distributions paid to limited partners with respect to period	$	969.0		$	940.2		$	1,932.5		$	1,873.7

Cash distribution per unit declared by Enterprise GP with respect to period	$	0.4400		$	0.4300		$	0.8775		$	0.8575

Total DCF retained by partnership with respect to period (4)	$	753.4		$	480.2		$	1,418.3		$	932.2

Distribution coverage ratio (5)		1.8	x		1.5	x		1.7	x		1.5	x

(1)	For a discussion of the primary drivers of changes in our comparative income statement amounts, see “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.
(3)	Sustaining capital expenditures include cash payments and accruals applicable to the period.
(4)	At the sole discretion of Enterprise GP, cash retained by the partnership with respect to each of these periods was primarily reinvested in growth capital projects. This retainage of cash substantially reduced our reliance on the equity capital markets to fund such expenditures.
(5)	Distribution coverage ratio is determined by dividing DCF by total cash distributions paid to limited partners and in connection with distribution equivalent rights with respect to the period.

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

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
Net cash flows provided by operating activities (GAAP)	$	2,023.3		$	1,464.2		$	3,183.7		$	2,697.8
Adjustments to reconcile net cash flows provided by operating activities to DCF (addition or subtraction indicated by sign):
Net effect of changes in operating accounts		(227.8	)		25.4			332.0			228.5
Sustaining capital expenditures		(80.1	)		(72.8	)		(141.7	)		(139.1	)
Other, net		7.0			3.6			(23.2	)		18.7
DCF (non-GAAP)	$	1,722.4		$	1,420.4		$	3,350.8		$	2,805.9

Free Cash Flow

Free Cash Flow (“FCF”), a non-GAAP financial measure, is a traditional cash flow metric that is widely used by a variety of investors and other participants in the financial community, as opposed to DCF, which is a cash flow measure primarily used by investors and others in evaluating master limited partnerships. In general, FCF is a measure of how much cash flow a business generates during a specified time period after accounting for all capital investments, including expenditures for growth and sustaining capital projects. By comparison, only sustaining capital expenditures are reflected in DCF.

We believe that FCF is important to traditional investors since it reflects the amount of cash available for reducing debt, investing in additional capital projects, paying distributions, common unit repurchases and similar matters. Since business partners fund certain capital projects of our consolidated subsidiaries, our determination of FCF reflects the amount of cash we receive from noncontrolling interests, net of any distributions paid to such interests. Our calculation of FCF may or may not be comparable to similarly titled measures used by other companies.

Our use of FCF 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.

FCF fluctuates based on our earnings, the level of investing activities we undertake each period, and the timing of operating cash receipts and payments. In addition to providing the quarterly amounts presented below, we also provide a calculation of aggregate FCF over the twelve months ended June 30, 2019 in order to measure FCF over a longer term. The following table summarizes our calculation of FCF for the periods indicated (dollars in millions):

	For the Three Months Ended June 30,						For the Six Months Ended June 30,						For the Twelve Months Ended June 30,
	2019			2018			2019			2018			2019
Net cash flows provided by operating activities (GAAP)	$	2,023.3		$	1,464.2		$	3,183.7		$	2,697.8		$	6,612.2
Adjustments to net cash flows provided by operating activities to derive FCF (addition or subtraction indicated by sign):
Cash used in investing activities		(1,112.0	)		(970.5	)		(2,286.5	)		(2,089.6	)		(4,478.5	)
Cash contributions from noncontrolling interests		64.8			206.8			99.6			206.9			130.8
Cash distributions paid to noncontrolling interests		(28.9	)		(12.9	)		(46.9	)		(28.3	)		(100.2	)
FCF (non-GAAP)	$	947.2		$	687.6		$	949.9		$	786.8		$	2,164.3

For a discussion of primary drivers of our quarterly net cash flows provided by operating activities and cash used in investing activities, see “Cash Flows from Operating, Investing and Financing Activities” within this Part I, Item 2.

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Capital Investments

We currently have $6 billion of growth capital projects scheduled to be completed by the end of 2020 including:

•	expansion of our Front Range and Texas Express NGL pipelines (third quarter of 2019),

•	increase in LPG loading capacity at EHT (third quarter of 2019 and third quarter of 2020),

•	our iBDH facility (fourth quarter of 2019),

•	the Shin Oak NGL pipeline (full service expected in fourth quarter of 2019),

•	our ethylene export terminal (fourth quarter of 2019 through the fourth quarter of 2020),

•	our Mentone cryogenic natural gas processing plant (first quarter of 2020),

•	expansion projects involving our crude oil system between the Permian Basin and our ECHO terminal (third quarter of 2020),

•	two new NGL fractionators in Chambers County, Texas (“Frac X” in the fourth quarter of 2019 and “Frac XI” in the first half of 2020), and

•	expansion of our PGP export capabilities and an eighth deep-water ship dock at EHT for loading crude oil (both projects scheduled for fourth quarter of 2020).

Based on information currently available, we expect our total capital investments for 2019 to approximate $4.4 billion, which reflects growth capital expenditures of $4.0 billion and $350 million for sustaining capital expenditures.

Our forecast of capital investments for 2019 is based on 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 investments due to factors beyond our control, such as adverse economic conditions, weather-related issues and changes in supplier prices. Furthermore, our forecast of capital investments may change due to decisions made by management at a later date, which may include unforeseen acquisition opportunities.

Our success in raising capital, including partnering with other companies to share project 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 investments 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 investments for the periods indicated (dollars in millions):

	For the Six Months Ended June 30,
	2019		2018
Capital investments for property, plant and equipment: (1)
Growth capital projects (2)	$	2,116.4	$	1,780.7
Sustaining capital projects (3)		144.4		140.4
Total	$	2,260.8	$	1,921.1

Cash used for business combinations, net	$	–	$	149.7

Investments in unconsolidated affiliates	$	59.9	$	45.9

(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.

Fluctuations in our investments in growth capital projects and investments in unconsolidated affiliates are explained in large part by increases or decreases in expenditures for major expansion projects. Our most significant growth capital investments for the six months ended June 30, 2019 involve projects at our Mont Belvieu complex as well as projects to expand our Gulf Coast export terminals. Fluctuations in investments in sustaining capital projects are explained in large part by the timing and cost of pipeline integrity and similar projects.

Comparison of Six Months Ended June 30, 2019 with Six Months Ended June 30, 2018

Investments in growth capital projects at our Mont Belvieu complex increased $256.4 million period-to-period primarily due to construction activities surrounding Frac X and Frac XI, which accounted for a $275.4 million increase, our second iBDH unit, which accounted for an $89.4 million increase, and our DIB expansion, which accounted for an additional $48.3 million increase, partially offset by lower expenditures attributable to our PDH facility and ninth Mont Belvieu-area NGL fractionator (“Frac IX”), which accounted for a combined $161.5 million decrease. Our PDH facility and Frac IX were placed into service during the second quarter of 2018.

Investments in ethylene-related pipelines, storage facilities and export assets increased $153.1 million period-to-period.

Our growth capital investments in support of Permian Basin production decreased $43.3 million period-to-period primarily due to lower expenditures at our Orla natural gas processing facility, which accounted for a $181.9 million decrease, and on our Midland-to-ECHO 1 Pipeline System, which accounted for an additional $93.2 million decrease, partially offset by increased expenditures at our Mentone cryogenic natural gas processing plant, which accounted for a $168.9 million increase, and for the conversion of a portion of our Seminole NGL Pipeline system to crude oil service (i.e., the Midland-to-ECHO 2 Pipeline System), which accounted for an additional $72.8 million increase. The third processing train at our Orla natural gas processing facility was placed into service in July 2019.

Net cash used for business combinations during the six months ended June 30, 2018 reflect our acquisition of the remaining 50% member interest in Delaware Processing in March 2018.

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Critical Accounting Policies and Estimates

A discussion of our critical accounting policies and estimates is included in our 2018 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

The principal amount of our consolidated debt obligations were $27.12 billion at June 30, 2019 compared to $26.42 billion at December 31, 2018. 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 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.

Recent Accounting Developments

For information regarding recent changes in our accounting for leases, 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 14 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

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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 13 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 following table summarizes our portfolio of commodity derivative instruments outstanding at June 30, 2019 (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 (billion cubic feet (“Bcf”))	25.9	n/a	Cash flow hedge
Forecasted sales of NGLs (million barrels (“MMBbls”))	4.2	n/a	Cash flow hedge
Octane enhancement:
Forecasted purchase of NGLs (MMBbls)	1.3	n/a	Cash flow hedge
Forecasted sales of octane enhancement products (MMBbls)	2.0	n/a	Cash flow hedge
Natural gas marketing:
Forecasted purchase of natural gas (Bcf)	3.7	n/a	Cash flow hedge
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)	55.0	2.8	Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products (MMBbls)	72.1	0.8	Cash flow hedge
NGLs inventory management activities (MMBbls)	0.6	n/a	Fair value hedge
Refined products marketing:
Refined products inventory management activities (MMBbls)	0.1	n/a	Fair value hedge
Crude oil marketing:
Forecasted purchases of crude oil (MMBbls)	19.2	n/a	Cash flow hedge
Forecasted sales of crude oil (MMBbls)	26.2	n/a	Cash flow hedge
Propylene marketing:
Forecasted sales of NGLs for propylene marketing activities (MMBbls)	0.3	n/a	Cash flow hedge
Derivatives not designated as hedging instruments:
Natural gas risk management activities (Bcf) (3)	47.5	0.1	Mark-to-market
NGL risk management activities (MMBbls) (3)	5.4	n/a	Mark-to-market
Refined products risk management activities (MMBbls) (3)	1.8	n/a	Mark-to-market
Crude oil risk management activities (MMBbls) (3)	39.0	1.6	Mark-to-market

(1)	Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes.
(2)	The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is December 2020, December 2019 and December 2020, respectively.
(3)	Reflects the use of derivative instruments to manage risks associated with transportation, processing and storage assets.

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Sensitivity Analysis

The following tables show the effect of hypothetical price movements on the estimated fair values of our principal commodity derivative instrument portfolios at the dates indicated (dollars in millions).

The fair value information presented in the sensitivity analysis tables excludes the impact of applying Chicago Mercantile Exchange (“CME”) Rule 814, which deems that financial instruments cleared by the CME are settled daily in connection with variation margin payments. As a result of this exchange rule, CME-related derivatives are considered to have no fair value at the balance sheet date for financial reporting purposes; however, the derivatives remain outstanding and subject to future commodity price fluctuations until they are settled in accordance with their contractual terms. Derivative transactions cleared on exchanges other than the CME (e.g., the Intercontinental Exchange or ICE) continue to be reported on a gross basis.

Natural gas marketing portfolio

		Portfolio Fair Value at
Scenario	Resulting Classification	December 31, 2018			June 30, 2019				July 15, 2019
Fair value assuming no change in underlying commodity prices	Asset (Liability)		$	7.8		$	0.3			$	0.1
Fair value assuming 10% increase in underlying commodity prices	Asset (Liability)			8.0			0.7				1.2
Fair value assuming 10% decrease in underlying commodity prices	Asset (Liability)			7.7			(0.2	)			(1.1	)

NGL and refined products marketing, natural gas processing and octane enhancement portfolio

		Portfolio Fair Value at
Scenario	Resulting Classification	December 31, 2018			June 30, 2019			July 15, 2019
Fair value assuming no change in underlying commodity prices	Asset (Liability)		$	77.5		$	65.4		$	68.7
Fair value assuming 10% increase in underlying commodity prices	Asset (Liability)			56.2			41.9			40.2
Fair value assuming 10% decrease in underlying commodity prices	Asset (Liability)			98.9			89.0			97.3

Crude oil marketing portfolio

		Portfolio Fair Value at
Scenario	Resulting Classification	December 31, 2018				June 30, 2019				July 15, 2019
Fair value assuming no change in underlying commodity prices	Asset (Liability)		$	(26.5	)		$	(10.9	)		$	(20.5	)
Fair value assuming 10% increase in underlying commodity prices	Asset (Liability)			(88.6	)			(57.0	)			(67.9	)
Fair value assuming 10% decrease in underlying commodity prices	Asset (Liability)			35.6				35.2				26.9

The fair value of our crude oil marketing portfolio decreased since June 30, 2019 primarily due to higher crude oil prices.

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Interest Rate Hedging Activities

Sensitivity Analysis

With respect to the tabular data below, the 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.

In May 2019, we entered into two 30-year forward-starting swaps in connection with the expected future issuance of senior notes. Forward-starting swaps hedge the expected underlying benchmark interest rates related to future issuances of debt. The following table summarizes our portfolio of these swaps at June 30, 2019 (dollars in millions).

Hedged Transaction

Number and Type

of Derivatives

Outstanding

Notional

Amount

Expected

Settlement

Date

Average Rate

Locked

Accounting

Treatment

Future long-term debt offering

1 forward-starting swaps

75.0

9/2020

2.39

Cash flow hedge

Future long-term debt offering

1 forward-starting swaps

75.0

4/2021

2.41

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, 2018			June 30, 2019				July 15, 2019
Fair value assuming no change in underlying interest rates	Asset (Liability)		$	–		$	(5.2	)		$	(3.5	)
Fair value assuming 10% increase in underlying interest rates	Asset (Liability)			–			1.9				3.6
Fair value assuming 10% decrease in underlying interest rates	Asset (Liability)			–			(12.7	)			(11.1	)

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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 and (ii) W. Randall Fowler, our general partner’s President and 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 Mr. Fowler is our principal financial officer. Based on this evaluation, as of the end of the period covered by this quarterly report, Messrs. Teague and Fowler 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 second quarter of 2019, 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 and Fowler 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.

In June 2019, we received a Notice of Violation from the U.S. Environmental Protection Agency in connection with regulatory requirements applicable to facilities that we operate in Baton Rouge, Louisiana. The eventual resolution of this matter may result in monetary sanctions in excess of $0.1 million; however, we do not expect such expenditures to be material to our consolidated financial statements.

For additional information regarding our litigation matters, see “Litigation” under Note 15 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.

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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 2018 Form 10-K, in addition to other information in such annual report. The risk factors set forth in our 2018 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.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

Issuer Purchases of Equity Securities

The following table summarizes our equity repurchase activity during the second quarter of 2019:

Period	Total Number of Units Purchased		Average Price Paid per Unit		Total Number Of Units Purchased as Part of 2019 Buyback Program		Remaining Dollar Amount of Units That May Be Purchased Under the 2019 Buyback Program ($ thousands)
2019 Buyback Program: (1)
April 2019		–	$	–		–	$	1,948,466
May 2019		261,985	$	27.89		2,114,377	$	1,941,139
June 2019		794,751	$	27.97		2,909,128	$	1,923,165
Vesting of phantom unit awards:
April 2019		–	$	–		n/a		n/a
May 2019 (2)		41,111	$	28.98		n/a		n/a
June 2019 (3)		1,179	$	27.89		n/a		n/a

(1)	In January 2019, we announced the 2019 Buyback Program, which authorized the repurchase of up to $2 billion of EPD’s common units. See “Significant Recent Developments” under Part I, Item 2 of this quarterly report for additional information. The repurchased units were cancelled immediately upon acquisition.
(2)	Of the 159,278 phantom unit awards that vested in May 2019 and converted to common units, 41,111 units were sold back to us by employees to cover related withholding tax requirements. These repurchases are not part of any announced program. We cancelled these units immediately upon acquisition.
(3)	Of the 3,843 phantom unit awards that vested in June 2019 and converted to common units, 1,179 units were sold back to us by employees to cover related withholding tax requirements. These repurchases are not part of any announced program. We cancelled these units immediately upon acquisition.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

None.

ITEM 4. MINE SAFETY DISCLOSURES.

Not applicable.

ITEM 5. OTHER INFORMATION.

None.

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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).
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).

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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).
2.14	Amendment No. 1 dated as of June 6, 2018 to Contribution and Purchase Agreement, by and among Enterprise Products Partners L.P., Oiltanking Holding Americas, Inc., Enterprise Products Holdings LLC and Marquard & Bahls, AG (incorporated by reference to Exhibit 2.2 to Form 8-K filed June 12, 2018).
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	Amendment No. 4 to the Sixth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated as of February 26, 2019 (incorporated by reference to Exhibit 3.7 to Form 10-K filed March 1, 2019).
3.8	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).
3.9	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).
3.10	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).
3.11	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).
3.12	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).
3.13	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).
3.14	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).

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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	Amended and Restated Eighth Supplemental Indenture, dated as of August 25, 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 August 25, 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	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).
4.12	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).
4.13	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).
4.14	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).
4.15	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).

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4.16	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).
4.17	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).
4.18	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).
4.19	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).
4.20	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).
4.21	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).
4.22	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).
4.23	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).
4.24	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).
4.25	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).
4.26	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).
4.27	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).
4.28	Thirty-Second Supplemental Indenture, dated as of October 11, 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 October 11, 2018).

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4.29	Thirty-Third Supplemental Indenture, dated as of July 8, 2019, 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 July 8, 2019).
4.30	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).
4.31	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).
4.32	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).
4.33	Form of Global Note representing an aggregate of $550.0 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 August 25, 2006).
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 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).
4.43	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).
4.44	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).
4.45	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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4.46	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).
4.47	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).
4.48	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).
4.49	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).
4.50	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).
4.51	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).
4.52	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).
4.53	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).
4.54	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).
4.55	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).
4.56	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).
4.57	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).
4.58	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).
4.59	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).
4.60	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).
4.61	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).
4.62	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).

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4.63	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).
4.64	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).
4.65	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).
4.66	Form of Global Note representing $750.0 million principal amount of 3.50% Senior Notes due 2022 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed October 11, 2018).
4.67	Form of Global Note representing $1,000.0 million principal amount of 4.15% Senior Notes due 2028 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed October 11, 2018).
4.68	Form of Global Note representing $1,250.0 million principal amount of 4.80% Senior Notes due 2049 with attached Guarantee (incorporated by reference to Exhibit C to Exhibit 4.3 to Form 8-K filed October 11, 2018).
4.69	Form of Global Note representing $1,250.0 million principal amount of 3.125% Senior Notes due 2029 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed July 8, 2019).
4.70	Form of Global Note representing $1,250.0 million principal amount of 4.200% Senior Notes due 2050 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed July 8, 2019).
4.71	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).
4.72	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).
4.73	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).
4.74	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).
4.75	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).
4.76	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).
4.77	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).
4.78	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).

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4.79	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).
4.80	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).
4.81	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).
4.82	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).
4.83	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).
4.84	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).
4.85	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).
4.86	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).
4.87	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).
4.88	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).

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4.89	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).
10.1***	Retention Bonus Agreement between A. James Teague and Enterprise Products Company dated effective April 15, 2019 (incorporated by reference to Exhibit 10.1 to Form 8-K filed April 18, 2019).
10.2***	Retention Bonus Agreement between W. Randall Fowler and Enterprise Products Company dated effective April 15, 2019 (incorporated by reference to Exhibit 10.2 to Form 8-K filed April 18, 2019).
10.3***	Retention Bonus Agreement between Graham W. Bacon and Enterprise Products Company dated effective April 15, 2019 (incorporated by reference to Exhibit 10.3 to Form 8-K filed April 18, 2019).
10.4***	Retention Bonus Agreement between Brent B. Secrest and Enterprise Products Company dated effective April 15, 2019 (incorporated by reference to Exhibit 10.4 to Form 8-K filed April 18, 2019).
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 six months ended June 30, 2019.
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 six months ended June 30, 2019.
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 six months ended June 30, 2019.
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 six months ended June 30, 2019.
101#	Interactive data files pursuant to Rule 405 of Regulation S-T formatted in iXBRL (Inline Extensible Business Reporting Language): (i) our Unaudited Condensed Consolidated Balance Sheets as of June 30, 2019 and December 31, 2018; (ii) our Unaudited Condensed Statements of Consolidated Operations for the three and six months ended June 30, 2019 and 2018; (iii) our Unaudited Condensed Statements of Consolidated Comprehensive Income for the three and six months ended June 30, 2019 and 2018; (iv) our Unaudited Condensed Statements of Consolidated Cash Flows for the six months ended June 30, 2019 and 2018; (v) our Unaudited Condensed Statements of Consolidated Equity for the three and six months ended June 30, 2019 and 2018; and (vi) the notes to our Unaudited Condensed Consolidated Financial Statements.
104#	Cover Page Interactive Data File–the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL 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.

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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 August 9, 2019.

		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