EPD 10-Q Quarter ended June 30, 2019

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)

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

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

		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

		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

		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

		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	)
Reclassificatio n of losses ( gains) to ne t 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 comprehens ive 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

		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	)
Cas h used in financing ac tivities			( 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

		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

		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

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”).

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.

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:

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.

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

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

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.

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.

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.

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

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.

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.

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	)

		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.

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

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.

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
N on-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.

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.

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
Ne t 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.

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.

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.

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.

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.

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
													Financial Instruments				Cash Collateral Received				Cash Collateral Paid
	(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
													Financial Instruments					Cash Collateral Received				Cash Collateral Paid
	(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

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	)

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.

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.

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.

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.

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 %

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.

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.

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.

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.

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.

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

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

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

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

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
Comp rehensive income attrib utable 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

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

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

/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

							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.

	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.

		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

		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

		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 .

		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.

		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

		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.

		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

		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

		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

						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

		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

		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.

		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

		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 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.

	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.

		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	)

		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

		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

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

		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	)

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.

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).

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).

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).

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).

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).

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).

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).

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).

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.

		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