ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS

(Dollars in millions, except per unit amounts)

	For the Three Months Ended March 31,						For the Three Months Ended March 31,
	2020			2019			2021			2020
Revenues:
Third parties	$	7,466.5		$	8,531.2		$	9,141.1		$	7,466.5
Related parties		16.0			12.3			14.2			16.0
Total revenues (see Note 9)		7,482.5			8,543.5			9,155.3			7,482.5
Costs and expenses:
Operating costs and expenses:
Third parties		5,735.3			6,655.3
Third party and other costs								7,229.3			5,735.3
Related parties		325.0			364.4			324.1			325.0
Total operating costs and expenses		6,060.3			7,019.7			7,553.4			6,060.3
General and administrative costs:
Third parties		23.0			20.4
Third party and other costs								21.5			23.0
Related parties		32.5			31.8			34.8			32.5
Total general and administrative costs		55.5			52.2			56.3			55.5
Total costs and expenses (see Note 10)		6,115.8			7,071.9			7,609.7			6,115.8
Equity in income of unconsolidated affiliates		140.8			154.6			148.9			140.8
Operating income		1,507.5			1,626.2			1,694.5			1,507.5
Other income (expense):
Interest expense		(317.5	)		(277.2	)		(322.8	)		(317.5	)
Change in fair market value of Liquidity Option		(2.3	)		(57.8	)		0			(2.3	)
Interest income		7.2			1.3			1.1			7.2
Other, net		0.9			0.2			(0.2	)		0.9
Total other expense, net		(311.7	)		(333.5	)		(321.9	)		(311.7	)
Income before income taxes		1,195.8			1,292.7			1,372.6			1,195.8
Benefit from (provision for) income taxes (see Note 11)		179.2			(12.3	)
Benefit from (provision for) income taxes (see Note 15)								(10.0	)		179.2
Net income		1,375.0			1,280.4			1,362.6			1,375.0
Net income attributable to noncontrolling interests		(24.9	)		(19.9	)		(21.3	)		(24.9	)
Net income attributable to limited partners	$	1,350.1		$	1,260.5
Net income attributable to preferred units								(0.9	)		0
Net income attributable to common unitholders							$	1,340.4		$	1,350.1

Earnings per unit: (see Note 12)
Basic earnings per unit	$	0.61		$	0.57
Diluted earnings per unit	$	0.61		$	0.57
Earnings per unit: (see Note 11)
Basic and diluted earnings per common unit							$	0.61		$	0.61

See Notes to Unaudited Condensed Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED

COMPREHENSIVE INCOME

(Dollars in millions)

	For the Three Months Ended March 31,						For the Three Months Ended March 31,
	2020			2019			2021			2020

Net income	$	1,375.0		$	1,280.4		$	1,362.6		$	1,375.0
Other comprehensive income (loss):
Cash flow hedges: (see Note 14)
Cash flow hedges: (see Note 13)
Commodity hedging derivative instruments:
Changes in fair value of cash flow hedges		475.1			(95.2	)		(461.2	)		475.1
Reclassification of gains to net income		(155.6	)		(58.3	)
Reclassification of losses (gains) to net income								616.1			(155.6	)
Interest rate hedging derivative instruments:
Changes in fair value of cash flow hedges		(292.0	)		–			182.9			(278.1	)
Reclassification of losses to net income		23.5			9.2			8.6			9.6
Total cash flow hedges		51.0			(144.3	)		346.4			51.0
Other		(0.1	)		(0.6	)		(0.2	)		(0.1	)
Total other comprehensive income (loss)		50.9			(144.9	)
Total other comprehensive income								346.2			50.9
Comprehensive income		1,425.9			1,135.5			1,708.8			1,425.9
Comprehensive income attributable to noncontrolling interests		(24.9	)		(19.9	)		(21.3	)		(24.9	)
Comprehensive income attributable to limited partners	$	1,401.0		$	1,115.6
Comprehensive income attributable to preferred units								(0.9	)		0
Comprehensive income attributable to common unitholders							$	1,686.6		$	1,401.0

See Notes to Unaudited Condensed Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Dollars in millions)

	For the Three Months Ended March 31,						For the Three Months Ended March 31,
	2020			2019			2021			2020
Operating activities:
Net income	$	1,375.0		$	1,280.4		$	1,362.6		$	1,375.0
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		509.0			474.5
Asset impairment and related charges		1.6			4.8
Depreciation and accretion								425.4			414.0
Amortization of intangible assets								36.1			39.6
Amortization of major maintenance costs for reaction-based plants								2.6			0
Other amortization expense								60.9			55.4
Impairment of assets other than goodwill (see Note 4)								65.6			1.6
Equity in income of unconsolidated affiliates		(140.8	)		(154.6	)		(148.9	)		(140.8	)
Distributions received from unconsolidated affiliates attributable to earnings		126.9			139.0			111.9			126.9
Net losses (gains) attributable to asset sales		0.1			(0.4	)
Net losses attributable to asset sales and related matters								10.9			0.1
Deferred income tax expense (benefit)		(184.1	)		1.8			4.6			(184.1	)
Change in fair market value of derivative instruments		(29.5	)		(96.3	)		(15.6	)		(29.5	)
Change in fair market value of Liquidity Option		2.3			57.8			0			2.3
Non-cash expense related to long-term operating leases (see Note 16)		10.0			11.0			9.3			10.0
Net effect of changes in operating accounts (see Note 17)		341.7			(559.8	)		99.0			341.7
Other operating activities		–			2.2			(1.3	)		0
Net cash flows provided by operating activities		2,012.2			1,160.4			2,023.1			2,012.2
Investing activities:
Capital expenditures		(1,079.5	)		(1,148.9	)		(679.0	)		(1,079.5	)
Investments in unconsolidated affiliates		(3.3	)		(29.1	)		(1.3	)		(3.3	)
Distributions received from unconsolidated affiliates attributable to the return of capital		10.3			4.5			18.6			10.3
Proceeds from asset sales		0.6			1.7			6.2			0.6
Other investing activities		0.2			(2.7	)		(1.5	)		0.2
Cash used in investing activities		(1,071.7	)		(1,174.5	)		(657.0	)		(1,071.7	)
Financing activities:
Borrowings under debt agreements		5,411.8			15,692.4			7,531.8			5,411.8
Repayments of debt		(3,406.6	)		(14,999.2	)		(8,741.8	)		(3,406.6	)
Debt issuance costs		(28.4	)		–			0			(28.4	)
Monetization of interest rate derivative instruments		(33.3	)		–			75.2			(33.3	)
Cash distributions paid to limited partners (see Note 8)		(974.2	)		(950.4	)
Cash distributions paid to common unitholders (see Note 8)								(981.7	)		(974.2	)
Cash payments made in connection with distribution equivalent rights		(5.8	)		(4.5	)		(7.0	)		(5.8	)
Cash distributions paid to noncontrolling interests		(29.9	)		(18.0	)		(29.8	)		(29.9	)
Cash contributions from noncontrolling interests		5.2			34.8			13.1			5.2
Net cash proceeds from the issuance of common units		–			42.7
Repurchase of common units under 2019 Buyback Program (see Note 8)		(140.1	)		(51.6	)		(13.9	)		(140.1	)
Other financing activities		(33.6	)		(34.7	)		(35.7	)		(33.6	)
Cash provided by (used in) financing activities		765.1			(288.5	)		(2,189.8	)		765.1
Net change in cash and cash equivalents, including restricted cash		1,705.6			(302.6	)		(823.7	)		1,705.6
Cash and cash equivalents, including restricted cash, at beginning of period		410.0			410.1			1,158.1			410.0
Cash and cash equivalents, including restricted cash, at end of period	$	2,115.6		$	107.5		$	334.4		$	2,115.6

See Notes to Unaudited Condensed Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY

(Dollars in millions)

	Partners’ Equity															Partners’ Equity
	Limited Partners			Treasury Units			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total			Common Limited Partner Interests			Treasury Units			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests in Consolidated Subsidiaries			Total
Balance, December 31, 2019	$	24,692.6		$	–		$	71.4		$	1,063.5		$	25,827.5
Balance, December 31, 2020																$	25,766.6		$	(1,297.3	)	$	(165.2	)	$	1,073.3		$	25,377.4
Net income		1,350.1			–			–			24.9			1,375.0			1,340.4			0			0			21.3			1,361.7
Cash distributions paid to limited partners		(974.2	)		–			–			–			(974.2	)
Cash distributions paid to common unitholders																	(981.7	)		0			0			0			(981.7	)
Cash payments made in connection with distribution equivalent rights		(5.8	)		–			–			–			(5.8	)		(7.0	)		0			0			0			(7.0	)
Cash distributions paid to noncontrolling interests		–			–			–			(29.9	)		(29.9	)		0			0			0			(29.8	)		(29.8	)
Cash contributions from noncontrolling interests		–			–			–			5.2			5.2			0			0			0			13.1			13.1
Amortization of fair value of equity-based awards		39.1			–			–			–			39.1			38.8			0			0			0			38.8
Repurchase and cancellation of common units under 2019 Buyback Program (see Note 8)		(140.1	)		–			–			–			(140.1	)		(13.9	)		0			0			0			(13.9	)
Common units issued in connection with settlement of Liquidity Option (see Note 8)		1,297.3			–			–			–			1,297.3
Treasury units acquired in connection with settlement of Liquidity Option, at cost (see Note 8)		–			(1,297.3	)		–			–			(1,297.3	)
Cash flow hedges		–			–			51.0			–			51.0			0			0			346.4			0			346.4
Other, net		(33.6	)		–			(0.1	)		0.1			(33.6	)		(34.6	)		0			(0.2	)		0			(34.8	)
Balance, March 31, 2020	$	26,225.4		$	(1,297.3	)	$	122.3		$	1,063.8		$	26,114.2
Balance, March 31, 2021																$	26,108.6		$	(1,297.3	)	$	181.0		$	1,077.9		$	26,070.2

Partners’ Equity

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 1,260.5 – 19.9 1,280.4
   Cash distributions paid to limited partners (950.4 ) – – (950.4 )
   Cash payments made in connection with
      distribution equivalent rights
(4.5 ) – – (4.5 )
   Cash distributions paid to noncontrolling interests – – (18.0 ) (18.0 )
   Cash contributions from noncontrolling interests – – 34.8 34.8
   Net cash proceeds from the issuance of common units 42.7 – – 42.7
   Common units issued in connection with
      employee compensation
45.6 – – 45.6
   Amortization of fair value of equity-based awards 32.0 – – 32.0
   Repurchase and cancellation of common units under
      2019 Buyback Program
(51.6 ) – – (51.6 )
   Cash flow hedges – (144.3 ) – (144.3 )
   Other, net (25.0 ) (0.6 ) (12.0 ) (37.6 )
    Balance, March 31, 2019 $ 24,151.9 $ (94.0 ) $ 463.4 $ 24,521.3

	Partners’ Equity
	Common Limited Partner Interests			Treasury Units			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests in Consolidated Subsidiaries			Total
Balance, December 31, 2019	$	24,692.6		$	0		$	71.4		$	1,063.5		$	25,827.5
Net income		1,350.1			0			0			24.9			1,375.0
Cash distributions paid to common unitholders		(974.2	)		0			0			0			(974.2	)
Cash payments made in connection with distribution equivalent rights		(5.8	)		0			0			0			(5.8	)
Cash distributions paid to noncontrolling interests		0			0			0			(29.9	)		(29.9	)
Cash contributions from noncontrolling interests		0			0			0			5.2			5.2
Amortization of fair value of equity-based awards		39.1			0			0			0			39.1
Repurchase and cancellation of common units under 2019 Buyback Program (see Note 8)		(140.1	)		0			0			0			(140.1	)
Common units issued to Skyline North Americas, Inc. in connection with settlement of Liquidity Option (see Note 8)		1,297.3			0			0			0			1,297.3
Treasury units acquired in connection with settlement of Liquidity Option, at cost (see Note 8)		0			(1,297.3	)		0			0			(1,297.3	)
Cash flow hedges		0			0			51.0			0			51.0
Other, net		(33.6	)		0			(0.1	)		0.1			(33.6	)
Balance, March 31, 2020	$	26,225.4		$	(1,297.3	)	$	122.3		$	1,063.8		$	26,114.2

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

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

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

~~stated in millions of dollars.~~

KEY REFERENCES USED IN THESE

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

References to ~~“EPD” or~~ the “Partnership” mean Enterprise Products Partners L.P. on a standalone basis.

References to “EPO” mean Enterprise Products Operating LLC, which is an indirect wholly owned subsidiary of ~~EPD,~~the Partnership, and its consolidated subsidiaries, through which ~~EPD~~the Partnership conducts its business. ~~Enterprise is~~We are managed by ~~its~~our general partner, Enterprise Products Holdings LLC (“Enterprise GP”), which is a wholly owned subsidiary of Dan Duncan LLC, a privately held Texas limited liability company.

The membership interests of Dan Duncan LLC are owned by a voting trust, the current trustees (“DD LLC Trustees”) of which are: (i) Randa Duncan Williams, who is also a director and Chairman of the Board of Directors (the “Board”) of Enterprise GP; (ii) Richard H. Bachmann, who is also a director and Vice Chairman of the Board of Enterprise GP; and (iii) ~~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 Co-Chief Executive Officer and Chief Financial Officer of Enterprise GP. Ms. Duncan Williams and Messrs. Bachmann and Fowler also currently serve as managers of Dan Duncan LLC.

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

We, Enterprise GP, EPCO ~~along with Mr. Fowler, who is also~~and Dan Duncan LLC are affiliates under the ~~Executive Vice President~~collective common control of the DD LLC Trustees and ~~Chief Financial Officer of EPCO.~~the EPCO Trustees. EPCO, together with its privately held affiliates, owned approximately ~~32.1%~~32.2% of ~~EPD’s limited partner~~the Partnership’s common units outstanding at March 31, ~~2020.~~2021.

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

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

stated in millions of dollars.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Partnership Organization and ~~Basis of Presentation~~Operations

We are owned by our limited partners (preferred and common unitholders) from an economic perspective. Enterprise GP, which owns a non-economic general partner interest in us, manages our Partnership. We conduct substantially all of our business operations through EPO and ~~are owned 100% by EPD’s limited partners~~its consolidated subsidiaries.

Our fully integrated, midstream energy asset network (or “value chain”) links producers of natural gas, NGLs and crude oil 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 controlsome of the ~~DD LLC Trustees~~largest supply basins in the United States (“U.S.”), Canada and the ~~EPCO Trustees.~~ Gulf of Mexico with domestic consumers and international markets. Our midstream energy operations include:

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

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

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

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

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

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

Like many publicly traded partnerships, we have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement (the “ASA”) or by other service providers. See Note 1514 for information regarding related party matters.

Our results of operations for the three months ended March 31, ~~2020~~2021 are not necessarily indicative of results expected for the full year of ~~2020.~~2021. In our opinion, the accompanying Unaudited Condensed Consolidated Financial Statements include all adjustments consisting of normal recurring accruals necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with United States (“U.S.”) generally accepted accounting principles (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”).

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~~ENTERPRISE PRODUCTS PARTNERS L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

These Unaudited Condensed Consolidated Financial Statements and Notes thereto should be read in conjunction with the Audited Consolidated Financial Statements and Notes thereto included in our annual report on Form 10-K for the year ended December 31, ~~2019~~2020 (the ~~“2019~~“2020 Form 10-K”) filed with the SEC on ~~February 28, 2020.~~March 1, 2021.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 2. Summary of Significant Accounting Policies

Apart from those matters ~~noted below,~~described in this footnote, there have been no ~~changes in~~updates to our significant accounting policies since those reported under Note 2 of the ~~2019~~2020 Form 10-K.

Allowance for Credit Losses

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

The following table presents our allowance for credit losses activity since December 31, 2020:

Allowance for credit losses, December 31, 2020	$	46.5
Charged to costs and expenses		0.2
Charged to other accounts		1.1
Deductions		(0.5	)
Allowance for credit losses, March 31, 2021	$	47.3

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.

	March 31, 2020		December 31, 2019		March 31, 2021		December 31, 2020
Cash and cash equivalents	$	2,025.7	$	334.7	$	229.4	$	1,059.9
Restricted cash		89.9		75.3		105.0		98.2
Total cash, cash equivalents and restricted cash shown in the Unaudited Condensed Statements of Consolidated Cash Flows	$	2,115.6	$	410.0	$	334.4	$	1,158.1

Restricted cash primarily represents amounts held in segregated bank accounts by our clearing brokers as margin in support of our commodity derivative instruments portfolio and related physical purchases and sales of natural gas, NGLs, crude oil, refined products and power. Additional cash may be restricted to maintain our commodity derivative instruments portfolio as prices fluctuate or margin requirements change. See Note 1413 for information regarding our derivative instruments and hedging activities.

~~Recent Accounting Developments~~

~~Credit Losses~~

~~In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-13,~~ ~~Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. The new guidance, referred to~~

Note 3. Inventories

Our inventory amounts by product type were as ~~the current expected credit loss (“CECL”) model, requires the measurement of expected credit losses for financial assets (e.g., accounts receivable) held~~follows at the reporting date based on historical experience, current economic conditions, and reasonable and supportable forecasts. These result in the more timely recognition of losses. The adoption of this new guidance on January 1, 2020 did not have a material impact on our consolidated financial statements.dates indicated:

~~Fair Value Measurement~~

~~In August 2018, the FASB issued ASU 2018-13,~~ ~~Fair Value Measurements (Topic 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurement,~~ which amended the disclosure requirements related to fair value measurements in an effort to enhance the overall usefulness of the disclosures and reduce costs by eliminating certain disclosures that were not considered to be decision-useful for users of the financial statements. The ASU will now require incremental disclosures regarding changes in unrealized gains and losses, significant unobservable inputs used to develop Level 3 fair value measurements and measurement uncertainty. Additionally, the ASU eliminated certain policy and process disclosures and reporting requirements.

	March 31, 2021		December 31, 2020
NGLs	$	1,707.8	$	1,888.1
Petrochemicals and refined products		1,151.0		642.6
Crude oil		825.7		758.1
Natural gas		18.8		14.7
Total	$	3,703.3	$	3,303.5

We adopted the requirements of this ASU on January 1, 2020. The amendments that resulted in additional disclosures have been applied prospectively for only the most recent interim or annual period presented in the year of adoption. All other amendments were applied retrospectively. See Note 14 for information regarding our fair value measurements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~Goodwill~~

~~In January 2017, the FASB issued ASU 2017-04,~~ ~~Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.~~ This ASU simplifies the accounting for goodwill impairment by removing Step 2 of the goodwill impairment test, which requires a hypothetical purchase price allocation. Goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. We adopted this guidance on January 1, 2020 for future goodwill impairment testing.

~~Note 3. Inventories~~

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

March 31,
2020

December 31,
2019

NGLs $ 893.9 $ 1,094.9
Petrochemicals and refined products 199.8 311.5
Crude oil 432.9 674.2
Natural gas 12.2 10.8
Total $ 1,538.8 $ 2,091.4

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 March 31,						For the Three Months Ended March 31,
	2020			2019			2021			2020
Cost of sales (1)		$	4,823.0		$	5,835.6		$	6,263.0		$	4,823.0
Lower of cost or net realizable value adjustments recognized in cost of sales			38.0			5.4			10.0			38.0

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

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~~ENTERPRISE PRODUCTS PARTNERS L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

Note 4. Property, Plant and Equipment

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

	Estimated Useful Life in Years			March 31, 2020		December 31, 2019			Estimated Useful Life in Years			March 31, 2021		December 31, 2020
Plants, pipelines and facilities (1)		3-45	(5)	$	47,954.0	$	47,201.2			3-45	(5)	$	50,036.0	$	49,972.8
Underground and other storage facilities (2)		5-40	(6)		3,991.9		3,965.5			5-40	(6)		4,231.4		4,207.5
Transportation equipment (3)		3-10			203.5		198.9	��		3-10			199.2		204.9
Marine vessels (4)		15-30			904.0		905.9			15-30			929.6		932.7
Land					375.9		372.3						372.1		371.9
Construction in progress					2,817.4		2,641.2						2,055.3		1,807.7
Total					56,246.7		55,285.0
Subtotal													57,823.6		57,497.5
Less accumulated depreciation					14,087.6		13,681.6						15,805.9		15,584.7
Subtotal property, plant and equipment, net													42,017.7		41,912.8
Capitalized major maintenance costs for reaction-based plants, net of accumulated amortization (7)													84.7		0
Property, plant and equipment, net				$	42,159.1	$	41,603.4					$	42,102.4	$	41,912.8

(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.
(7)	For reaction-based plants, we use the deferral method when accounting for major maintenance activities. Under the deferral method, major maintenance costs are capitalized and amortized over the period until the next major overhaul project. On a weighted-average basis, the expected amortization period for these costs is 2.8 years.

Property, plant and equipment at March 31, 2021 and December 31, 2020 includes $69.0 million and $69.7 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, 2020:

ARO liability balance, December 31, 2020	$	149.5
Liabilities incurred		0
Liabilities settled		0
Revisions in estimated cash flows		(1.1	)
Accretion expense		1.7
ARO liability balance, March 31, 2021	$	150.1

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Of the $150.1 million total ARO liability recorded at March 31, 2021, $11.3 million was reflected as a current liability and $138.8 million as a long-term liability.

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

	For the Three Months Ended March 31,						For the Three Months Ended March 31,
	2020			2019			2021			2020
Depreciation expense (1)		$	412.2		$	380.6		$	423.7		$	412.2
Accretion expense (1)									1.7			1.8
Capitalized interest (2)			30.5			36.2			19.6			30.5

(1)

Depreciation and accretion 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~~impairment charges

~~Property,~~In March 2021, we entered into agreements to sell a coal bed natural gas gathering system and related Val Verde treating facility, both of which were components of our San Juan Gathering System, to a third party for $40.0 million in cash. The transaction closed and was effective on April 1, 2021. In total, we recognized an impairment charge of $43.4 million, which reflects the write down of $36.6 million of property, plant and equipment and $6.8 million of intangible assets (see Note 6). The impairment charge attributable to this transaction primarily reflects the reclassification of the underlying assets and liabilities (at their estimated fair values) to their respective held-for-sale accounts at March 31, 2021. The remainder of our impairment charges for the three month periods ended March 31, 2021 and 2020 are attributable to the complete write-off of assets that are no longer expected to be used or constructed.

Asset impairment charges related to operations are a component of “Third party and ~~December 31,~~other costs” within the “Operating costs and expenses” section of our Unaudited Condensed Statements of Consolidated Operations.

We are closely monitoring the recoverability of our long-lived assets, investments in unconsolidated affiliates and goodwill in light of the adverse economic effects of the coronavirus disease 2019 ~~includes $70.0 million and $69.6 million, respectively,~~(“COVID-19”) pandemic. If the adverse economic impacts of ~~asset retirement costs capitalized as an increase~~the pandemic persist for longer periods than currently expected, these developments could result in the ~~associated long-lived asset. The following table presents information regarding our asset retirement obligations, or AROs, since December 31, 2019:~~recognition of non-cash impairment charges in the future.

ARO liability balance, December 31, 2019 $ 132.1
Liabilities incurred 1.2
Revisions in estimated cash flows (0.2 )
Accretion expense 2.0
ARO liability balance, March 31, 2020 $ 135.1

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 5. Investments in Unconsolidated Affiliates

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

	March 31, 2020		December 31, 2019		March 31, 2021		December 31, 2020
NGL Pipelines & Services	$	699.1	$	703.8	$	664.6	$	671.6
Crude Oil Pipelines & Services		1,877.5		1,866.5		1,749.5		1,723.7
Natural Gas Pipelines & Services		27.9		27.3		32.5		31.4
Petrochemical & Refined Products Services		4.0		2.6		3.2		2.5
Total	$	2,608.5	$	2,600.2	$	2,449.8	$	2,429.2

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

For the Three Months
Ended March 31,

2020 2019
NGL Pipelines & Services $ 32.7 $ 30.1
Crude Oil Pipelines & Services 107.3 124.6
Natural Gas Pipelines & Services 1.6 1.7
Petrochemical & Refined Products Services (0.8 ) (1.8 )
Total $ 140.8 $ 154.6

	For the Three Months Ended March 31,
	2021		2020
NGL Pipelines & Services	$	28.1	$	32.7
Crude Oil Pipelines & Services		118.9		107.3
Natural Gas Pipelines & Services		1.4		1.6
Petrochemical & Refined Products Services		0.5		(0.8	)
Total	$	148.9	$	140.8

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~~ENTERPRISE PRODUCTS PARTNERS L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

Note 6. Intangible Assets and Goodwill

Identifiable Intangible Assets

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

	March 31, 2020							December 31, 2019							March 31, 2021							December 31, 2020
	Gross Value		Accumulated Amortization			Carrying Value		Gross Value		Accumulated Amortization			Carrying Value		Gross Value		Accumulated Amortization			Carrying Value		Gross Value		Accumulated Amortization			Carrying Value
NGL Pipelines & Services:
Customer relationship intangibles	$	447.8	$	(210.0	)	$	237.8	$	447.8	$	(206.3	)	$	241.5	$	447.8	$	(224.5	)	$	223.3	$	447.8	$	(221.3	)	$	226.5
Contract-based intangibles		162.6		(46.7	)		115.9		162.6		(43.9	)		118.7		162.6		(57.8	)		104.8		162.6		(55.0	)		107.6
Segment total		610.4		(256.7	)		353.7		610.4		(250.2	)		360.2		610.4		(282.3	)		328.1		610.4		(276.3	)		334.1
Crude Oil Pipelines & Services:
Customer relationship intangibles		2,203.5		(260.1	)		1,943.4		2,203.5		(243.5	)		1,960.0		2,195.0		(306.1	)		1,888.9		2,195.0		(291.6	)		1,903.4
Contract-based intangibles		276.9		(239.3	)		37.6		276.9		(235.0	)		41.9		283.1		(253.2	)		29.9		283.1		(249.9	)		33.2
Segment total		2,480.4		(499.4	)		1,981.0		2,480.4		(478.5	)		2,001.9		2,478.1		(559.3	)		1,918.8		2,478.1		(541.5	)		1,936.6
Natural Gas Pipelines & Services:
Customer relationship intangibles		1,350.3		(489.6	)		860.7		1,350.3		(481.6	)		868.7		1,350.3		(521.1	)		829.2		1,350.3		(512.2	)		838.1
Contract-based intangibles		468.0		(397.7	)		70.3		468.0		(395.5	)		72.5		231.1		(179.1	)		52.0		470.7		(403.8	)		66.9
Segment total		1,818.3		(887.3	)		931.0		1,818.3		(877.1	)		941.2		1,581.4		(700.2	)		881.2		1,821.0		(916.0	)		905.0
Petrochemical & Refined Products Services:
Customer relationship intangibles		181.4		(59.1	)		122.3		181.4		(57.5	)		123.9		181.4		(69.7	)		111.7		181.4		(68.3	)		113.1
Contract-based intangibles		46.0		(24.6	)		21.4		46.0		(24.2	)		21.8		44.9		(24.9	)		20.0		44.9		(24.6	)		20.3
Segment total		227.4		(83.7	)		143.7		227.4		(81.7	)		145.7		226.3		(94.6	)		131.7		226.3		(92.9	)		133.4
Total intangible assets	$	5,136.5	$	(1,727.1	)	$	3,409.4	$	5,136.5	$	(1,687.5	)	$	3,449.0	$	4,896.2	$	(1,636.4	)	$	3,259.8	$	5,135.8	$	(1,826.7	)	$	3,309.1

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

	For the Three Months Ended March 31,				For the Three Months Ended March 31,
	2020		2019		2021		2020
NGL Pipelines & Services	$	6.5	$	9.1	$	6.0	$	6.5
Crude Oil Pipelines & Services		20.9		22.0		17.8		20.9
Natural Gas Pipelines & Services		10.2		10.9		10.6		10.2
Petrochemical & Refined Products Services		2.0		2.2		1.7		2.0
Total	$	39.6	$	44.2	$	36.1	$	39.6

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

Remainder of 2020		2021		2022		2023		2024
Remainder of 2021										Remainder of 2021	2022		2023		2024		2025
$	125.1	$	167.1	$	164.1	$	162.4	$	158.9	107.9	$	159.5	$	167.4	$	163.6	$	162.2

Impairment of Intangible Asset

In March 2021, we recognized an impairment charge of $6.8 million for the write down of contract-based intangible assets associated with the sale of a portion of our San Juan Gathering System (see Note 4). The contract-based intangible assets were classified within our Natural Gas Pipelines & Services business segment.

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 ~~2019~~2020 Form 10-K. We are closely monitoring the recoverability of our long-lived assets, which include goodwill, in light of the COVID-19 pandemic.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 7. Debt Obligations

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

	March 31, 2020			December 31, 2019			March 31, 2021			December 31, 2020
EPO senior debt obligations:
Commercial Paper Notes, variable-rates	$	–		$	482.0		$	115.0		$	0
Senior Notes Q, 5.25% fixed-rate, due January 2020		–			500.0
Senior Notes Y, 5.20% fixed-rate, due September 2020		1,000.0			1,000.0
September 2019 364-Day Revolving Credit Agreement, variable-rate, due September 2020		–			–
Senior Notes TT, 2.80% fixed-rate, due February 2021		750.0			750.0			0			750.0
Senior Notes RR, 2.85% fixed-rate, due April 2021		575.0			575.0			0			575.0
September 2020 364-Day Revolving Credit Agreement, variable-rate, due September 2021								0			0
Senior Notes VV, 3.50% fixed-rate, due February 2022		750.0			750.0			750.0			750.0
Senior Notes CC, 4.05% fixed-rate, due February 2022		650.0			650.0			650.0			650.0
Senior Notes HH, 3.35% fixed-rate, due March 2023		1,250.0			1,250.0			1,250.0			1,250.0
Senior Notes JJ, 3.90% fixed-rate, due February 2024		850.0			850.0			850.0			850.0
Multi-Year Revolving Credit Agreement, variable-rate, due September 2024		–			–			0			0
Senior Notes MM, 3.75% fixed-rate, due February 2025		1,150.0			1,150.0			1,150.0			1,150.0
Senior Notes PP, 3.70% fixed-rate, due February 2026		875.0			875.0			875.0			875.0
Senior Notes SS, 3.95% fixed-rate, due February 2027		575.0			575.0			575.0			575.0
Senior Notes WW, 4.15% fixed-rate, due October 2028		1,000.0			1,000.0			1,000.0			1,000.0
Senior Notes YY, 3.125% fixed-rate, due July 2029		1,250.0			1,250.0			1,250.0			1,250.0
Senior Notes AAA, 2.80% fixed-rate, due January 2030		1,000.0			–			1,250.0			1,250.0
Senior Notes D, 6.875% fixed-rate, due March 2033		500.0			500.0			500.0			500.0
Senior Notes H, 6.65% fixed-rate, due October 2034		350.0			350.0			350.0			350.0
Senior Notes J, 5.75% fixed-rate, due March 2035		250.0			250.0			250.0			250.0
Senior Notes W, 7.55% fixed-rate, due April 2038		399.6			399.6			399.6			399.6
Senior Notes R, 6.125% fixed-rate, due October 2039		600.0			600.0			600.0			600.0
Senior Notes Z, 6.45% fixed-rate, due September 2040		600.0			600.0			600.0			600.0
Senior Notes BB, 5.95% fixed-rate, due February 2041		750.0			750.0			750.0			750.0
Senior Notes DD, 5.70% fixed-rate, due February 2042		600.0			600.0			600.0			600.0
Senior Notes EE, 4.85% fixed-rate, due August 2042		750.0			750.0			750.0			750.0
Senior Notes GG, 4.45% fixed-rate, due February 2043		1,100.0			1,100.0			1,100.0			1,100.0
Senior Notes II, 4.85% fixed-rate, due March 2044		1,400.0			1,400.0			1,400.0			1,400.0
Senior Notes KK, 5.10% fixed-rate, due February 2045		1,150.0			1,150.0			1,150.0			1,150.0
Senior Notes QQ, 4.90% fixed-rate, due May 2046		975.0			975.0			975.0			975.0
Senior Notes UU, 4.25% fixed-rate, due February 2048		1,250.0			1,250.0			1,250.0			1,250.0
Senior Notes XX, 4.80% fixed-rate, due February 2049		1,250.0			1,250.0			1,250.0			1,250.0
Senior Notes ZZ, 4.20% fixed-rate, due January 2050		1,250.0			1,250.0			1,250.0			1,250.0
Senior Notes BBB, 3.70% fixed-rate, due January 2051		1,000.0			–			1,000.0			1,000.0
Senior Notes DDD, 3.20% fixed-rate, due February 2052								1,000.0			1,000.0
Senior Notes NN, 4.95% fixed-rate, due October 2054		400.0			400.0			400.0			400.0
Senior Notes CCC, 3.95% fixed rate, due January 2060		1,000.0			–			1,000.0			1,000.0
TEPPCO senior debt obligations:
TEPPCO Senior Notes, 7.55% fixed-rate, due April 2038		0.4			0.4			0.4			0.4
Total principal amount of senior debt obligations		27,250.0			25,232.0			26,290.0			27,500.0
EPO Junior Subordinated Notes C, variable-rate, due June 2067 (1)		232.2			232.2			232.2			232.2
EPO Junior Subordinated Notes D, fixed/variable-rate, due August 2077 (2)		700.0			700.0			700.0			700.0
EPO Junior Subordinated Notes E, fixed/variable-rate, due August 2077 (3)		1,000.0			1,000.0			1,000.0			1,000.0
EPO Junior Subordinated Notes F, fixed/variable-rate, due February 2078 (4)		700.0			700.0			700.0			700.0
TEPPCO Junior Subordinated Notes, variable-rate, due June 2067 (1)		14.2			14.2			14.2			14.2
Total principal amount of senior and junior debt obligations		29,896.4			27,878.4			28,936.4			30,146.4
Other, non-principal amounts		(290.5	)		(253.3	)		(277.1	)		(280.7	)
Less current maturities of debt		(1,750.0	)		(1,981.9	)		(1,513.4	)		(1,325.0	)
Total long-term debt	$	27,855.9		$	25,643.2		$	27,145.9		$	28,540.7

(1)	Variable rate is reset quarterly and based on 3-month London Interbank Offered Rate ("LIBOR"), plus 2.778%.
(2)	Fixed rate of 4.875% through August 15, 2022; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 2.986%.
(3)	Fixed rate of 5.250% through August 15, 2027; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 3.033%.
(4)	Fixed rate of 5.375% through February 14, 2028; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 2.57%.

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

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Variable Interest Rates

The following table presents the range of interest rates and weighted-average interest rates paid on our consolidated variable-rate debt during the three months ended March 31, ~~2020:~~2021:

	Range of Interest Rates Paid	Weighted-Average Interest Rate Paid
Commercial Paper Notes	~~1.78%~~0.15% to ~~2.08%~~0.25%	~~1.86%~~0.22%
EPO Junior Subordinated Notes C and TEPPCO Junior Subordinated Notes	~~4.36%~~2.97% to ~~4.68%~~3.00%	~~4.57%~~2.99%

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

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

Scheduled Maturities of Debt

The following table presents the scheduled ~~contractual~~ maturities of principal amounts of ~~our~~EPO’s consolidated debt obligations at March 31, ~~2020~~2021 for the next five years, and in total thereafter:

Scheduled Maturities of Debt
Total
Remainder
of 2020
2021 2022 2023 2024 Thereafter
Principal amount of senior and junior debt obligations $ 29,896.4 $ 1,000.0 $ 1,325.0 $ 1,400.0 $ 1,250.0 $ 850.0 $ 24,071.4

			Scheduled Maturities of Debt
	Total		Remainder of 2021		2022		2023		2024		2025		Thereafter
Commercial Paper Notes	$	115.0	$	115.0	$	0	$	0	$	0	$	0	$	0
Senior Notes		26,175.0		0		1,400.0		1,250.0		850.0		1,150.0		21,525.0
Junior Subordinated Notes		2,646.4		0		0		0		0		0		2,646.4
Total	$	28,936.4	$	115.0	$	1,400.0	$	1,250.0	$	850.0	$	1,150.0	$	24,171.4

In February 2021, EPO repaid all of the $750.0 million in principal amount of its Senior Notes TT using remaining cash on hand attributable to its August 2020 senior notes offering and proceeds from the issuance of short-term notes under its commercial paper program.

In March 2021, EPO redeemed all of the $575.0 million outstanding principal amount of its Senior Notes RR one month prior to their scheduled maturity in April ~~2020,~~2021. These notes were redeemed at par (i.e., at a redemption price equal to the outstanding principal amount of such notes to be redeemed, plus accrued and unpaid interest thereon) using proceeds from the issuance of short-term notes under its commercial paper program.

Letters of Credit

At March 31, 2021, EPO ~~entered into an additional 364-Day revolving~~had $200.7 million of letters of credit ~~agreement. See Note 19 regarding this subsequent event.~~outstanding primarily related to our commodity hedging activities.

Lender Financial Covenants

We were in compliance with the financial covenants of our consolidated debt agreements at March 31, 2021.

Parent-Subsidiary Guarantor Relationships

~~EPD~~The Partnership 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~~the Partnership would be responsible for full and unconditional repayment of that obligation.

~~Issuance of $3.0 Billion of Senior Notes in January 2020~~

In January 2020, EPO issued $3.0 billion aggregate principal amount of senior notes comprised of (i) $1.0 billion principal amount of senior notes due January 2030 (“Senior Notes AAA”), (ii) $1.0 billion principal amount of senior notes due January 2051 (“Senior Notes BBB”) and (iii) $1.0 billion principal amount of senior notes due January 2060 (“Senior Notes CCC”). Net proceeds from this offering were used by EPO for the repayment of $500 million principal amount of its Senior Notes Q that matured in January 2020, temporary repayment of amounts outstanding under its commercial paper program and for general company purposes. In addition, net proceeds from this offering will be used by EPO for the repayment of $1.0 billion principal amount of its Senior Notes Y upon their maturity in September 2020.

Senior Notes AAA were issued at 99.921% of their principal amount and have a fixed-rate interest rate of 2.80% per year. Senior Notes BBB were issued at 99.413% of their principal amount and have a fixed-rate interest rate of 3.70% per year. Senior Notes CCC were issued at 99.360% of their principal amount and have a fixed-rate interest rate of 3.95% per year. EPD guaranteed these senior notes through an unconditional guarantee on an unsecured and unsubordinated basis.

~~Lender Financial Covenants~~

~~We were in compliance with the financial covenants of our consolidated debt agreements at March 31, 2020.~~

~~Letters of Credit~~

~~At March 31, 2020, EPO had $101.4 million of letters of credit outstanding primarily related to our commodity hedging activities.~~

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Note 8. ~~Equity and Distributions~~Capital Accounts

~~Partners’ Equity~~Common Limited Partner Interests

The following table summarizes changes in the number of our ~~limited partner~~ common units outstanding ~~and treasury units~~ since December 31, ~~2019:~~2020:

Limited
Partner
Common Units
Outstanding

Treasury Units

Units outstanding at December 31, 2019 2,189,226,130 –
Common units issued in connection with settlement of Liquidity Option 54,807,352 –
Treasury units acquired in connection with settlement of Liquidity Option (54,807,352 ) 54,807,352
Common unit repurchases under 2019 Buyback Program (6,357,739 ) –
Common units issued in connection with the vesting of phantom unit awards, net 2,912,214 –
Other 19,638 –
Units outstanding at March 31, 2020 2,185,800,243 54,807,352

Common units outstanding at December 31, 2020	2,182,308,958
Common unit repurchases under 2019 Buyback Program	(709,816	)
Common units issued in connection with the vesting of phantom unit awards, net	3,553,313
Other	26,148
Common units outstanding at March 31, 2021	2,185,178,603

Registration Statements

We have a universal shelf registration statement (the “2019 Shelf”) on file with the SEC which allows ~~EPD~~the Partnership and EPO (each on a standalone basis) to issue an unlimited amount of equity and debt securities, respectively. ~~EPO issued $3.0 billion of senior notes in January 2020 using the 2019 Shelf (see Note 7).~~

In addition, ~~EPD~~the Partnership has a registration statement on file with the SEC covering the issuance of up to $2.54 billion of its common units in amounts, at prices and on terms ~~to be determined by~~based on market conditions and other factors at the time of such offerings ~~in connection with its~~(referred to as the Partnership’s at-the-market (“ATM”) ~~program. During the~~ ~~three months ended March 31, 2020~~ ~~and~~ ~~2019, EPD~~program). The Partnership did not issue any common units under its ATM ~~program.~~ ~~After taking into account~~program during the ~~aggregate sales price of common units sold under the ATM program through~~three months ended March 31, ~~2020, EPD has the~~2021. The Partnership’s capacity to issue additional common units under ~~its~~the ATM program ~~up to an aggregate sales price~~remains at $2.54 billion as of ~~$2.54 billion.~~March 31, 2021.

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

~~Settlement of Liquidity Option in March 2020~~

On February 25, 2020, the Partnership received notice from Marquard & Bahls AG (“M&B”) of its election to exercise its rights (the “Liquidity Option”) under the Liquidity Option Agreement among EPD, Oiltanking Holding Americas, Inc. (“OTA”) and M&B dated October 1, 2014 (the “Liquidity Option Agreement”). On March 5, 2020, we settled our obligations under the Liquidity Option Agreement by issuing 54,807,352 new EPD common units to Skyline North Americas, Inc. (“Skyline,” an affiliate of M&B) in exchange for the capital stock of OTA. Upon settlement of the Liquidity Option, we indirectly acquired the 54,807,352 EPD common units owned by OTA (which were issued to OTA in October 2014) and assumed all future income tax obligations of OTA, including its deferred tax liability. At March 5, 2020, OTA’s assets and liabilities consisted primarily of the EPD common units it owned and the related deferred tax liability, respectively.

At March 5, 2020, our accrual for the Liquidity Option liability was $511.9 million. The Liquidity Option liability, at any measurement date, represents the present value of estimated federal and state income taxes that we believe a market participant would incur due to ownership of OTA, including its deferred income tax liabilities. OTA’s deferred tax liability at March 5, 2020 was $439.7 million. The market value of the new EPD common units issued to Skyline was $1.3 billion based on a closing price of $23.67 per unit on March 5, 2020.

The 54,807,352 new EPD common units issued to Skyline upon settlement of the Liquidity Option constitute “restricted securities” in the meaning of Rule 144 under the Securities Act of 1933, as amended (the “Securities Act”) and may not be resold except pursuant to an effective registration statement or an available exemption under the Securities Act. In connection with the settlement of the Liquidity Option, Enterprise entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with Skyline. Pursuant to the Registration Rights Agreement, Skyline has the right to request that we prepare and file a registration statement to permit and otherwise facilitate the public resale of all or a portion of such EPD common units that Skyline and its affiliates then own. ~~Our obligation to Skyline to effect such transactions is limited to~~ 5 ~~registration statements and underwritten offerings.~~

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~~As a result of the Liquidity Option settlement, the partners’ equity balance for common units (as presented on our Unaudited Condensed Consolidated Balance Sheet) increased by the $1.3~~ ~~billion market value of the new EPD common units issued to Skyline. Since OTA does not meet the definition of a business as described in ASC 805,~~ ~~Business Combinations, the acquisition of OTA was accounted for as the purchase of treasury units and assumption of the related deferred tax liability.~~ ~~In consolidation, we present the~~ ~~54,807,352~~ ~~EPD common units owned by OTA as treasury units, with their historical cost based on the $1.3~~ ~~billion market value of the~~ ~~54,807,352~~ ~~new EPD common units issued to Skyline.~~

~~Upon settlement of the Liquidity Option, the Liquidity Option liability was effectively replaced by the deferred tax liability of OTA as calculated in accordance with ASC 740,~~ ~~Income Taxes. See Note 11 for additional information regarding OTA’s deferred tax liability.~~

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

~~In January 2020, management announced its intention to use approximately 2.0% of net cash flow provided by operating activities, or cash flow from operations (“CFFO”)~~During the three months ended March 31, 2021, ~~in 2020 to repurchase EPD common units under~~ the ~~2019 Buyback Program. EPD repurchased~~ ~~6,357,739 common units under the~~ ~~2019 Buyback Program through~~Partnership settled open market ~~purchases during~~repurchase transactions initiated in December 2020 involving an aggregate 709,816 common units. The total cost of these repurchases was $13.9 million including commissions and fees. During the three months ended March 31, 2020~~. The total purchase price of these repurchases (including commissions and fees) was $140.1 million.~~ ~~During~~, the ~~three months ended March 31, 2019, EPD~~Partnership repurchased ~~1,852,392~~6,357,739 common units under the 2019 Buyback Program for a total purchase price of $~~51.6~~140.1 ~~million.~~million including commissions and fees. Units ~~The units~~ repurchased ~~during~~under the ~~three months ended March 31, 2020 and~~ 2019 ~~were~~Buyback Program are immediately cancelled upon acquisition. At March 31, ~~2020,~~2021, the remaining available capacity under the 2019 Buyback Program was $~~1.78~~1.72 billion.

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

~~During the~~ ~~three months ended March 31, 2020, after~~After taking into account tax withholding requirements, ~~EPD~~the Partnership issued ~~a net~~ ~~2,912,214~~3,553,313 new common units to employees in connection with the vesting of phantom unit ~~awards.~~awards during the three months ended March 31, 2021. See Note 1312 for information regarding our phantom unit awards.

Common Units Delivered Under DRIP and EUPP

~~EPD~~The Partnership has registration statements on file with the SEC in connection with its distribution reinvestment plan (“DRIP”) and employee unit purchase plan (“EUPP”). In July 2019, ~~EPD~~the Partnership announced that, beginning with the quarterly distribution payment paid in August 2019, it would use common units purchased on the open market, rather than issuing new common units, to satisfy its delivery obligations under the DRIP and EUPP. This election is subject to change in future quarters depending on the ~~partnership’s~~Partnership’s need for equity capital. ~~In February 2020, a total~~During the three months ended March 31, 2021, agents of the Partnership purchased ~~1,422,063~~1,553,688 common units ~~were purchased~~ on the open market and delivered them to participants in ~~connection with~~ the DRIP and EUPP. Apart from $0.5 million attributable to the plan discount available to all participants in the EUPP, the funds used to effect these purchases were sourced from the DRIP and EUPP participants. No other ~~partnership~~Partnership funds were used to satisfy these obligations. We plan to use open market purchases to satisfy DRIP and EUPP reinvestments in connection with the distribution expected to be paid on May 12, ~~2020.~~2021.

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Preferred Units

The following table summarizes changes in the number of our Series A Cumulative Convertible Preferred Units (“preferred units”) outstanding since December 31, 2020:

Preferred units outstanding at December 31, 2020			50,138
Paid in-kind distribution to related party			274
Preferred units outstanding at March 31, 2021			50,412

We present the capital accounts attributable to our preferred unitholders as mezzanine equity on our consolidated balance sheets since the terms of the preferred units allow for cash redemption by such unitholders in the event of a Change of Control (as defined in our partnership agreement), without regard to the likelihood of such an event.

In February 2021, the Partnership made a quarterly distribution to its third party and related party preferred unitholders valued at $0.9 million, consisting of paid-in-kind distributions of 274 new preferred units and $0.6 million of cash.

In March 2021, a privately held affiliate of EPCO sold its entire ownership interest in the Partnership’s preferred units to third parties.

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												Cash Flow Hedges
	Commodity Derivative Instruments			Interest Rate Derivative Instruments			Other			Total			Commodity Derivative Instruments			Interest Rate Derivative Instruments			Other			Total
Accumulated Other Comprehensive Income, December 31, 2019	$	55.1		$	13.9		$	2.4		$	71.4
Accumulated Other Comprehensive Income (Loss), December 31, 2020													$	(93.2	)	$	(74.3	)	$	2.3		$	(165.2	)
Other comprehensive income (loss) for period, before reclassifications		475.1			(292.0	)		(0.1	)		183.0			(461.2	)		182.9			(0.2	)		(278.5	)
Reclassification of losses (gains) to net income during period		(155.6	)		23.5			–			(132.1	)		616.1			8.6			0			624.7
Total other comprehensive income (loss) for period		319.5			(268.5	)		(0.1	)		50.9			154.9			191.5			(0.2	)		346.2
Accumulated Other Comprehensive Income (Loss), March 31, 2020	$	374.6		$	(254.6	)	$	2.3		$	122.3
Accumulated Other Comprehensive Income, March 31, 2021													$	61.7		$	117.2		$	2.1		$	181.0

	Cash Flow Hedges												Cash Flow Hedges
	Commodity Derivative Instruments			Interest Rate Derivative Instruments			Other			Total			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
Accumulated Other Comprehensive Income, December 31, 2019													$	55.1		$	13.9		$	2.4		$	71.4
Other comprehensive income (loss) for period, before reclassifications		(95.2	)		–			(0.6	)		(95.8	)		475.1			(278.1	)		(0.1	)		196.9
Reclassification of losses (gains) to net income during period		(58.3	)		9.2			–			(49.1	)		(155.6	)		9.6			0			(146.0	)
Total other comprehensive income (loss) for period		(153.5	)		9.2			(0.6	)		(144.9	)		319.5			(268.5	)		(0.1	)		50.9
Accumulated Other Comprehensive Income (Loss), March 31, 2019	$	(0.8	)	$	(95.6	)	$	2.4		$	(94.0	)
Accumulated Other Comprehensive Income (Loss), March 31, 2020													$	374.6		$	(254.6	)	$	2.3		$	122.3

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

		For the Three Months Ended March 31,					For the Three Months Ended March 31,
	Location	2020		2019		Location	2021		2020
Losses (gains) on cash flow hedges:
Interest rate derivatives	Interest expense	$	23.5	$	9.2	Interest expense	$	8.6	$	9.6
Commodity derivatives	Revenue		(154.4)		(65.3)	Revenue		597.4		(154.4)
Commodity derivatives	Operating costs and expenses		(1.2)		7.0	Operating costs and expenses		18.7		(1.2)
Total		$	(132.1)	$	(49.1)		$	624.7	$	(146.0)

For information regarding our interest rate and commodity derivative instruments, see Note ~~14.~~13.

~~Cash Distributions~~

On March 18, 2020, the Board declared a quarterly cash distribution to be paid to our limited partners with respect to the first quarter of 2020 of $0.4450 per common unit, or $1.78 per unit on an annualized basis. The quarterly distribution associated with the first quarter of 2020 is payable on May 12, 2020, to unitholders of record as of the close of business on April 30, 2020. This distribution represents a 1.7% increase over the distribution declared with respect to the first quarter of 2019.

In light of current economic conditions, management will evaluate future cash distributions in 2020 on a quarterly basis. 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 payments.

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Cash Distributions

On April 8, 2021, we announced that the Board declared a quarterly cash distribution of $0.45 per common unit, or $1.80 per common unit on an annualized basis, to be paid to the Partnership’s common unitholders with respect to the first quarter of 2021. The quarterly distribution is payable on May 12, 2021 to unitholders of record as of the close of business on April 30, 2021. The total amount to be paid is $991.5 million, which includes $8.1 million for distribution equivalent rights (“DERs”) on phantom unit awards.

The payment of quarterly cash distributions is subject to management’s evaluation of our financial condition, results of operations and cash flows in connection with such payments and Board approval. In light of current economic conditions, management will evaluate any future increases in cash distributions on a quarterly basis.

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 March 31,				For the Three Months Ended March 31,
	2020		2019		2021		2020
NGL Pipelines & Services:
Sales of NGLs and related products	$	2,419.2	$	2,671.2	$	3,005.6	$	2,419.2
Segment midstream services:
Natural gas processing and fractionation		188.5		269.5		183.4		188.5
Transportation		265.0		275.3		274.6		265.0
Storage and terminals		95.4		98.4		119.9		95.4
Total segment midstream services		548.9		643.2		577.9		548.9
Total NGL Pipelines & Services		2,968.1		3,314.4		3,583.5		2,968.1
Crude Oil Pipelines & Services:
Sales of crude oil		1,696.9		2,328.4		1,838.9		1,696.9
Segment midstream services:
Transportation		218.4		183.7		208.8		218.4
Storage and terminals		123.6		95.2		117.8		123.6
Total segment midstream services		342.0		278.9		326.6		342.0
Total Crude Oil Pipelines & Services		2,038.9		2,607.3		2,165.5		2,038.9
Natural Gas Pipelines & Services:
Sales of natural gas		399.2		655.7		1,335.3		399.2
Segment midstream services:
Transportation		271.4		271.8		251.5		271.4
Total segment midstream services		271.4		271.8		251.5		271.4
Total Natural Gas Pipelines & Services		670.6		927.5		1,586.8		670.6
Petrochemical & Refined Products Services:
Sales of petrochemicals and refined products		1,597.5		1,480.6		1,598.9		1,597.5
Segment midstream services:
Fractionation and isomerization		35.8		40.8		53.5		35.8
Transportation, including marine logistics		134.9		126.6		116.7		134.9
Storage and terminals		36.7		46.3		50.4		36.7
Total segment midstream services		207.4		213.7		220.6		207.4
Total Petrochemical & Refined Products Services		1,804.9		1,694.3		1,819.5		1,804.9
Total consolidated revenues	$	7,482.5	$	8,543.5	$	9,155.3	$	7,482.5

Substantially all of our revenues are derived from contracts with customers as defined within ASC 606, Revenue from Contracts with Customers.

~~Unbilled Revenue and Deferred Revenue~~

~~The following table provides information regarding our contract assets and contract liabilities at March 31, 2020:~~

Contract Asset Location Balance
Unbilled revenue (current amount) Prepaid and other current assets $ 70.5
Total $ 70.5

Contract Liability Location Balance
Deferred revenue (current amount) Other current liabilities $ 134.0
Deferred revenue (noncurrent) Other long-term liabilities 208.7
Total $ 342.7

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Unbilled Revenue and Deferred Revenue

The following table provides information regarding our contract assets and contract liabilities at March 31, 2021:

Contract Asset	Location	Balance
Unbilled revenue (current amount)	Prepaid and other current assets	$	66.5
Total		$	66.5

Contract Liability	Location	Balance
Deferred revenue (current amount)	Other current liabilities	$	148.7
Deferred revenue (noncurrent)	Other long-term liabilities		216.7
Total		$	365.4

The following table presents significant changes in our unbilled revenue and deferred revenue balances ~~during~~for the three months ended March 31, ~~2020:~~2021:

	Unbilled Revenue			Deferred Revenue			Unbilled Revenue			Deferred Revenue
Balance at December 31, 2019	$	17.6		$	314.9
Balance at December 31, 2020							$	18.8		$	343.5
Amount included in opening balance transferred to other accounts during period (1)		(4.2	)		(64.8	)		(4.5	)		(105.0	)
Amount recorded during period(2)		65.6			170.9			56.0			248.5
Amounts recorded during period transferred to other accounts (1)		(8.5	)		(75.8	)		(3.8	)		(120.0	)
Other changes		–			(2.5	)		0			(1.6	)
Balance at March 31, 2020	$	70.5		$	342.7
Balance at March 31, 2021							$	66.5		$	365.4

(1)	Unbilled revenues are transferred to accounts receivable once we have an unconditional right to consideration from the customer. Deferred revenues are recognized as revenue upon satisfaction of our performance obligation to the customer.
(2)	Unbilled revenue represents revenue that has been recognized upon satisfaction of a performance obligation, but cannot be contractually invoiced (or billed) to the customer at the balance sheet date until a future period. Deferred revenue is recorded when payment is received from a customer prior to our satisfaction of the associated performance obligation.

Remaining Performance Obligations

The following table presents estimated fixed future consideration from revenue contracts that contain minimum volume commitments, deficiency and similar fees and the term of the contracts exceeds one year. These amounts represent the revenues we expect to recognize in future periods from these contracts as of March 31, ~~2020.~~2021.

Period	Fixed Consideration		Fixed Consideration
Nine Months Ended December 31, 2020	$	2,901.3
One Year Ended December 31, 2021		3,594.9
Nine Months Ended December 31, 2021			$	2,959.8
One Year Ended December 31, 2022		3,250.9		3,528.0
One Year Ended December 31, 2023		2,990.0		3,123.2
One Year Ended December 31, 2024		2,855.1		2,948.0
Thereafter		14,587.2
One Year Ended December 31, 2025				2,634.0
Thereafter 0				12,928.8
Total	$	30,179.4	$	28,121.8

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Note 10. Business Segments and Related Information

Our operations are reported under 4 business segments: (i) NGL Pipelines & Services, (ii) Crude Oil Pipelines & Services, (iii) Natural Gas Pipelines & Services and (iv) Petrochemical & Refined Products Services. Our business segments are generally organized and managed according to the types of services rendered (or technologies employed) and products produced and/or sold.

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

The following information summarizes the assets and operations of each business segment:

•	Our NGL Pipelines & Services business segment includes our natural gas processing and related NGL marketing activities, NGL pipelines, NGL fractionation facilities, NGL and related product storage facilities, and NGL marine terminals.

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

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

•

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

Segment Gross Operating Margin

We evaluate segment performance based on our financial measure of gross operating margin. Gross operating margin is an important performance measure of the core profitability of our operations and forms the basis of our internal financial reporting. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results. Gross operating margin is exclusive of other income and expense transactions, income taxes, the cumulative effect of changes in accounting principles and extraordinary charges. Gross operating margin is presented on a 100% basis before any allocation of earnings to noncontrolling interests. Our calculation of gross operating margin may or may not be comparable to similarly titled measures used by other companies.

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

	For the Three Months Ended March 31,						For the Three Months Ended March 31,
	2020			2019			2021			2020
Operating income	$	1,507.5		$	1,626.2		$	1,694.5		$	1,507.5
Adjustments to reconcile operating income to total segment gross operating margin (addition or subtraction indicated by sign):
Depreciation, amortization and accretion expense in operating costs and expenses(1)		482.8			450.9			496.1			482.8
Asset impairment and related charges in operating costs and expenses		1.6			4.8
Net losses (gains) attributable to asset sales in operating costs and expenses		0.1			(0.4	)
Asset impairment charges in operating costs and expenses								65.5			1.6
Net losses attributable to asset sales and related matters in operating costs and expenses								10.9			0.1
General and administrative costs		55.5			52.2			56.3			55.5
Non-refundable payments received from shippers attributable to make-up rights ~~(1)~~(2)		16.8			2.2			19.3			16.8
Subsequent recognition of revenues attributable to make-up rights ~~(2)~~(3)		(7.1	)		(7.5	)		(39.3	)		(7.1	)
Total segment gross operating margin	$	2,057.2		$	2,128.4		$	2,303.3		$	2,057.2

(1)	Excludes amortization of major maintenance costs for reaction-based plants, which are a component of gross operating margin.
(2)	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)~~(3)	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 March 31,				For the Three Months Ended March 31,
	2020		2019		2021		2020
Gross operating margin by segment:
NGL Pipelines & Services	$	1,042.0	$	959.2	$	1,086.4	$	1,042.0
Crude Oil Pipelines & Services		452.9		662.3		400.2		452.9
Natural Gas Pipelines & Services		283.8		264.3		535.2		283.8
Petrochemical & Refined Products Services		278.5		242.6		281.5		278.5
Total segment gross operating margin	$	2,057.2	$	2,128.4	$	2,303.3	$	2,057.2

2021

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

For the Three Months
Ended March 31,

2020 2019
Mark-to-market gains (losses) in gross operating margin:
NGL Pipelines & Services $ (12.3 ) $ 1.3
Crude Oil Pipelines & Services 10.7 99.8
Natural Gas Pipelines & Services 28.8 (0.3 )
Petrochemical & Refined Products Services 2.3 (4.5 )
Total mark-to-market impact on gross operating margin $ 29.5 $ 96.3

~~For information regarding our hedging activities, see Note 14.~~

Summarized Segment Financial Information

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

	Reportable Business Segments														Reportable Business Segments
	NGL Pipelines & Services		Crude Oil Pipelines & Services		Natural Gas Pipelines & Services		Petrochemical & Refined Products Services			Adjustments and Eliminations			Consolidated Total		NGL Pipelines & Services		Crude Oil Pipelines & Services		Natural Gas Pipelines & Services		Petrochemical & Refined Products Services			Adjustments and Eliminations			Consolidated Total
Revenues from third parties:
Three months ended March 31, 2021															$	3,580.7	$	2,157.0	$	1,583.9	$	1,819.5		$	0		$	9,141.1
Three months ended March 31, 2020	$	2,966.3	$	2,027.7	$	667.6	$	1,804.9		$	–		$	7,466.5		2,966.3		2,027.7		667.6		1,804.9			0			7,466.5
Three months ended March 31, 2019		3,311.6		2,601.6		923.7		1,694.3			–			8,531.2
Revenues from related parties:
Three months ended March 31, 2021																2.8		8.5		2.9		0			0			14.2
Three months ended March 31, 2020		1.8		11.2		3.0		–			–			16.0		1.8		11.2		3.0		0			0			16.0
Three months ended March 31, 2019		2.8		5.7		3.8		–			–			12.3
Intersegment and intrasegment revenues:
Three months ended March 31, 2021																13,088.6		7,420.1		145.8		6,234.2			(26,888.7	)		0
Three months ended March 31, 2020		5,780.7		7,840.3		115.1		808.1			(14,544.2	)		–		5,780.7		7,840.3		115.1		808.1			(14,544.2	)		0
Three months ended March 31, 2019		5,491.4		7,885.0		195.4		714.4			(14,286.2	)		–
Total revenues:
Three months ended March 31, 2021																16,672.1		9,585.6		1,732.6		8,053.7			(26,888.7	)		9,155.3
Three months ended March 31, 2020		8,748.8		9,879.2		785.7		2,613.0			(14,544.2	)		7,482.5		8,748.8		9,879.2		785.7		2,613.0			(14,544.2	)		7,482.5
Three months ended March 31, 2019		8,805.8		10,492.3		1,122.9		2,408.7			(14,286.2	)		8,543.5
Equity in income (loss) of unconsolidated affiliates:
Three months ended March 31, 2021																28.1		118.9		1.4		0.5			0			148.9
Three months ended March 31, 2020		32.7		107.3		1.6		(0.8	)		–			140.8		32.7		107.3		1.6		(0.8	)		0			140.8
Three months ended March 31, 2019		30.1		124.6		1.7		(1.8	)		–			154.6

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

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~~ENTERPRISE PRODUCTS PARTNERS L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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 March 31, 2020 $ 16,997.8 $ 6,340.2 $ 8,433.6 $ 7,570.1 $ 2,817.4 $ 42,159.1
At December 31, 2019 16,652.1 6,324.4 8,432.5 7,553.2 2,641.2 41,603.4
Investments in unconsolidated affiliates:
(see Note 5)

At March 31, 2020 699.1 1,877.5 27.9 4.0 – 2,608.5
At December 31, 2019 703.8 1,866.5 27.3 2.6 – 2,600.2
Intangible assets, net: (see Note 6)

At March 31, 2020 353.7 1,981.0 931.0 143.7 – 3,409.4
At December 31, 2019 360.2 2,001.9 941.2 145.7 – 3,449.0
Goodwill: (see Note 6)

At March 31, 2020 2,651.7 1,841.0 296.3 956.2 – 5,745.2
At December 31, 2019 2,651.7 1,841.0 296.3 956.2 – 5,745.2
Segment assets:
At March 31, 2020 20,702.3 12,039.7 9,688.8 8,674.0 2,817.4 53,922.2
At December 31, 2019 20,367.8 12,033.8 9,697.3 8,657.7 2,641.2 53,397.8

	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 March 31, 2021	$	17,121.5	$	7,015.1	$	8,355.8	$	7,554.7	$	2,055.3	$	42,102.4
At December 31, 2020		17,128.3		6,982.6		8,465.8		7,528.4		1,807.7		41,912.8
Investments in unconsolidated affiliates: (see Note 5)
At March 31, 2021		664.6		1,749.5		32.5		3.2		0		2,449.8
At December 31, 2020		671.6		1,723.7		31.4		2.5		0		2,429.2
Intangible assets, net: (see Note 6)
At March 31, 2021		328.1		1,918.8		881.2		131.7		0		3,259.8
At December 31, 2020		334.1		1,936.6		905.0		133.4		0		3,309.1
Goodwill: (see Note 6)
At March 31, 2021		2,651.7		1,841.0		0		956.2		0		5,448.9
At December 31, 2020		2,651.7		1,841.0		0		956.2		0		5,448.9
Segment assets:
At March 31, 2021		20,765.9		12,524.4		9,269.5		8,645.8		2,055.3		53,260.9
At December 31, 2020		20,785.7		12,483.9		9,402.2		8,620.5		1,807.7		53,100.0

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 March 31,					For the Three Months Ended March 31,
	2020		2019			2021		2020
Consolidated revenues:
NGL Pipelines & Services	$	2,968.1	$	3,314.4		$	3,583.5	$	2,968.1
Crude Oil Pipelines & Services		2,038.9		2,607.3			2,165.5		2,038.9
Natural Gas Pipelines & Services		670.6		927.5			1,586.8		670.6
Petrochemical & Refined Products Services		1,804.9		1,694.3			1,819.5		1,804.9
Total consolidated revenues	$	7,482.5	$	8,543.5		$	9,155.3	$	7,482.5

Consolidated costs and expenses
Operating costs and expenses:
Cost of sales	$	4,823.0	$	5,835.6		$	6,263.0	$	4,823.0
Other operating costs and expenses (1)		752.8		728.8			715.3		752.8
Depreciation, amortization and accretion		482.8		450.9			498.7		482.8
Asset impairment and related charges		1.6		4.8
Net losses (gains) attributable to asset sales		0.1		(0.4	)
Asset impairment charges							65.5		1.6
Net losses attributable to asset sales and related matters							10.9		0.1
General and administrative costs		55.5		52.2			56.3		55.5
Total consolidated costs and expenses	$	6,115.8	$	7,071.9		$	7,609.7	$	6,115.8

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

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

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~~ENTERPRISE PRODUCTS PARTNERS L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~Note 11. Income Taxes~~

Income taxes are accounted for under the asset-and-liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. We recognize the effect of income tax positions only if those positions are more likely than not of being sustained. Recognized income tax positions are measured at the largest amount that is greater than 50% likely of being realized. Changes in recognition or measurement are reflected in the period in which the change in judgment occurs. ~~We did not rely on any uncertain tax positions in recording our income tax-related amounts during the first quarters of 2020 and 2019.~~

~~OTA Deferred Tax Liability~~

On March 5, 2020, we settled the Liquidity Option (see Note 8) and assumed OTA’s deferred tax liability, which primarily comprised the outside basis difference of OTA in the 54,807,352 EPD common units it received in October 2014. ~~Upon settlement of the Liquidity Option, the Liquidity Option liability was effectively replaced by the deferred tax liability of OTA as calculated in accordance with ASC 740,~~ ~~Income Taxes. At March 5, 2020, the Liquidity Option liability amount was $511.9~~ ~~million. Since the book value of the Liquidity Option liability exceeded OTA’s estimated deferred tax liability of $439.7~~ ~~million on that date, we recognized a non-cash benefit in earnings of $72.2~~ ~~million, which is reflected in the “Benefit from (provision for) income tax” line on our Unaudited Condensed Statement of Consolidated Operations for the three months ended March 31, 2020.~~ At March 31, 2020, OTA’s deferred tax liability decreased to $324.7 million primarily due to a decline in the fair value of OTA’s assets, which resulted in an additional non-cash benefit of $115.0 million in income tax expense for the first quarter of 2020. In total, earnings for the first quarter of 2020 reflect $187.2 million of unrealized income tax benefits related to OTA. ~~The following table presents changes in OTA’s deferred tax liability since the settlement date to March 31, 2020:~~

Deferred tax liability at March 5, 2020 $ 439.7
Impact of change in fair value of units on deferred tax liability:
Change in fair value of 54,807,352 EPD common units held by OTA (1) $ (513.5 )
Multiplied by estimated blended federal and state tax rate 22.4 % (114.8 )
Other, including interim allocations of taxable income (0.2 )
Deferred tax liability at March 31, 2020 $ 324.7

~~(1)~~

~~The market price of EPD common units declined from $23.67 per unit at March 5, 2020 (settlement date of the Liquidity Option) to $14.30 per unit on March 31, 2020.~~

The deferred tax liability of OTA will continue to be subject to periodic fluctuations due to changes in the market value of the EPD common units currently held, the resulting changes of which will be recognized through income tax expense (benefit) on our Unaudited Condensed Statements of Consolidated Operations. For example, if the market price of EPD common units increases between reporting dates, we expect to recognize deferred income tax expense in connection with an anticipated increase in OTA’s deferred tax liability. Conversely, if the market price of EPD common units decreases between reporting dates, we expect to recognize a deferred income tax benefit in connection with an anticipated decrease in OTA’s deferred tax liability.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~Tabular Disclosures Regarding Income Taxes~~

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

For the Three Months
Ended March 31,

2020 2019
Current portion of income tax provision (benefit):
Federal $ 0.1 $ 0.9
State 4.6 9.0
Foreign 0.2 0.6
Total current portion 4.9 10.5
Deferred portion of income tax provision (benefit):
Federal (172.8 ) (0.1 )
State (11.3 ) 1.9
Total deferred portion (184.1 ) 1.8
Total provision for (benefit from) income taxes $ (179.2 ) $ 12.3

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

For the Three Months
Ended March 31,

2020 2019
Pre-Tax Net Book Income (“NBI”) $ 1,195.8 $ 1,292.7

Texas Margin Tax (1) 7.7 10.9
State income taxes (net of federal benefit) (2) (11.3 ) 0.2
Federal income taxes computed by applying the federal
statutory rate to NBI of corporate entities
(107.8 ) 1.2
Federal benefit attributable to settlement of Liquidity Option (2) (67.8 ) –
Provision for (benefit from) income taxes $ (179.2 ) $ 12.3

Effective income tax rate (15.0 )% 1.0 %

~~(1)~~	Although the Texas Margin Tax is not considered a state income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers our Texas-sourced revenues and expenses.
~~(2)~~	The total benefit recognized in income tax expense on March 5, 2020 from settlement of the Liquidity Option was $72.2 million, which is comprised of $4.4 million of state income tax benefit and $67.8 million of federal income tax benefit.

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

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~~ENTERPRISE PRODUCTS PARTNERS L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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

March 31, December 31,
2020 2019
Deferred tax liabilities:
Attributable to investment in OTA $ 324.7
Attributable to property, plant and equipment 103.2 $ 100.2
Attributable to investments in other entities 3.3 3.3
Total deferred tax liabilities 431.2 103.5
Less deferred tax assets:
Net operating loss carryovers (1) 0.1 0.1
Temporary differences related to Texas Margin Tax 2.9 3.0
Total deferred tax assets 3.0 3.1
Total net deferred tax liabilities $ 428.2 $ 100.4

~~(1)~~

~~These losses expire in various years between 2020 and 2037 and are subject to limitations on their utilization.~~

Note ~~12.~~11. Earnings Per Unit

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

	For the Three Months Ended March 31,						For the Three Months Ended March 31,
	2020			2019			2021			2020
BASIC EARNINGS PER UNIT
Net income attributable to limited partners	$	1,350.1		$	1,260.5
BASIC EARNINGS PER COMMON UNIT
Net income attributable to common unitholders							$	1,340.4		$	1,350.1
Earnings allocated to phantom unit awards (1)		(9.9	)		(7.8	)		(11.0	)		(9.9	)
Net income available to common unitholders	$	1,340.2		$	1,252.7
Net income allocated to common unitholders							$	1,329.4		$	1,340.2

Basic weighted-average number of common units outstanding		2,188.9			2,187.1			2,183.4			2,188.9

Basic earnings per unit	$	0.61		$	0.57
Basic earnings per common unit							$	0.61		$	0.61

DILUTED EARNINGS PER UNIT
DILUTED EARNINGS PER COMMON UNIT
Net income attributable to common unitholders							$	1,340.4		$	1,350.1
Net income attributable to preferred units								0.9			0
Net income attributable to limited partners	$	1,350.1		$	1,260.5		$	1,341.3		$	1,350.1

Diluted weighted-average number of units outstanding:
Distribution-bearing common units		2,188.9			2,187.1			2,183.4			2,188.9
Phantom units (1)		15.1			12.4
Phantom units (2)								17.4			15.1
Preferred units (2)								2.5			0
Total		2,204.0			2,199.5			2,203.3			2,204.0

Diluted earnings per unit	$	0.61		$	0.57
Diluted earnings per common unit							$	0.61		$	0.61

(1)	Phantom units are considered participating securities for purposes of computing basic earnings per unit. See Note 1312 for information regarding our phantom units.
(2)	We use the “if-converted method” to determine the potential dilutive effect of the vesting of phantom unit awards and the conversion of preferred units outstanding. See Note 12 for information regarding phantom unit awards. See Note 8 for information regarding preferred units.

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~~ENTERPRISE PRODUCTS PARTNERS L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

Note ~~13.~~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 March 31,				For the Three Months Ended March 31,
	2020		2019		2021		2020
Equity-classified awards:
Phantom unit awards	$	36.2	$	29.4	$	38.0	$	36.2
Profits interest awards		2.9		2.6		1.1		2.9
Total	$	39.1	$	32.0	$	39.1	$	39.1

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

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Phantom Unit Awards

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

	Number of Units			Weighted- Average Grant Date Fair Value per Unit (1)		Number of Units			Weighted- Average Grant Date Fair Value per Unit (1)
Phantom unit awards at December 31, 2019		12,974,684		$	27.21
Phantom unit awards at December 31, 2020							15,669,442		$	26.76
Granted (2)		7,397,845		$	25.72		7,700,645		$	21.30
Vested		(4,204,938	)	$	26.32		(5,141,095	)	$	27.19
Forfeited		(22,624	)	$	26.92		(119,963	)	$	25.08
Phantom unit awards at March 31, 2020		16,144,967		$	26.76
Phantom unit awards at March 31, 2021							18,109,029		$	24.32

(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 ~~2020~~2021 was ~~$190.3~~$164.0 million based on a grant date market price of ~~EPD~~the Partnership’s common units ranging from ~~$24.98~~$20.79 to ~~$25.76~~$21.44 per unit. An estimated annual forfeiture rate of ~~2.4%~~2.0% was applied to these awards.

Each phantom unit award includes a ~~distribution equivalent right (“DER”),~~DER, which entitles the participant to nonforfeitable cash payments equal to the product of the number of phantom unit awards outstanding for the participant and the cash distribution per common unit paid by ~~EPD~~the Partnership to its common unitholders. Cash payments made in connection with DERs are charged to partners’ equity when the phantom unit award is expected to result in the issuance of common units; otherwise, such amounts are expensed.

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

	For the Three Months Ended March 31,				For the Three Months Ended March 31,
	2020		2019		2021		2020
Cash payments made in connection with DERs	$	5.8	$	4.5	$	7.0	$	5.8
Total intrinsic value of phantom unit awards that vested during period		109.2		97.0		112.7		109.2

For the EPCO group of companies, the unrecognized compensation cost associated with phantom unit awards was ~~$278.7~~$269.8 million at March 31, ~~2020,~~2021, of which our share of such cost is currently estimated to be ~~$239.8~~$229.2 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 2.3 years.

Profits Interest Awards

EPCO has established four 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 March 31, 2021, our share of the total unrecognized compensation cost related to the Employee Partnerships was $14.9 million, which we expect to recognize over a weighted-average period of 2.6years.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~Profits Interest Awards~~

EPCO currently serves as the general partner for each of four limited partnerships (referred to as “Employee Partnerships”) that serve as long-term incentive arrangements for key employees of EPCO by providing such employees a profits interest in one or more of the Employee Partnerships. The profits interest in a fifth Employee Partnership (EPD PubCo Unit I L.P.) fully vested in February 2020 and the partnership was liquidated. At ~~March 31, 2020, our share of the total unrecognized compensation cost related to the four remaining Employee Partnerships was $21.0 million, which we expect to recognize over a weighted-average period of 3.2 years.~~

Note ~~14. Derivative Instruments,~~13. Hedging Activities and Fair Value Measurements

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

Interest Rate Hedging Activities

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

Forward-Starting Swaps

~~The following table summarizes our portfolio~~As a result of ~~30-year forward-starting swaps at March 31, 2020, all of which are associated with the expected future issuance of senior notes.~~

Hedged Transaction
Number and Type
of Derivatives
Outstanding
Notional
Amount
Expected
Settlement
Date
Weighted-Average
Fixed Rate
Locked
Accounting
Treatment
Future long-term debt offering 1 forward-starting swap $75.0 4/2021 2.41% Cash flow hedge
Future long-term debt offering 5 forward-starting swaps $500.0 4/2021 2.13% Cash flow hedge
Future long-term debt offering 2 forward-starting swaps (1) $150.0 2/2022 1.72% Cash flow hedge
Future long-term debt offering 1 forward starting swap (1) $100.0 4/2021 1.46% Cash flow hedge
Future long-term debt offering 2 forward starting swaps (1) $150.0 2/2022 1.48% Cash flow hedge
Future long-term debt offering 2 forward starting swaps (1) $100.0 2/2022 0.95% Cash flow hedge

~~(1)~~

~~These swaps were entered into during the three months ended March 31, 2020.~~

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

~~In January 2020,~~favorable market conditions, we terminated an aggregate ~~$575~~$675.0 million notional amount of forward-starting swaps in March 2021, which resulted in a net cash payment of $0.1 million. Since the original swaptions associated with these forward-starting swaps were not designated as hedging instruments and were subject to mark-to-market accounting, we previously incurred an unrealized, mark-to-market loss at inception of the forward starting swaps of $47.6 million that was reflected as an increase in interest expense in 2019. Immediately following exercise of the swaptions and our being put into the forward-starting swaps, these instruments were designated as cash flow hedges. For the period from inception through the termination date in March 2021, we recognized cumulative gains on the forward-starting swaps of $47.5 million in accumulated other comprehensive income, of which $45.9 million will be reclassified to earnings (as a decrease in interest expense) over the life of the associated debt obligations. We reclassified $1.6 million of the cumulative gain as a decrease in interest expense in March 2021.

We terminated an additional aggregate $400.0 million notional amount of forward-starting swaps in March 2021 due to favorable market conditions, which resulted in net cash ~~payments~~proceeds of ~~$33.3~~$75.3 million. ~~These swaps were unwound~~As cash flow hedges, gains on these derivative instruments are reflected as a component of accumulated other comprehensive income and will be reclassified to earnings (as a decrease in ~~connection with our issuance~~interest expense) over the life of ~~Senior Notes BBB due January 2051.~~the associated future debt obligations.

As a result of these terminations, we do not have any interest rate derivative instruments outstanding at March 31, 2021.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 March 31, ~~2020,~~2021, 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 and (iii) hedging natural gas processing margins.~~inventory.

The following table summarizes our portfolio of commodity derivative instruments outstanding at March 31, ~~2020~~2021 (volume measures as noted):

	Volume (1)		Accounting	Volume (1)		Accounting
Derivative Purpose	Current (2)	Long-Term (2)	Treatment	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”))	11.9	n/a	Cash flow hedge	20.3	n/a	Cash flow hedge
Octane enhancement:
Forecasted purchase of NGLs (MMBbls)	0.7	n/a	Cash flow hedge	0.1	n/a	Cash flow hedge
Forecasted sales of octane enhancement products (MMBbls)	13.6	n/a	Cash flow hedge	0.4	n/a	Cash flow hedge
Natural gas marketing:
Forecasted purchase of natural gas (Bcf)	4.5	n/a	Cash flow hedge
Natural gas storage inventory management activities (Bcf)	4.4	n/a	Fair value hedge	2.8	n/a	Fair value hedge
NGL marketing:
Forecasted purchases of NGLs and related hydrocarbon products (MMBbls)	126.3	0.4	Cash flow hedge	132.9	2.7	Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products (MMBbls)	140.0	2.2	Cash flow hedge	139.7	4.2	Cash flow hedge
NGLs inventory management activities (MMBbls)	0.8	n/a	Fair value hedge	2.6	n/a	Fair value hedge
Refined products marketing:
Forecasted purchases of refined products (MMBbls)	5.1	n/a	Cash flow hedge	25.8	n/a	Cash flow hedge
Forecasted sales of refined products (MMBbls)	6.8	n/a	Cash flow hedge	37.4	n/a	Cash flow hedge
Refined products inventory management activities (MMBbls)	0.5	n/a	Fair value hedge	1.3	n/a	Fair value hedge
Crude oil marketing:
Forecasted purchases of crude oil (MMBbls)	24.5	n/a	Cash flow hedge	17.9	n/a	Cash flow hedge
Forecasted sales of crude oil (MMBbls)	31.4	n/a	Cash flow hedge	27.0	n/a	Cash flow hedge
Propylene marketing:
Forecasted sales of NGLs for propylene marketing activities (MMBbls)	0.6	n/a	Cash flow hedge
Commercial energy:
Forecasted purchases of power related to asset operations (terawatt hours (“TWh”))	0.2	n/a	Cash flow hedge
Petrochemical marketing:
Forecasted purchases of petrochemical products (MMBbls)				1.1	n/a	Cash flow hedge
Forecasted sales of petrochemical products (MMBbls)				1.0	n/a	Cash flow hedge
Derivatives not designated as hedging instruments:
Natural gas risk management activities (Bcf) (3)	54.5	0.3	Mark-to-market	26.3	0.4	Mark-to-market
NGL risk management activities (MMBbls) (3)	15.7	n/a	Mark-to-market	31.7	21.1	Mark-to-market
Refined products risk management activities (MMBbls) (3)	5.1	n/a	Mark-to-market	14.2	n/a	Mark-to-market
Crude oil risk management activities (MMBbls) (3)	33.9	9.0	Mark-to-market	32.0	2.4	Mark-to-market
Commercial energy risk management activities (TWh) (3)	0.1	n/a	Mark-to-market

(1)	Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes.
(2)	The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is December 2022, December 2021 ~~December 2020~~ and ~~December 2022,~~October 2023, respectively.
(3)	Reflects the use of derivative instruments to manage risks associated with our transportation, processing and storage ~~assets and end use power requirements.~~assets.

The carrying amount of our inventories subject to fair value hedges was ~~$28.1~~$256.8 million and ~~$31.7~~$144.0 million at March 31, ~~2020~~2021 and December 31, ~~2019,~~2020, respectively.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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						Asset Derivatives						Liability Derivatives
	March 31, 2020			December 31, 2019			March 31, 2020			December 31, 2019			March 31, 2021			December 31, 2020			March 31, 2021			December 31, 2020
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments
Interest rate derivatives	Current assets	$	–	Current assets	$	–	Current liabilities	$	–	Current liabilities	$	6.7	Current assets	$	0	Current assets	$	0	Current liabilities	$	0	Current liabilities	$	109.1
Interest rate derivatives	Other assets		–	Other assets		–	Other liabilities		258.3	Other liabilities		6.8	Other assets		0	Other assets		12.4	Other liabilities		0	Other liabilities		11.0
Total interest rate derivatives			–			–			258.3			13.5			0			12.4			0			120.1
Commodity derivatives	Current assets		310.7	Current assets		116.5	Current liabilities		244.6	Current liabilities		107.1	Current assets		289.3	Current assets		210.5	Current liabilities		233.4	Current liabilities		234.0
Commodity derivatives	Other assets		–	Other assets		–	Other liabilities		–	Other liabilities		–	Other assets		0.9	Other assets		0.4	Other liabilities		9.5	Other liabilities		6.1
Total commodity derivatives			310.7			116.5			244.6			107.1			290.2			210.9			242.9			240.1
Total derivatives designated as hedging instruments		$	310.7		$	116.5		$	502.9		$	120.6		$	290.2		$	223.3		$	242.9		$	360.2

Derivatives not designated as hedging instruments
Commodity derivatives	Current assets	$	55.1	Current assets	$	10.7	Current liabilities	$	24.6	Current liabilities	$	8.6	Current assets	$	33.7	Current assets	$	18.1	Current liabilities	$	6.0	Current liabilities	$	6.1
Commodity derivatives	Other assets		5.1	Other assets		0.6	Other liabilities		3.0	Other liabilities		0.5	Other assets		1.0	Other assets		0.2	Other liabilities		0.6	Other liabilities		0.1
Total commodity derivatives			60.2			11.3			27.6			9.1			34.7			18.3			6.6			6.2
Total derivatives not designated as hedging instruments		$	60.2		$	11.3		$	27.6		$	9.1		$	34.7		$	18.3		$	6.6		$	6.2

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																							Offsetting of Financial Assets and Derivative Assets
	Gross Amounts of Recognized Assets			Gross Amounts Offset in the Balance Sheet			Amounts of Assets Presented in the Balance Sheet			Gross Amounts Not Offset in the Balance Sheet											Amounts That Would Have Been Presented On Net Basis			Gross Amounts of Recognized Assets			Gross Amounts Offset in the Balance Sheet			Amounts of Assets Presented in the Balance Sheet			Gross Amounts Not Offset in the Balance Sheet									Amounts That Would Have Been Presented On Net Basis
	Gross Amounts of Recognized Assets			Gross Amounts Offset in the Balance Sheet			Amounts of Assets Presented in the Balance Sheet			Financial Instruments				Cash Collateral Received			Cash Collateral Paid				Amounts That Would Have Been Presented On Net Basis			Gross Amounts of Recognized Assets			Gross Amounts Offset in the Balance Sheet			Amounts of Assets Presented in the Balance Sheet			Financial Instruments				Cash Collateral Received			Cash Collateral Paid		Amounts That Would Have Been Presented On Net Basis
	(i)			(ii)			(iii) = (i) – (ii)			(iv)											(v) = (iii) + (iv)			(i)			(ii)			(iii) = (i) – (ii)			(iv)									(v) = (iii) + (iv)
As of March 31, 2020:
As of March 31, 2021:
Commodity derivatives		$	370.9		$	–		$	370.9		$	(267.0	)		$	–		$	(100.6	)		$	3.3		$	324.9		$	0		$	324.9		$	(248.7	)	$	(68.0	)	$	0		$	8.2
As of December 31, 2019:
As of December 31, 2020:
Interest rate derivatives																									$	12.4		$	0		$	12.4		$	0		$	0		$	0		$	12.4
Commodity derivatives		$	127.8		$	–		$	127.8		$	(115.3	)		$	–		$	(11.0	)		$	1.5			229.2			0			229.2			(228.5	)		0			0			0.7

	Offsetting of Financial Liabilities and Derivative Liabilities																				Offsetting of Financial Liabilities and Derivative Liabilities
	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheet			Amounts of Liabilities Presented in the Balance Sheet			Gross Amounts Not Offset in the Balance Sheet								Amounts That Would Have Been Presented On Net Basis			Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheet			Amounts of Liabilities Presented in the Balance Sheet			Gross Amounts Not Offset in the Balance Sheet									Amounts That Would Have Been Presented On Net Basis
	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheet			Amounts of Liabilities Presented in the Balance Sheet			Financial Instruments				Cash Collateral Received		Cash Collateral Paid		Amounts That Would Have Been Presented On Net Basis			Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheet			Amounts of Liabilities Presented in the Balance Sheet			Financial Instruments				Cash Collateral Received		Cash Collateral Paid			Amounts That Would Have Been Presented On Net Basis
	(i)			(ii)			(iii) = (i) – (ii)			(iv)								(v) = (iii) + (iv)			(i)			(ii)			(iii) = (i) – (ii)			(iv)									(v) = (iii) + (iv)
As of March 31, 2020:
As of March 31, 2021:
Commodity derivatives																						$	249.5		$	0		$	249.5		$	(248.7	)	$	0	$	0			$	0.8
As of December 31, 2020:
Interest rate derivatives		$	258.3		$	–		$	258.3		$	–		$	–	$	–		$	258.3		$	120.1		$	0		$	120.1		$	0		$	0	$	0			$	120.1
Commodity derivatives			272.2			–			272.2			(267.0	)		–		–			5.2			246.3			0			246.3			(228.5	)		0		(17.3	)			0.5
As of December 31, 2019:
Interest rate derivatives		$	13.5		$	–		$	13.5		$	–		$	–	$	–		$	13.5
Commodity derivatives			116.2			–			116.2			(115.3	)		–		–			0.9

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

Derivatives in Fair Value Hedging Relationships	Location	Gain (Loss) Recognized in Income on Derivative					Location	Gain (Loss) Recognized in Income on Derivative
		For the Three Months Ended March 31,						For the Three Months Ended March 31,
		2020		2019				2021			2020
Commodity derivatives	Revenue	$	3.9	$	(8.5	)	Revenue	$	(120.0	)	$	3.9
Total		$	3.9	$	(8.5	)		$	(120.0	)	$	3.9

Derivatives in Fair Value Hedging Relationships	Location	Gain (Loss) Recognized in Income on Hedged Item					Location	Gain (Loss) Recognized in Income on Hedged Item
		For the Three Months Ended March 31,						For the Three Months Ended March 31,
		2020			2019			2021		2020
Commodity derivatives	Revenue	$	(8.2	)	$	9.9	Revenue	$	169.7	$	(8.2	)
Total		$	(8.2	)	$	9.9		$	169.7	$	(8.2	)

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

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

Derivatives in Cash Flow Hedging Relationships	Change in Value Recognized in Other Comprehensive Income (Loss) on Derivative						Change in Value Recognized in Other Comprehensive Income (Loss) on Derivative
	For the Three Months Ended March 31,						For the Three Months Ended March 31,
	2020			2019			2021			2020
Interest rate derivatives	$	(292.0	)	$	–		$	182.9		$	(278.1	)
Commodity derivatives – Revenue (1)		477.8			(86.7	)		(442.2	)		477.8
Commodity derivatives – Operating costs and expenses (1)		(2.7	)		(8.5	)		(19.0	)		(2.7	)
Total	$	183.1		$	(95.2	)	$	(278.3	)	$	197.0

(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~~when the ~~underlying derivative~~forecasted transactions ~~as appropriate.~~affect earnings.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Derivatives in Cash Flow Hedging Relationships	Location	Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income						Location	Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income
		For the Three Months Ended March 31,							For the Three Months Ended March 31,
		2020			2019				2021			2020
Interest rate derivatives	Interest expense	$	(23.5	)	$	(9.2	)	Interest expense	$	(8.6	)	$	(9.6	)
Commodity derivatives	Revenue		154.4			65.3		Revenue		(597.4	)		154.4
Commodity derivatives	Operating costs and expenses		1.2			(7.0	)	Operating costs and expenses		(18.7	)		1.2
Total		$	132.1		$	49.1			$	(624.7	)	$	146.0

Over the next twelve months, we expect to reclassify $39.8 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 ~~$363.1~~$92.1 million of gains attributable to commodity derivative instruments from accumulated other comprehensive income to earnings, ~~$366.7~~with $92.0 million as an increase in revenue and ~~$3.6~~$0.1 million as ~~an increase~~a decrease 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					Location	Gain (Loss) Recognized in Income on Derivative
		For the Three Months Ended March 31,						For the Three Months Ended March 31,
		2020			2019			2021			2020
Commodity derivatives	Revenue	$	63.5		$	95.1	Revenue	$	(43.1	)	$	63.5
Commodity derivatives	Operating costs and expenses		(0.1	)		0.1	Operating costs and expenses		0.9			(0.1	)
Total		$	63.4		$	95.2		$	(42.2	)	$	63.4

The ~~$63.4~~$42.2 million ~~gain~~loss recognized for the three months ended March 31, ~~2020~~2021 (as noted in the preceding table) from derivatives not designated as hedging instruments consists of ~~$20.6~~$104.5 million of realized ~~gains~~losses and ~~$42.8~~$62.3 million of net unrealized mark-to-market gains attributable to commodity derivatives.

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.

~~Table of Contents~~

~~ENTERPRISE PRODUCTS PARTNERS L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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

At March 31, 2020
Fair Value Measurements Using

Quoted Prices
in Active
Markets for
Identical Assets
and Liabilities
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)
Total
Financial assets:
Commodity derivatives:
Value before application of CME Rule 814 $ 764.5 $ 938.1 $ 14.3 $ 1,716.9
Impact of CME Rule 814 (723.9 ) (609.7 ) (12.4 ) (1,346.0 )
Total commodity derivatives 40.6 328.4 1.9 370.9
Total $ 40.6 $ 328.4 $ 1.9 $ 370.9

Financial liabilities:
Interest rate derivatives $ – $ 258.3 $ – $ 258.3
Commodity derivatives:
Value before application of CME Rule 814 531.1 912.9 5.3 1,449.3
Impact of CME Rule 814 (490.9 ) (685.5 ) (0.7 ) (1,177.1 )
Total commodity derivatives 40.2 227.4 4.6 272.2
Total $ 40.2 $ 485.7 $ 4.6 $ 530.5

At December 31, 2019
Fair Value Measurements Using

Quoted Prices
in Active
Markets for
Identical Assets
and Liabilities
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)
Total
Financial assets:
Commodity derivatives:
Value before application of CME Rule 814 $ 53.4 $ 343.7 $ 0.1 $ 397.2
Impact of CME Rule 814 (47.0 ) (222.4 ) – (269.4 )
Total commodity derivatives 6.4 121.3 0.1 127.8
Total $ 6.4 $ 121.3 $ 0.1 $ 127.8

Financial liabilities:
Liquidity Option (see Note 8) $ – $ – $ 509.6 $ 509.6
Interest rate derivatives – 13.5 – 13.5
Commodity derivatives:
Value before application of CME Rule 814 88.1 273.6 0.3 362.0
Impact of CME Rule 814 (81.9 ) (163.9 ) – (245.8 )
Total commodity derivatives 6.2 109.7 0.3 116.2
Total $ 6.2 $ 123.2 $ 509.9 $ 639.3

~~In the aggregate, the fair value of our commodity hedging portfolios at~~ ~~March 31, 2020~~ ~~was a net derivative asset of $267.6million prior to the impact of CME Rule 814.~~

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	At March 31, 2021 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	$	719.7		$	1,155.6		$	2.5		$	1,877.8
Impact of CME Rule 814		(719.7	)		(831.9	)		(1.3	)		(1,552.9	)
Total commodity derivatives		0			323.7			1.2			324.9
Total	$	0		$	323.7		$	1.2		$	324.9

Financial liabilities:
Commodity derivatives:
Value before application of CME Rule 814	$	1,270.7		$	947.3		$	0.5		$	2,218.5
Impact of CME Rule 814		(1,270.7	)		(698.2	)		(0.1	)		(1,969.0	)
Total commodity derivatives		–			249.1			0.4			249.5
Total	$	0		$	249.1		$	0.4		$	249.5

	At December 31, 2020 Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total
Financial assets:
Interest rate derivatives	$	0		$	12.4		$	0		$	12.4
Commodity derivatives:
Value before application of CME Rule 814		678.6			878.6			12.9			1,570.1
Impact of CME Rule 814		(678.6	)		(650.4	)		(11.9	)		(1,340.9	)
Total commodity derivatives		0			228.2			1.0			229.2
Total	$	0		$	240.6		$	1.0		$	241.6

Financial liabilities:
Interest rate derivatives	$	0		$	120.1		$	0		$	120.1
Commodity derivatives:
Value before application of CME Rule 814		1,065.6			1,047.4			25.9			2,138.9
Impact of CME Rule 814		(1,065.6	)		(807.3	)		(19.7	)		(1,892.6	)
Total commodity derivatives		0			240.1			6.2			246.3
Total	$	0		$	360.2		$	6.2		$	366.4

In the aggregate, the fair value of our commodity hedging portfolios at March 31, 2021 was a net derivative liability of $340.7million prior to the impact of CME Rule 814.

Financial assets and liabilities recorded on the balance sheet at March 31, ~~2020~~2021 using significant unobservable inputs (Level 3) are not material to the Unaudited Condensed Consolidated Financial Statements. ~~Refer to Note 8 for discussion of the settlement of the Liquidity Option in March 2020 and Note 11 for the income tax impact related to this transaction.~~

Nonrecurring Fair Value Measurements

~~Non-cash~~We did not have any significant nonrecurring fair value measurements at March 31, 2021 or 2020.

See Note 4 for information regarding other non-cash asset impairment ~~charges for the three months ended March~~ charges.

31 2020 were $1.6 million compared to $4.8 million for the three months ended March 31, 2019. Charges for 2020 primarily relate to assets retired during the quarter whose operations have ceased. Impairment charges are a component

Table of ~~“Operating costs and expenses” on our Unaudited Condensed Statements of Consolidated Operations.~~Contents

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Other Fair Value Information

The carrying amounts of cash and cash equivalents (including restricted cash balances), accounts receivable, commercial paper notes and accounts payable approximate their fair values based on their short-term nature. The estimated total fair value of our fixed-rate debt obligations was ~~$28.77~~$31.72 billion and ~~$30.37~~$35.00 billion at March 31, ~~2020~~2021 and December 31, ~~2019,~~2020, respectively. The aggregate carrying value of these debt obligations was ~~$29.65~~$28.58 billion and ~~$27.15~~$29.90 billion at March 31, ~~2020~~2021 and December 31, ~~2019,~~2020, 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 ~~15.~~14. Related Party Transactions

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

	For the Three Months Ended March 31,				For the Three Months Ended March 31,
	2020		2019		2021		2020
Revenues – related parties:
Unconsolidated affiliates	$	16.0	$	12.3	$	14.2	$	16.0
Costs and expenses – related parties:
EPCO and its privately held affiliates	$	286.0	$	272.9	$	292.2	$	286.0
Unconsolidated affiliates		71.5		123.3		66.7		71.5
Total	$	357.5	$	396.2	$	358.9	$	357.5

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

	March 31, 2020		December 31, 2019		March 31, 2021		December 31, 2020
Accounts receivable - related parties:
EPCO and its privately held affiliates					$	1.8	$	1.9
Unconsolidated affiliates	$	1.9	$	2.5		5.2		3.7
Total					$	7.0	$	5.6

Accounts payable - related parties:
EPCO and its privately held affiliates	$	59.8	$	143.7	$	73.3	$	139.6
Unconsolidated affiliates		9.6		18.6		11.8		9.9
Total	$	69.4	$	162.3	$	85.1	$	149.5

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.

~~Table of Contents~~

~~ENTERPRISE PRODUCTS PARTNERS L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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 March 31, ~~2020,~~2021, 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
701,956,852 32.1%

Total Number of Limited Partner Interests Held	Percentage of Common Units Outstanding
702,863,875 common units	32.2%

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Of the total number of Partnership common units held by EPCO and its privately held affiliates, ~~108,222,618~~92,976,464 have been pledged as security under the separate credit facilities of EPCO and its privately held affiliates at March 31, ~~2020.~~2021. 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~~the Partnership’s common units.

WeThe Partnership and Enterprise GP are both separate legal entities apart from each other and apart from EPCO and its other affiliates, with assets and liabilities that are also separate from those of EPCO and its other affiliates. EPCO and its privately held affiliates depend on the cash distributions they receive from us and other investments to fund their other activities and to meet their respective debt obligations. During the three months ended March 31, ~~2020~~2021 and ~~2019,~~2020, we paid EPCO and its privately held affiliates cash distributions totaling $306.1 million and $302.8 million, ~~and $296.0 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. See Note 8 for additional information regarding the DRIP.~~

We have no employees. All of our administrative and operating functions ~~and general and administrative support services~~ are provided either by employees of EPCO ~~pursuant~~(pursuant to the ~~ASA~~ASA) or by other service providers. We and our general partner are parties to the ASA. 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 March 31,				For the Three Months Ended March 31,
	2020		2019		2021		2020
Operating costs and expenses	$	251.2	$	239.1	$	254.7	$	251.2
General and administrative expenses		30.5		29.3		33.2		30.5
Total costs and expenses	$	281.7	$	268.4	$	287.9	$	281.7

We lease office space from privately held affiliates of ~~EPCO. The~~EPCO at rental rates ~~in these lease agreements~~that approximate market rates. For each of the three months ended March 31, ~~2020~~2021 and ~~2019,~~2020, we recognized $3.4 million ~~and~~ $~~3.8million, respectively,~~ of related party operating lease expense in connection with these office space leases.

Note 15. Income Taxes

The following table presents the components of our consolidated benefit from (provision for) income taxes for the periods indicated (dollars in millions):

	For the Three Months Ended March 31,
	2021			2020
Deferred tax benefit (expense) attributable to OTA Holdings, Inc. (“OTA”)	$	(6.3	)	$	187.2
Revised Texas Franchise Tax (“Texas Margin Tax”)		(3.3	)		(7.7	)
Other		(0.4	)		(0.3	)
Benefit from (provision for) income taxes	$	(10.0	)	$	179.2

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

	For the Three Months Ended March 31,
	2021			2020
Current portion of income tax benefit (provision):
Federal	$	0.8		$	(0.1	)
State		(5.1	)		(4.6	)
Foreign		(1.1	)		(0.2	)
Total current portion		(5.4	)		(4.9	)
Deferred portion of income tax benefit (provision):
Federal		(5.9	)		172.8
State		1.3			11.3
Total deferred portion		(4.6	)		184.1
Total benefit from (provision for) income taxes	$	(10.0	)	$	179.2

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

	For the Three Months Ended March 31,
	2021			2020
Pre-Tax Net Book Income (“NBI”)	$	1,372.6		$	1,195.8

Texas Margin Tax (1)		(3.3	)		(7.7	)
State income tax benefit (provision), net of federal benefit (2)		(0.6	)		11.3
Federal income tax benefit (provision) computed by applying the federal statutory rate to NBI of corporate entities		(3.1	)		107.8
Federal benefit attributable to settlement of Liquidity Option Agreement (2)		0			67.8
Valuation allowance on deferred tax assets (3)		(2.8	)		0
Other		(0.2	)		0
Benefit from (provision for) income taxes	$	(10.0	)	$	179.2

Effective income tax rate		(0.7	)%		15.0	%

(1)	Although the Texas Margin Tax is not considered a state income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers our Texas-sourced revenues and expenses.
(2)	The total benefit recognized in income tax expense in March 2020 from settlement of the Liquidity Option Agreement was $72.2 million, which is comprised of $4.4 million of state income tax benefit and $67.8 million of federal income tax benefit.
(3)	Management believes that it is more likely than not that the net deferred tax assets attributable to OTA will not be fully realizable. Accordingly, we provided for a valuation allowance against OTA’s net deferred tax assets at March 31, 2021.

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

	March 31,		December 31,
	2021		2020
Deferred tax liabilities:
Attributable to investment in OTA	$	362.9	$	356.6
Attributable to property, plant and equipment		105.2		106.4
Attributable to investments in other entities		4.0		4.1
Other		13.5		0
Total deferred tax liabilities		485.6		467.1
Less deferred tax assets:
Net operating loss carryovers (1)		2.9		0.1
Temporary differences related to Texas Margin Tax		2.7		2.3
Total deferred tax assets		5.6		2.4
Total net deferred tax liabilities before valuation allowance		480.0		464.7
Less: Valuation allowance on deferred tax assets		2.8		0
Total net deferred tax liabilities	$	482.8	$	464.7

(1)	Of the loss amount presented for March 31, 2021, $0.1 million expires in various years between 2021 and 2037. The remaining $2.8 million has an indefinite carryover period. All losses are subject to limitations on their utilization.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

OTA Deferred Tax Liability

On March 5, 2020, the Partnership settled its obligations under a put option agreement (the “Liquidity Option Agreement” or “Liquidity Option”) with OTA and Marquard & Bahls AG, and became the owner of OTA and indirectly assumed its deferred tax liability, which reflects OTA’s outside basis difference in the limited partner interests it received from the Partnership in October 2014. Upon settlement of the Liquidity Option, the Liquidity Option liability recorded by the Partnership was effectively replaced by the deferred tax liability of OTA calculated in accordance with ASC 740, Income Taxes.

At March 5, 2020, the Liquidity Option liability amount was $511.9 million. Since the book value of the Liquidity Option liability exceeded OTA’s estimated deferred tax liability of $439.7 million on that date, we recognized a non-cash benefit in earnings of $72.2 million, which is reflected in the “Benefit from (provision for) income tax” line on our Unaudited Condensed Statement of Consolidated Operations for the three months ended March 31, 2020. OTA recognized an additional net, non-cash deferred income tax benefit of $115.0 million at March 31, 2020 primarily due to a decrease in the outside basis difference of its investment in the Partnership attributable to a decline in the market price of the Partnership’s common units subsequent to March 5, 2020 through March 31, 2020. In total, our earnings for the three months ended March 31, 2020 reflect $187.2 million of net deferred income tax benefit attributable to OTA.

Note 16. Commitments and ~~Contingencies~~Contingent Liabilities

Litigation

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

Our accruals for litigation contingencies were $0.2 million and $6.1 million at March 31, ~~2020~~2021 and December 31, ~~2019,~~2020, respectively, and recorded in our Unaudited Condensed Consolidated Balance Sheets as a component of “Other current liabilities.”

~~Table of Contents~~

~~ENTERPRISE PRODUCTS PARTNERS L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~Energy Transfer Matter~~

~~In connection with a proposed pipeline project, we and~~ ~~Energy Transfer Partners, L.P. (“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 Enterprise and a third party in the 298~~^th Judicial District Court of Dallas County, Texas in connection with the cancelled project alleging, among other things, that we and ETP had formed a “partnership” and this suit went to trial in 2014. While the trial court awarded a judgment for damages in ETP’s favor, Enterprise appealed this judgment. 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 Enterprise and rendering judgment that ETP take nothing on those claims. ETP filed a Petition for Review with the Supreme Court of Texas and, on January 31, 2020, the Supreme Court of Texas issued a unanimous opinion affirming the judgment of the Dallas Court of Appeals in Enterprise’s favor. On March 6, 2020, the Supreme Court of Texas issued its Mandate to the Trial Court of Dallas County, bringing this lawsuit and the resulting appeal to a close.

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 ~~initial~~first propane dehydrogenation facility (“PDH 1”) ~~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 1 project. In December 2015, Enterprise engaged a second contractor, Optimized Process Designs LLC, to complete the construction and installation of PDH 1.

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

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 ~~$29.90~~$28.94 billion and ~~$27.88~~$30.15 billion at March 31, ~~2020~~2021 and December 31, ~~2019,~~2020, respectively. The year-to-date reduction in debt principal amount outstanding is primarily due to EPO’s repayment of Senior Notes TT and RR, partially offset by the issuance of short-term notes under its commercial paper program. See Note 7 for additional information regarding our scheduled future maturities of debt principal.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Lease Accounting Matters

There has been no significant change in our operating lease obligations since those disclosed in the 2020 Form 10-K.

The following table presents information regarding operating leases where we are the lessee at March 31, ~~2020:~~2021:

Asset Category	ROU Asset Carrying Value (1)		Lease Liability Carrying Value (2)		Weighted- Average Remaining Term	Weighted- Average Discount Rate (3)	ROU Asset Carrying Value (1)		Lease Liability Carrying Value (2)		Weighted- Average Remaining Term	Weighted- Average Discount Rate (3)
Storage and pipeline facilities	$	137.0	$	137.5	16 years	4.3%	$	124.3	$	124.9	15 years	4.3%
Transportation equipment		45.6		46.3	3 years	3.5%		31.6		33.6	3 years	3.3%
Office and warehouse space		176.3		179.8	17 years	3.2%		168.7		185.9	16 years	3.2%
Total	$	358.9	$	363.6			$	324.6	$	344.4

(1)	Right-of-use (“ROU”) asset amounts are a component of “Other assets” on our Unaudited Condensed Consolidated Balance Sheet.
(2)	At March 31, ~~2020,~~2021, lease liabilities of ~~$31.0~~$27.1 million and ~~$332.6~~$317.3 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.~~842, Leases.

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

	For the Three Months Ended March 31,				For the Three Months Ended March 31,
	2020		2019		2021		2020
Long-term operating leases:
Fixed lease expense:
Non-cash lease expense (amortization of ROU assets)	$	10.0	$	11.0	$	9.3	$	10.0
Related accretion expense on lease liability balances		3.4		2.4		3.1		3.4
Total fixed lease expense		13.4		13.4		12.4		13.4
Variable lease expense		0.2		1.8		0.4		0.2
Subtotal operating lease expense		13.6		15.2		12.8		13.6
Short-term operating leases		13.2		11.8		13.5		13.2
Total operating lease expense	$	26.8	$	27.0	$	26.3	$	26.8

~~Fixed lease expense is charged~~Cash payments attributable to ~~earnings on a straight-line basis over the contractual term, with any variable lease payments expensed as incurred. Short-term~~ operating lease ~~expense is expensed as incurred. Cash paid for operating lease liabilities recorded on our balance sheet was $10.1~~obligations were $9.1 million and ~~$9.9~~$10.1 million for the three months ended March 31, ~~2020~~2021 and ~~2019,~~2020, respectively.

~~We do not have any significant operating or direct financing leases where we are the lessor. Our operating~~Operating lease income for the three months ended March 31, ~~2020~~2021 and ~~2019~~2020 was $~~3.5~~3.0 million and $~~4.8~~3.5 million, respectively. ~~We do not have any sales-type leases.~~

~~Our operating lease commitments at March 31, 2020 did not differ materially from those reported in our 2019 Form 10-K.~~

Purchase Obligations

We have contractual future product purchase commitments for natural gas, NGLs, crude oil, petrochemicals and refined ~~products. These commitments represent~~products representing enforceable and legally binding agreements as of the reporting date. Our product purchase commitments increased from $14.8 billion at December 31, 2020 to $19.34 billion at March 31, ~~2020 declined by an estimated $10.45 billion when compared to those reported in our 2019 Form 10-K~~2021 primarily due to ~~lower NGL and~~an increase in crude oil and NGL prices inbetween the first quarter of 2020. At March 31, 2020, our estimated long-term product purchase obligations totaled $10.12 billion after reflecting the decline in commodity prices, agreements added during the first three months of 2020 and those commitments that expired during the year. At December 31, 2019, our estimated long-term product purchase obligations totaled $20.57 billion.two reporting dates.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~Settlement of Liquidity Option~~

~~See Note 8 for information regarding settlement of the Liquidity Option on March 5, 2020.~~

Note 17. Supplemental Cash Flow Information

The following table ~~presents~~provides information regarding the net effect of changes in our operating accounts and cash payments for interest and income taxes for the periods indicated:

	For the Three Months Ended March 31,						For the Three Months Ended March 31,
	2020			2019			2021			2020
Decrease (increase) in:
Accounts receivable – trade	$	1,702.4		$	(653.0	)	$	(1,214.7	)	$	1,702.4
Accounts receivable – related parties		0.5			2.0			(1.6	)		0.5
Inventories		507.7			(84.5	)		(95.7	)		507.7
Prepaid and other current assets		1,001.7			(223.4	)		158.4			1,001.7
Other assets		22.7			(13.2	)		2.3			22.7
Increase (decrease) in:
Accounts payable – trade		22.4			(35.7	)		83.5			22.4
Accounts payable – related parties		(93.0	)		(7.9	)		(64.4	)		(93.0	)
Accrued product payables		(1,743.1	)		673.0			1,591.7			(1,743.1	)
Accrued interest		(193.4	)		(178.7	)		(231.4	)		(193.4	)
Other current liabilities		(896.4	)		(8.4	)		(160.2	)		(896.4	)
Other liabilities		10.2			(30.0	)		31.1			10.2
Net effect of changes in operating accounts	$	341.7		$	(559.8	)	$	99.0		$	341.7

Cash payments for interest, net of $19.6 and $30.5 capitalized during the three months ended March 31, 2021 and 2020, respectively							$	541.1		$	496.3

Cash payments (refunds) for federal and state income taxes							$	(4.5	)	$	0.4

We incurred liabilities for construction in progress that had not been paid at March 31, ~~2020~~2021 and December 31, ~~2019~~2020 of ~~$394.0~~$283.4 million and ~~$432.0~~$236.1 million, respectively. Such amounts are not included under the caption “Capital expenditures” on the Unaudited Condensed Statements of Consolidated Cash Flows.

We recognized non-cash charges totaling $11.5 million for involuntary conversions during the first quarter of 2021 that are a component of net losses attributable to asset sales and related matters.

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~~ENTERPRISE PRODUCTS PARTNERS L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~Note 18. 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~~

~~March 31, 2020~~

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 $ 1,897.3 $ 230.2 $ (12.0 ) $ 2,115.5 $ 0.1 $ – $ 2,115.6
Accounts receivable – trade, net 1,026.1 2,268.9 (1.2 ) 3,293.8 – – 3,293.8
Accounts receivable – related parties 235.3 871.8 (924.3 ) 182.8 – (180.9 ) 1.9
Inventories 1,080.8 458.5 (0.5 ) 1,538.8 – – 1,538.8
Derivative assets 324.0 61.8 (20.0 ) 365.8 – – 365.8
Prepaid and other current assets 217.3 249.7 (64.8 ) 402.2 0.8 0.2 403.2
Total current assets 4,780.8 4,140.9 (1,022.8 ) 7,898.9 0.9 (180.7 ) 7,719.1
Property, plant and equipment, net 6,537.2 35,664.4 (42.5 ) 42,159.1 – – 42,159.1
Investments in unconsolidated affiliates 46,002.5 4,781.6 (48,175.6 ) 2,608.5 25,229.5 (25,229.5 ) 2,608.5
Intangible assets, net 631.9 2,794.9 (17.4 ) 3,409.4 – – 3,409.4
Goodwill 459.5 5,285.7 – 5,745.2 – – 5,745.2
Other assets 553.0 313.9 (243.8 ) 623.1 0.9 – 624.0
Total assets $ 58,964.9 $ 52,981.4 $ (49,502.1 ) $ 62,444.2 $ 25,231.3 $ (25,410.2 ) $ 62,265.3

LIABILITIES AND EQUITY
Current liabilities:
Current maturities of debt $ 1,750.0 $ – $ – $ 1,750.0 $ – $ – $ 1,750.0
Accounts payable – trade 157.7 769.9 (11.8 ) 915.8 – – 915.8
Accounts payable – related parties 895.0 111.9 (937.5 ) 69.4 180.9 (180.9 ) 69.4
Accrued product payables 1,379.2 1,788.7 (1.6 ) 3,166.3 – – 3,166.3
Accrued interest 238.2 3.2 (3.1 ) 238.3 – – 238.3
Derivative liabilities 208.1 81.1 (20.0 ) 269.2 – – 269.2
Other current liabilities 191.5 378.3 (63.4 ) 506.4 – – 506.4
Total current liabilities 4,819.7 3,133.1 (1,037.4 ) 6,915.4 180.9 (180.9 ) 6,915.4
Long-term debt 27,841.3 14.6 – 27,855.9 – – 27,855.9
Deferred tax liabilities 24.6 400.8 (0.6 ) 424.8 – 3.4 428.2
Other long-term liabilities 579.4 619.0 (246.8 ) 951.6 – – 951.6
Commitments and contingencies
Equity:
Partners’ and other owners’ equity 25,699.9 48,749.4 (49,253.5 ) 25,195.8 25,050.4 (25,195.8 ) 25,050.4
Noncontrolling interests – 64.5 1,036.2 1,100.7 – (36.9 ) 1,063.8
Total equity 25,699.9 48,813.9 (48,217.3 ) 26,296.5 25,050.4 (25,232.7 ) 26,114.2
Total liabilities and equity $ 58,964.9 $ 52,981.4 $ (49,502.1 ) $ 62,444.2 $ 25,231.3 $ (25,410.2 ) $ 62,265.3

~~Table of Contents~~

~~ENTERPRISE PRODUCTS PARTNERS L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~Enterprise Products Partners L.P.~~

~~Unaudited Condensed Consolidating Balance Sheet~~

~~December 31, 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 $ 109.2 $ 315.8 $ (15.1 ) $ 409.9 $ 0.1 $ – $ 410.0
Accounts receivable – trade, net 1,471.1 3,403.8 (1.3 ) 4,873.6 – – 4,873.6
Accounts receivable – related parties 233.1 799.9 (1,023.6 ) 9.4 – (6.9 ) 2.5
Inventories 1,351.3 740.4 (0.3 ) 2,091.4 – – 2,091.4
Derivative assets 115.2 12.0 – 127.2 – – 127.2
Prepaid and other current assets 221.0 183.5 (46.3 ) 358.2 – – 358.2
Total current assets 3,500.9 5,455.4 (1,086.6 ) 7,869.7 0.1 (6.9 ) 7,862.9
Property, plant and equipment, net 6,413.3 35,233.6 (43.5 ) 41,603.4 – – 41,603.4
Investments in unconsolidated affiliates 45,514.0 4,165.7 (47,079.5 ) 2,600.2 25,279.3 (25,279.3 ) 2,600.2
Intangible assets, net 636.7 2,852.3 (40.0 ) 3,449.0 – – 3,449.0
Goodwill 459.5 5,285.7 – 5,745.2 – – 5,745.2
Other assets 404.9 288.5 (221.9 ) 471.5 1.0 – 472.5
Total assets $ 56,929.3 $ 53,281.2 $ (48,471.5 ) $ 61,739.0 $ 25,280.4 $ (25,286.2 ) $ 61,733.2

LIABILITIES AND EQUITY
Current liabilities:
Current maturities of debt $ 1,981.9 $ – $ – $ 1,981.9 $ – $ – $ 1,981.9
Accounts payable – trade 301.4 717.7 (14.6 ) 1,004.5 – – 1,004.5
Accounts payable – related parties 977.5 222.3 (1,037.5 ) 162.3 6.9 (6.9 ) 162.3
Accrued product payables 1,895.4 3,021.9 (1.6 ) 4,915.7 – – 4,915.7
Accrued interest 431.6 0.9 (0.8 ) 431.7 – – 431.7
Derivative liabilities 114.2 8.2 – 122.4 – – 122.4
Other current liabilities 120.5 438.2 (47.3 ) 511.4 – (0.2 ) 511.2
Total current liabilities 5,822.5 4,409.2 (1,101.8 ) 9,129.9 6.9 (7.1 ) 9,129.7
Long-term debt 25,628.6 14.6 – 25,643.2 – – 25,643.2
Deferred tax liabilities 22.2 75.6 (0.8 ) 97.0 – 3.4 100.4
Other long-term liabilities 161.2 608.9 (247.2 ) 522.9 509.5 – 1,032.4
Commitments and contingencies
Equity:
Partners’ and other owners’ equity 25,294.8 48,107.6 (48,155.3 ) 25,247.1 24,764.0 (25,247.1 ) 24,764.0
Noncontrolling interests – 65.3 1,033.6 1,098.9 – (35.4 ) 1,063.5
Total equity 25,294.8 48,172.9 (47,121.7 ) 26,346.0 24,764.0 (25,282.5 ) 25,827.5
Total liabilities and equity $ 56,929.3 $ 53,281.2 $ (48,471.5 ) $ 61,739.0 $ 25,280.4 $ (25,286.2 ) $ 61,733.2

~~Table of Contents~~

~~ENTERPRISE PRODUCTS PARTNERS L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~Enterprise Products Partners L.P.~~

~~Unaudited Condensed Consolidating Statement of Operations~~

~~For the Three Months Ended March 31, 2020~~

EPO and Subsidiaries

Subsidiary
Issuer
(EPO)

Other
Subsidiaries
(Non-
guarantor)

EPO and
Subsidiaries
Eliminations
and
Adjustments

Consolidated
EPO and
Subsidiaries

Enterprise
Products
Partners
L.P.
(Guarantor)

Eliminations
and
Adjustments

Consolidated
Total

Revenues $ 9,627.0 $ 4,638.4 $ (6,782.9 ) $ 7,482.5 $ – $ – $ 7,482.5
Costs and expenses:
Operating costs and expenses 9,219.4 3,624.6 (6,783.7 ) 6,060.3 – – 6,060.3
General and administrative costs 5.8 48.4 0.7 54.9 0.6 – 55.5
Total costs and expenses 9,225.2 3,673.0 (6,783.0 ) 6,115.2 0.6 – 6,115.8
Equity in income of unconsolidated affiliates 678.1 153.1 (690.4 ) 140.8 1,280.7 (1,280.7 ) 140.8
Operating income 1,079.9 1,118.5 (690.3 ) 1,508.1 1,280.1 (1,280.7 ) 1,507.5
Other income (expense):
Interest expense (317.7 ) (2.6 ) 2.8 (317.5 ) – – (317.5 )
Other, net 8.2 (511.0 ) 510.7 7.9 (2.1 ) – 5.8
Total other income (expense), net (309.5 ) (513.6 ) 513.5 (309.6 ) (2.1 ) – (311.7 )
Income before income taxes 770.4 604.9 (176.8 ) 1,198.5 1,278.0 (1,280.7 ) 1,195.8
Benefit from (provision for) income taxes (4.6 ) 112.3 (0.3 ) 107.4 72.1 (0.3 ) 179.2
Net income 765.8 717.2 (177.1 ) 1,305.9 1,350.1 (1,281.0 ) 1,375.0
Net income attributable to noncontrolling interests
– (1.4 ) (24.9 ) (26.3 ) – 1.4 (24.9 )
Net income attributable to entity $ 765.8 $ 715.8 $ (202.0 ) $ 1,279.6 $ 1,350.1 $ (1,279.6 ) $ 1,350.1

~~Enterprise Products Partners L.P.~~

~~Unaudited Condensed Consolidating Statement of Operations~~

~~For the Three Months Ended March 31, 2019~~

EPO and Subsidiaries

Subsidiary
Issuer
(EPO)

Other
Subsidiaries
(Non-
guarantor)

EPO and
Subsidiaries
Eliminations
and
Adjustments

Consolidated
EPO and
Subsidiaries

Enterprise
Products
Partners
L.P.
(Guarantor)

Eliminations
and
Adjustments

Consolidated
Total

Revenues $ 9,477.8 $ 5,639.6 $ (6,573.9 ) $ 8,543.5 $ – $ – $ 8,543.5
Costs and expenses:
Operating costs and expenses 9,149.5 4,440.1 (6,569.9 ) 7,019.7 – – 7,019.7
General and administrative costs 3.8 46.8 0.7 51.3 0.9 – 52.2
Total costs and expenses 9,153.3 4,486.9 (6,569.2 ) 7,071.0 0.9 – 7,071.9
Equity in income of unconsolidated affiliates 1,276.8 172.1 (1,294.3 ) 154.6 1,319.2 (1,319.2 ) 154.6
Operating income 1,601.3 1,324.8 (1,299.0 ) 1,627.1 1,318.3 (1,319.2 ) 1,626.2
Other income (expense):
Interest expense (277.3 ) (2.7 ) 2.8 (277.2 ) – – (277.2 )
Other, net 3.1 1.2 (2.8 ) 1.5 (57.8 ) – (56.3 )
Total other expense, net (274.2 ) (1.5 ) – (275.7 ) (57.8 ) – (333.5 )
Income before income taxes 1,327.1 1,323.3 (1,299.0 ) 1,351.4 1,260.5 (1,319.2 ) 1,292.7
Provision for income taxes (4.2 ) (7.8 ) – (12.0 ) – (0.3 ) (12.3 )
Net income 1,322.9 1,315.5 (1,299.0 ) 1,339.4 1,260.5 (1,319.5 ) 1,280.4
Net income attributable to noncontrolling interests – (1.8 ) (19.4 ) (21.2 ) – 1.3 (19.9 )
Net income attributable to entity $ 1,322.9 $ 1,313.7 $ (1,318.4 ) $ 1,318.2 $ 1,260.5 $ (1,318.2 ) $ 1,260.5

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~~ENTERPRISE PRODUCTS PARTNERS L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~Enterprise Products Partners L.P.~~

~~Unaudited Condensed Consolidating Statement of Comprehensive Income~~

~~For the Three Months Ended March 31, 2020~~

~~Enterprise Products Partners L.P.~~

~~Unaudited Condensed Consolidating Statement of Comprehensive Income~~

~~For the Three Months Ended March 31, 2019~~

~~Table of Contents~~

~~ENTERPRISE PRODUCTS PARTNERS L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~Enterprise Products Partners L.P.~~

~~Unaudited Condensed Consolidating Statement of Cash Flows~~

~~For the Three Months Ended March 31, 2020~~

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 $ 765.8 $ 717.2 $ (177.1 ) $ 1,305.9 $ 1,350.1 $ (1,281.0 ) $ 1,375.0
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion 85.6 424.2 (0.8 ) 509.0 – – 509.0
Equity in income of unconsolidated affiliates (678.1 ) (153.1 ) 690.4 (140.8 ) (1,280.7 ) 1,280.7 (140.8 )
Distributions received from unconsolidated affiliates attributable to earnings 397.9 68.0 (339.0 ) 126.9 981.1 (981.1 ) 126.9
Net effect of changes in operating accounts and other operating activities 1,161.3 (612.7 ) (509.7 ) 38.9 103.2 – 142.1
Net cash flows provided by operating activities 1,732.5 443.6 (336.2 ) 1,839.9 1,153.7 (981.4 ) 2,012.2
Investing activities:
Capital expenditures (266.8 ) (813.0 ) 0.3 (1,079.5 ) – – (1,079.5 )
Proceeds from asset sales 0.1 0.5 – 0.6 – – 0.6
Other investing activities (640.1 ) 4.6 642.7 7.2 – – 7.2
Cash used in investing activities (906.8 ) (807.9 ) 643.0 (1,071.7 ) – – (1,071.7 )
Financing activities:
Borrowings under debt agreements 5,411.8 – – 5,411.8 – – 5,411.8
Repayments of debt (3,406.6 ) – – (3,406.6 ) – – (3,406.6 )
Cash distributions paid to owners (981.1 ) (374.6 ) 374.5 (981.2 ) (974.2 ) 981.2 (974.2 )
Cash payments made in connection with DERs – – – – (5.8 ) – (5.8 )
Cash distributions paid to noncontrolling interests – (2.2 ) (27.9 ) (30.1 ) – 0.2 (29.9 )
Cash contributions from noncontrolling interests – – 5.2 5.2 – – 5.2
Common units acquired in connection with 2019 Buyback Program – – – – (140.1 ) – (140.1 )
Cash contributions from owners – 655.5 (655.5 ) – – – –
Other financing activities (61.7 ) – – (61.7 ) (33.6 ) – (95.3 )
Cash provided by (used in) financing activities 962.4 278.7 (303.7 ) 937.4 (1,153.7 ) 981.4 765.1
Net change in cash and cash equivalents,
   including restricted cash
1,788.1 (85.6 ) 3.1 1,705.6 – – 1,705.6
Cash and cash equivalents, including
   restricted cash, at beginning of period
109.2 315.8 (15.1 ) 409.9 0.1 – 410.0
Cash and cash equivalents, including
   restricted cash, at end of period
$ 1,897.3 $ 230.2 $ (12.0 ) $ 2,115.5 $ 0.1 $ – $ 2,115.6

~~Table of Contents~~

~~ENTERPRISE PRODUCTS PARTNERS L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~Enterprise Products Partners L.P.~~

~~Unaudited Condensed Consolidating Statement of Cash Flows~~

~~For the Three Months Ended March 31, 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 $ 1,322.9 $ 1,315.5 $ (1,299.0 ) $ 1,339.4 $ 1,260.5 $ (1,319.5 ) $ 1,280.4
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion 74.9 399.8 (0.2 ) 474.5 – – 474.5
Equity in income of unconsolidated affiliates (1,276.8 ) (172.1 ) 1,294.3 (154.6 ) (1,319.2 ) 1,319.2 (154.6 )
Distributions received from unconsolidated affiliates attributable to earnings 338.4 83.0 (282.4 ) 139.0 981.7 (981.7 ) 139.0
Net effect of changes in operating accounts and other operating activities 100.9 (861.7 ) 27.7 (733.1 ) 154.0 0.2 (578.9 )
Net cash flows provided by operating activities 560.3 764.5 (259.6 ) 1,065.2 1,077.0 (981.8 ) 1,160.4
Investing activities:
Capital expenditures (223.8 ) (921.0 ) (4.1 ) (1,148.9 ) – – (1,148.9 )
Proceeds from asset sales 0.2 1.5 – 1.7 – – 1.7
Other investing activities (492.8 ) (10.1 ) 475.6 (27.3 ) (84.1 ) 84.1 (27.3 )
Cash used in investing activities (716.4 ) (929.6 ) 471.5 (1,174.5 ) (84.1 ) 84.1 (1,174.5 )
Financing activities:
Borrowings under debt agreements 15,692.4 – – 15,692.4 – – 15,692.4
Repayments of debt (14,999.1 ) (0.1 ) – (14,999.2 ) – – (14,999.2 )
Cash distributions paid to owners (981.7 ) (300.5 ) 300.5 (981.7 ) (950.4 ) 981.7 (950.4 )
Cash payments made in connection with DERs – – – – (4.5 ) – (4.5 )
Cash distributions paid to noncontrolling interests – (2.4 ) (15.7 ) (18.1 ) – 0.1 (18.0 )
Cash contributions from noncontrolling interests – – 34.8 34.8 – – 34.8
Net cash proceeds from issuance of common units – – – – 42.7 – 42.7
Common units acquired in connection with 2019 Buyback Program – – – – (51.6 ) – (51.6 )
Cash contributions from owners 84.1 512.9 (512.9 ) 84.1 – (84.1 ) –
Other financing activities – (5.6 ) – (5.6 ) (29.1 ) – (34.7 )
Cash provided by (used in) financing activities (204.3 ) 204.3 (193.3 ) (193.3 ) (992.9 ) 897.7 (288.5 )
Net change in cash and cash equivalents,
   including restricted cash
(360.4 ) 39.2 18.6 (302.6 ) – – (302.6 )
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
$ 33.0 $ 89.5 $ (15.0 ) $ 107.5 $ – $ – $ 107.5

~~Note 19. Subsequent Events~~

~~Enterprise Enters Into April 2020 364-Day Revolving Credit Agreement~~

~~In April 2020, EPO entered into an additional 364-day revolving credit agreement (the “April 2020~~ ~~364-Day Credit Agreement”). The new agreement provides EPO with an incremental $1.0~~ ~~billion of borrowing capacity, thereby increasing its overall borrowing capacity under its credit agreements to $6.0~~ ~~billion.~~ Under the terms of the April 2020 364-Day Credit Agreement, EPO may borrow up to $1.0 billion at a variable interest rate for a term of 364 days, subject to the terms and conditions set forth therein. EPO may use proceeds from borrowings under the April 2020 364-Day Credit Agreement for working capital, capital expenditures, acquisitions and other company purposes.

~~Table of Contents~~

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

RESULTS OF OPERATIONS.

For the Three Months Ended March 31, ~~2020~~2021 and ~~2019~~2020

The following information should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and accompanying Notes included in this quarterly report on Form 10-Q and the Audited Consolidated Financial Statements and related Notes, together with our discussion and analysis of financial position and results of operations, included in our annual report on Form 10-K for the year ended December 31, ~~2019~~2020 (the ~~“2019~~“2020 Form 10-K”), as filed on ~~February 28, 2020~~March 1, 2021 with the U.S. Securities and Exchange Commission (“SEC”). Our financial statements have been prepared in accordance with generally accepted accounting principles (“GAAP”) in the United States (“U.S.”).

~~Key References Used in this Management’s Discussion and Analysis~~

Unless the context requires otherwise, references to “we,” “us,” “our” or “Enterprise” are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries. ~~References to “EPD” or the “Partnership” mean Enterprise Products Partners L.P. on a standalone basis.~~ References to “EPO” mean Enterprise Products Operating LLC, which is an indirect wholly owned subsidiary of 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 Co-Chief Executive Officer 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 ~~32.1%~~ ~~of EPD’s limited partner common units at March 31, 2020.~~

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

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

~~As used in this quarterly report, the phrase “quarter-to-quarter” means the first quarter of 2020 compared to the first quarter of 2019.~~

~~Table of Contents~~

~~CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION~~Cautionary Statement Regarding Forward-Looking Information

This quarterly report on Form 10-Q for the year ended March 31, 2021 (our “quarterly report”) contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us. When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “seek,” “goal,” “estimate,” “forecast,” “intend,” “could,” “should,” “would,” “will,” “believe,” “may,” “scheduled,” “potential” and similar expressions and statements regarding our plans and objectives for future operations are intended to identify forward-looking statements. Although we and our general partner believe that our expectations reflected in such forward-looking statements (including ~~the~~any forward-looking statements/expectations of third parties referenced in this quarterly report) are reasonable, neither we nor our general partner can give any assurances that such expectations will prove to be correct.

Forward-looking statements are subject to a variety of risks (including those attributable to the Coronavirus disease 2019 (“COVID-19”) pandemic), uncertainties and assumptions as described in more detail under Part I, Item 1A of our ~~2019~~2020 Form 10-K and within Part II, Item 1A of this quarterly report. These risks include recent impacts of COVID-19 and decreases in certain commodity prices resulting from demand weakness and oversupply, which are discussed in Part II, Item 1A “Risk Factors” of this quarterly report, and this Part I, Item 2.10-K. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. You should not put undue reliance on any forward-looking statements. The forward-looking statements in this quarterly report speak only as of the date hereof. Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason.

~~Overview~~Key References Used in this Management’s Discussion and Analysis

Unless the context requires otherwise, references to “we,” “us” or “our” within this quarterly report are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries.

References to the “Partnership” mean Enterprise Products Partners L.P. on a standalone basis.

References to “EPO” mean Enterprise Products Operating LLC, which is an indirect wholly owned subsidiary of the Partnership, and its consolidated subsidiaries, through which the Partnership conducts its business. We are managed by our general partner, Enterprise Products Holdings LLC (“Enterprise GP”), which is a wholly owned subsidiary of Dan Duncan LLC, a privately held Texas limited liability company.

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

References to “EPCO” mean Enterprise Products Company, a privately held Texas corporation, and its privately held affiliates. The outstanding voting capital stock of EPCO is owned by a voting trust, the current trustees (“EPCO Trustees”) of which are: (i) Ms. Duncan Williams, who serves as Chairman of EPCO; (ii) Mr. Bachmann, who serves as the President and Chief Executive Officer of EPCO; and (iii) Mr. Fowler, who serves as an Executive Vice President and the Chief Financial Officer of EPCO. Ms. Duncan Williams and Messrs. Bachmann and Fowler also currently serve as directors of EPCO.

Table of Contents

We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates under the collective common control of the DD LLC Trustees and the EPCO Trustees. EPCO, together with its privately held affiliates, owned approximately 32.2% of the Partnership’s common units outstanding at March 31, 2021. In March 2021, a privately held affiliate of EPCO sold its entire ownership interest in the Partnership’s Series A Cumulative Convertible Preferred Units (“preferred units”) to third parties.

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

/d	=	per day	MMBPD	=	million barrels per day
BBtus	=	billion British thermal units	MMBtus	=	million British thermal units
Bcf	=	billion cubic feet	MMcf	=	million cubic feet
BPD	=	barrels per day	MWac	=	megawatts, alternating current
MBPD	=	thousand barrels per day	MWdc	=	megawatts, direct current
MMBbls	=	million barrels	TBtus	=	trillion British thermal units

As used in this quarterly report, the phrase “quarter-to-quarter” means the first quarter of 2021 compared to the first quarter of 2020.

Business Summary

We are a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.” Our preferred units are not publicly traded. We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO and are a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, petrochemicals and refined products. We are owned by our limited partners (preferred and common unitholders) from an economic perspective. Enterprise GP, which owns a non-economic general partner interest in us, manages our Partnership. We conduct substantially all of our business operations through EPO and its consolidated subsidiaries.

Our fully integrated, midstream energy asset network (or “value chain”) links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the United States (“U.S.”), Canada and the Gulf of Mexico with domestic consumers and international markets. Our midstream energy operations ~~currently~~ include:

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

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

crude oil gathering, transportation, storage, and ~~export~~marine terminals;

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

petrochemical and refined products transportation, storage, and marine terminals (including those used to export ethylene and ~~import terminals,~~polymer grade propylene (“PGP”); and ~~related services; and~~

a marine transportation business that operates ~~primarily~~ on ~~the~~key U.S. inland and ~~Intracoastal Waterway~~intracoastal waterway systems. Our assets currently include approximately 50,000 miles of pipelines; 260 MMBbls of storage capacity for NGLs, crude oil, petrochemicals and refined products; and 14 Bcf of natural gas storage capacity.

~~We conduct substantially all~~The safe operation of our ~~business through EPO~~assets is a top priority. We are committed to protecting the environment and ~~are owned 100% by EPD’s limited partners from an economic perspective. Enterprise GP manages our partnership~~the health 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~~safety of the ~~DD LLC Trustees~~public and those working on our behalf by conducting our business activities in a safe and environmentally responsible manner. For additional information, see “Environmental, Safety and Conservation” within the ~~EPCO Trustees.~~ Regulatory Matters section of Part I, Items 1 and 2 of the 2020 Form 10-K.

Our operations are reported under four business segments: (i) NGL Pipelines & Services, (ii) Crude Oil Pipelines & Services, (iii) Natural Gas Pipelines & Services, and (iv) Petrochemical & Refined Products Services. Our business segments are generally organized and managed according to the types of services rendered (or technologies employed) and products produced and/or sold.

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Each of our business segments benefits from the supporting role of our related marketing activities. The main purpose of our marketing activities is to support the utilization and expansion of assets across our midstream energy asset network by increasing the volumes handled by such assets, which results in additional fee-based earnings for each business segment. In performing these support roles, our marketing activities also seek to participate in supply and demand opportunities as a supplemental source of gross operating margin, a non-generally accepted accounting principle (“non-GAAP”)Our financial ~~measure, for the partnership. The financial~~position, results of ~~our marketing efforts fluctuate due~~operations and cash flows are subject to ~~changes in volumes handled and overall market conditions, which are influenced by current and forward market prices for~~certain risks. For information regarding such risks, see “Risk Factors” included under Part I, Item 1A of the ~~products bought and sold.~~2020 Form 10-K.

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

~~Update on 2020~~Current Outlook ~~– Coronavirus and Oil Price Shock~~

As noted previously under “Cautionary Statement Regarding Forward-Looking Information” within this Part I, Item 2, this quarterly report on Form 10-Q, including this ~~Update~~update to our outlook on ~~2020 Outlook,~~business conditions, contains forward-looking statements that are based on our beliefs and those of ~~our general partner, as well as~~Enterprise GP. In addition, it reflects assumptions made by us and information currently available to ~~us, which includes forecast information published by third parties. See “Cautionary Statement Regarding Forward-Looking Information” within this Part I, Item 2~~us.

With regards to the outlook for hydrocarbon supply and ~~“Risk Factors”~~demand fundamentals described in ~~Part II, Item 1A, for additional information. The following update to~~ our 2020 ~~Outlook replaces the general outlook provided in our 2019~~ Form 10-K, ~~under Part II, Item 7.~~

~~The global energy industry is being severely impacted by two historic events~~we believe that ~~began during~~ the ~~first quarter of 2020:~~

~~the emergence of coronavirus disease 2019 (“COVID-19”) as a global pandemic and its devastating effect on the global economy and energy demand; and~~

~~the initiation of a crude oil price war in March 2020 between members of~~underlying trends remain generally intact. Ongoing production cuts within the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (collectively, the “OPEC+” group), along with market-driven cuts in U.S., Brazilian and Canadian supplies, continue to provide much-needed support for international energy markets in coping with weakness in hydrocarbon demand attributable to the COVID-19 pandemic. As vaccination programs are implemented on a wider scale, many countries have eased their COVID-19 containment measures and governments have instituted fiscal measures in an effort to support economic activity. As a result, hydrocarbon demand has started to recover; however, a continuation of this trend remains dependent on successful containment of the disease, the efficacy and distribution of approved vaccines on COVID-19 and its ~~effect~~emerging variants, and proven therapeutics.

We continue to believe that our integrated, diversified and fee-based business model will enable us to successfully traverse this difficult period. The Partnership and its consolidated operations remain in a strong position, with our financial strength and operational flexibility demonstrated by $5.11 billion of consolidated liquidity at March 31, 2021, investment grade credit ratings on ~~global crude oil supplies. OPEC+ subsequently agreed in April 2020~~EPO’s long-term senior unsecured debt, a disciplined capital spending approach, the optimization of our assets to ~~reduce global supplies by 9.7 MMBPD beginning with the May 2020 production month.~~

provide incremental services to customers and to respond to market opportunities, and a portfolio of diverse, high quality customers.

The ~~consequences~~value of ~~international COVID-19 containment measures (and~~our diversified and integrated midstream system was exhibited again in the ~~resulting dramatic declines~~first quarter of 2021. Our propylene, NGL, refined products and natural gas businesses benefited from greater demand associated with the early stages of an economic recovery, winter demand and higher commodity prices. This was partially offset by plant and pipeline disruptions and lower volumes attributable to the impacts of major winter storms in ~~end-user demand for hydrocarbons~~mid-February 2021 and major maintenance activities at our PDH 1 and octane enhancement facilities.

Impact of February 2021 Winter Storms

Two major winter storms, Uri and Viola, impacted Texas and the southern U.S. in ~~general), paired with threatened and actual overproduction of crude oil~~mid-February 2021 (the “February 2021 winter storms”). The storms had a major impact on the electric power grid in ~~April 2020 by Saudi Arabia and Russia (in their attempt to gain market share from each other and U.S. shale producers),~~Texas, which resulted in ~~major~~widespread power outages. Voluntarily and in accordance with our agreements with the Electric Reliability Council of Texas, Inc. (“ERCOT”), we temporarily shut down our non-essential plants and other operations in Texas to support residential power consumption. Those Texas assets that remained operational (e.g., our natural gas processing plants, storage facilities and Texas Intrastate System) were impacted by rolling blackouts. The economic impacts of these disruptions, higher power and natural gas costs, as well as losses on natural gas hedges, were mitigated by sales of natural gas to ~~global energy markets. As a midstream energy company, these macroeconomic events have a direct impact on~~electricity generators, natural gas utilities and industrial customers to assist them in meeting their requirements. During and following the storms, many of our ~~financial position, results of operations~~customers also experienced downtime due to freeze-related damage and ~~cash flows. As noted in~~repairs that impacted our ~~2019 Form 10-K, changes in the supply of and demand for hydrocarbon products impacts both the volume of products that we sell and the level of services that we provide to customers.~~volumes.

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The ongoing COVID-19 public health emergency has resulted in record, near-term decreases in hydrocarbon demand due to travel restrictions, quarantines, temporary business closures and other measures. In its April 2020 Oil Market Report dated April 15, 2020 (the “April 2020 Report”), the International Energy Agency (“IEA”) estimated that global crude oil demand for April 2020 declined by approximately 29 MMBPD when compared to April 2019. For May 2020, the IEA forecasts that demand may be down by approximately 26 MMBPD when compared to May 2019. Within a few months of its initial discovery in China, the highly infectious COVID-19 virus spread across the globe and achieved pandemic status at the end of January 2020. U.S. federal, state and local governments, along with governments of most other developed economies, have imposed significant restrictions, including stay-at-home directives, on their populations in an attempt to stem the spread of the disease. As of April 15, 2020, a total of 187 countries and territories had enacted some form of containment measures. Although these restrictions have had significant economic repercussions, including dramatic declines in end-user demand for hydrocarbons in general, the spread of the disease has been slowed in some regions. Many countries, including the U.S., have either enacted or are considering enacting stimulus measures to support recovery of their economies. For example, on March 27, 2020, the Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”) was enacted by the U.S., which, at $2.2 trillion, is the largest-ever economic stimulus package in U.S. history. In addition, many central banks across the globe have embarked on significant monetary stimulus programs.

On February 13, 2020, the IEA forecasted that global demand for crude oil would fall to its lowest rate since 2011 due to the effects of COVID-19. As a result, and in connection with a significant drop in hydrocarbon demand in China due to spread of the disease in that country, the OPEC+ group met in early March 2020 to discuss cutting its crude oil production by an additional 1.5 MMBPD through the second quarter of 2020. OPEC called on Russia to join them in the proposed cuts, which was promptly rejected by Russia. On March 10, 2020, Saudi Arabia responded by initiating a price war with Russia by increasing its April production from 9.7 MMBPD to approximately 12.3 MMBPD, while Russia responded by declaring that it would increase its crude oil production by 300 MBPD to approximately 11.5 MMBPD. The actual and threatened actions by Saudi Arabia and Russia resulted in an immediate, severe decline in crude oil prices. For example, West Texas Intermediate (“WTI”) crude oil prices at Cushing, Oklahoma (as reported by the NYMEX) decreased from $41.28 per barrel on March 6, 2020 to $31.13 on March 9, 2020. Subsequently, WTI prices fluctuated from a high of $34.36 per barrel to a low of $20.09 per barrel through March 31, 2020. In contrast, WTI prices closed at $61.06 per barrel on December 31, 2019.

In April 2020, at the urging of President Trump, OPEC and Russia met again to discuss ways to stabilize the global oil markets. After intense negotiations, OPEC and Russia agreed to reduce their combined oil production by 9.7 MMBPD in May and June 2020, 7.7 MMBPD from July through December 2020 and 5.8 MMBPD from January 2021 to April 2022. Moreover, the U.S., Brazil and Canada contributed an aggregate 3.7 MMBPD of additional reductions on the basis that adverse market dynamics (e.g., COVID-19 demand destruction) will naturally result in lower production from their respective energy industries. The new OPEC+ agreement will be reevaluated in December 2021. The length of the output restrictions by U.S., Brazil and Canada will depend on market forces, which are based on supply and demand fundamentals.

Even with the recent production cuts announced by the OPEC+ group and others, the IEA in its April 2020 Report expects that global crude oil inventories will continue to rise over the near term. Notwithstanding the announced production cuts, crude oil prices further collapsed in April 2020, with the WTI price for May delivery closing at negative $37.63 per barrel on April 20, 2020. Per its April 2020 Report, the IEA expects that a gradual recovery in crude oil demand will gain traction in June 2020, although demand is estimated to be approximately 15 MMBPD lower than in June 2019. Overall, the IEA expects global crude oil demand to average 90.6 MMBPD in 2020, which represents a decline of approximately 9 MMBPD from 2019. As demand increases in the second half of 2020, the IEA expects that global crude oil and refined product inventories will begin to decrease, which should support moderate increases in energy commodity prices. WTI closed at $24.56 per barrel on May 5, 2020.

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These macroeconomic events are contributing to a number of significant developments within the domestic energy industry that impact our industry outlook for 2020. According to published reports, these developments include:

Most oil producers in North America will have to reduce the drilling and completion of new wells. According to a report published by the Federal Reserve Bank of Dallas, average breakeven prices in the Permian Basin range from $48 per barrel to $54 per barrel, with breakeven costs in the Eagle Ford Shale averaging $51 per barrel. As a result of lower crude oil prices, bankruptcies by shale oil producers are expected to increase according to a Rystad Energy report published on April 3, 2020. In April 2020, Whiting Petroleum Corporation was the first notable producer to declare Chapter 11 bankruptcy due to the crude oil price crash.

Notwithstanding reductions in the drilling and completion of new wells, U.S. producers continued to pump at near-record highs of approximately 13 MMBPD in late March 2020 (down to 12.3 MMBPD by April 10, 2020).

With the reduction in end-user demand caused by COVID-19, certain independent producers filed a complaint seeking that the Railroad Commission of Texas (“Texas RRC”), which has certain regulatory power over crude oil production in Texas, consider curtailing production for the first time in 50 years. Other states are also considering production curtailments. The Texas RRC held an open meeting on April 14, 2020 to discuss prorationing with various energy companies and other interested parties; however, on May 5, 2020, the commissioners passed a motion to dismiss the prorationing complaint. We continue to monitor state regulatory developments.

Although we expect a near-term reduction in volumes as the effects of these developments ripple through the major production basins, the long term impacts are not known at this time. We may experience throughput declines in the second half of 2020 on our gathering systems, long-haul liquids and natural gas pipelines and at our terminal, fractionation and export facilities. To the extent that we have firm transportation agreements (e.g., ship-or-pay arrangements) and the shipper/customer has sufficient liquidity to satisfy its contractual commitments, we expect the near-term impacts to be manageable. The expected reduction in upstream production and a lack of downstream global markets is negatively impacting the export of crude oil and basic petrochemicals from our marine terminals; however, LPG export demand has thus far remained resilient. Notably, markets that experience extreme demand shocks like the current environment generally need significant amounts of immediate storage capacity, which we can help provide.

Capital spending throughout the domestic energy industry is being significantly reduced to protect cash flow. For example, integrated oil majors Chevron Corporation and ExxonMobil recently announced reductions in their 2020 capital expenditure budgets of 20% (as of March 24, 2020) and 30% (as of April 7, 2020), respectively. Many smaller and independent energy producers are not expected to have the same level of access to the capital markets as they did during the previous downturn in 2015/2016.

Based on information currently available, we now expect our total capital investments for 2020 to approximate $2.8 billion to $3.3 billion (previously $3.4 billion to $4.4 billion), which reflects growth capital investments of $2.5 billion to $3.0 billion (previously $3.0 billion to $4.0 billion) and approximately $300 million for sustaining capital expenditures (previously $400 million). We currently expect our growth capital investments on sanctioned projects for 2021 and 2022 to approximate $2.5 billion and $1.5 billion, respectively. These amounts do not include capital investments associated with our proposed deepwater offshore crude oil terminal (the Sea Port Oil Terminal or “SPOT”), which remains subject to governmental ~~approvals. We do not expect to receive governmental approvals for SPOT in 2020.~~

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Downstream demand for hydrocarbon products such as gasoline and jet fuel is expected to remain depressed until the COVID-19 containment measures are lifted and the economy sufficiently improves. Refiners have significantly reduced their utilization rates in response to the lack of domestic and international demand. According to the IEA’s April 2020 Report, global refining throughput for 2020 is forecast to fall 7.6 MMBPD to 74.3 MMBPD in 2020 on sharply reduced demand for transportation fuels. Global refinery intake is expected to decrease 16 MMBPD in the second quarter of 2020 when compared to the second quarter of 2019. Although refinery runs are falling, the IEA expects that refined product inventories will increase by 6 MMBPD due to drastically lower demand. The IEA expects that refining activity will slowly recover in the second half of 2020.

As a result of the decline in downstream refinery activity and demand for transportation fuels, we expect near-term declines in our petrochemical and refined products businesses, particularly in volumes attributable to our Mont Belvieu octane enhancement facilities and related plants. We also expect near-term reductions in propylene fractionation volumes in the second quarter of 2020. Volumes at our facilities should improve as COVID-19 containment measures are lifted and economic conditions improve.

Although the outlook for 2020 includes major challenges for the domestic energy industry, we believe that our partnership was in a strong financial position entering into these unprecedented events and can endure through this economic cycle due to the following:

•

~~We entered 2020 in the strongest financial position in our 22-year history, with a solid balance sheet, strong liquidity and good coverage of the cash distribution. Our liquidity is supported by~~ ~~investment grade credit ratings on EPO’s long-term senior unsecured debt of BBB+, Baa1 and BBB+ from Standard & Poors, Moody’s and Fitch, respectively;~~

•

~~At April 30, 2020, our liquidity was $8.1~~ ~~billion comprised of an aggregate $6.0 billion from undrawn revolving credit facilities and $2.1~~ ~~billion of cash on hand. This includes a second 364-Day Revolving Credit Agreement that we entered into on April 3, 2020 that increased our liquidity by $1.0 billion;~~

We do not currently anticipate any need to access the debt capital markets until 2021. We completed a $3.0 billion senior notes offering in January 2020 that provided funds to repay all of our $1.5 billion of senior note maturities in 2020, and believe that we will have sufficient liquidity and/or access to debt capital markets to fund $1.33 billion of senior notes maturing in 2021;

In addition to the adjustments we made to our capital spending program for 2020 noted previously, we continue to discuss project commitments with customers and joint venture opportunities with strategic partners to optimize our use of available liquidity. These efforts could further reduce our planned growth capital investments for 2020, 2021 and 2022;

~~Our business is predominately fee-based (approximately 86% in 2019), with a substantial portion backed by take-or-pay arrangements;~~

Across all of our assets, we have contracted with a large number of quality customers in order to achieve customer diversification. In 2019, our top 200 largest customers represented 96% of consolidated revenues. Based on their respective year-end 2019 debt ratings, 81% of our top 200 customers were either investment grade rated or backed by letters of credit. Additionally, only 6% of our top 200 customer revenues were attributable to sub-investment grade or non-rated upstream producers. Given the current market environment, the rating agencies have taken numerous rating actions, including downgrades, across the energy industry. After adjusting for all ratings actions through April 23, 2020, we estimate that 78% of our top 200 customers remain investment grade rated or are backed by letters of credit;

We continue to leverage our assets to provide incremental services to customers during this difficult period and to respond to market opportunities caused by the destruction in near-term hydrocarbon demand and the related price shocks on crude oil, NGLs, refined products and petrochemicals. Currently, crude oil prices, along with those of certain refined products, are in contango as near-term deliveries trade at steep discounts to contracts further out in time;

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~~Our LPG export terminals continue to operate at high levels of utilization, thus far demonstrating resilient international demand for these energy commodities; and~~

In light of current events, we are closely monitoring the recoverability of our long-lived assets, equity method investments, intangible assets and goodwill carrying values for potential impairment. We did not recognize any significant non-cash asset impairment charges during the first quarter of 2020. However, if the impacts from the outbreak of COVID-19 and adverse developments in the global energy markets persist for significantly longer periods than currently expected, these events could result in asset impairment charges in the future.

~~Other~~Significant Recent Developments

Enterprise ~~Enters Into April 2020 364-Day Revolving Credit Agreement~~to Increase Its Use of Power from Renewable Resources

In ~~April 2020, EPO~~March 2021, we announced the execution of a power purchase agreement with EDF Renewables North America that will increase our use of electricity from solar power by 100 MWac/132 MWdc. We are committed to being a responsible steward of the environment, including using energy sustainably across our footprint. We estimate that by 2025, approximately 25% of our power will be from renewable resources.

Enterprise and Magellan to Develop Joint Houston Crude Oil Futures Contract

In January 2021, we and Magellan Midstream Partners, L.P (“Magellan”) announced that our affiliates had entered into an ~~additional 364-day revolving credit~~ agreement ~~(the “April 2020~~ ~~364-Day Credit Agreement”). The new agreement provides EPO with an incremental $1.0 billion~~to jointly develop a futures contract for the physical delivery of ~~borrowing capacity, thereby increasing its overall borrowing capacity under its credit agreements~~crude oil in the Houston, Texas area in response to ~~$6.0 billion. The April 2020~~ ~~364-Day Credit Agreement enhances our financial flexibility during the current economic downturn caused by the COVID-19 pandemic and oil price shock.~~

~~Under the terms of the April 2020 364-Day Credit Agreement, EPO may borrow up to $1.0 billion at a variable~~market interest ~~rate~~ for a ~~term of 364 days, subject to the terms~~Houston-based index with greater scale, flow assurance and ~~conditions set forth therein. EPO may use proceeds from borrowings under the April 2020 364-Day Credit Agreement for working capital, capital expenditures, acquisitions and other company purposes.~~

~~Enterprise Provides Distribution and Buyback Guidance for 2020~~

On March 18, 2020, the Board declared a quarterly cash distribution to be paid to our limited partners with respect to the first quarter of 2020 of $0.4450 per common unit, or $1.78 per unit on an annualized basis.price transparency. The quarterly distribution associated with the first quarter of 2020 is payable on May 12, 2020, to unitholders of record as of the close of business on April 30, 2020. This distribution represents a 1.7% increase over the distribution declared with respect to the first quarter of 2019.

In January 2020, management announced its intention to use approximately 2.0% of net cash flow provided by operating activities, or cash flow from operations (“CFFO”), in 2020 to repurchase EPD common units under the Buyback Program approved in January 2019 (the “2019 Buyback Program”). For information regarding the 2019 Buyback Program, including repurchases of common units in the first quarter of 2020, see “~~Liquidity and Capital Resources – Common Unit Buyback Program” within this Part I, Item 2.~~

~~Settlement of Liquidity Option~~

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At March 5, 2020, our accrual for the Liquidity Option liability was $511.9 million. The Liquidity Option liability, at any measurement date, represents the present value of estimated federal and state income taxes that we believe a market participant would incur due to ownership of OTA, including its deferred income tax liabilities. OTA’s deferred tax liability at March 5, 2020 was $439.7 million. The market value of the new EPD common units issued to Skyline was $1.30 billion based on a closing price of $23.67 per unit on March 5, 2020.

The 54,807,352 new EPD common units issued to Skyline upon settlement of the Liquidity Option constitute “restricted securities” in the meaning of Rule 144 under the Securities Act of 1933, as amended (the “Securities Act”) and may not be resold except pursuant to an effective registration statement or an available exemption under the Securities Act. In connection with the settlement of the Liquidity Option, Enterprise entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with Skyline. Pursuant to the Registration Rights Agreement, Skyline has the right to request that we prepare and file a registration statement to permit and otherwise facilitate the public resale of all or a portion of such EPD common units that Skyline and its affiliates then own. ~~Our obligation to Skyline to effect such transactions is limited to five registration statements and underwritten offerings.~~

As a result of the Liquidity Option settlement, the partners’ capital balance for common units (as presented on our Unaudited Condensed Consolidated Balance Sheet) increased by the $1.30 billion market value of the new EPD common units issued to Skyline. Since OTA does not meet the definition of a business as described in ASC 805, ~~Business Combinations, the acquisition of OTA was accounted for as the purchase of treasury units and the assumption of related deferred income tax liability.~~ ~~In consolidation, we present the~~ ~~54,807,352~~ ~~EPD common units owned by OTA as treasury units, with their historical cost based on the $1.30 billion market value of the~~ ~~54,807,352~~ ~~new EPD common units issued to Skyline.~~

~~For information regarding the impact of the settlement on our earnings for the first quarter of 2020, see “Income Statement Highlights – Income Taxes” within this Item 2.~~

~~Issuance of $3.0 Billion of Senior Notes in January 2020~~

In January 2020, EPO issued $3.0 billion aggregate principal amount of senior notes comprised of (i) $1.0 billion principal amount of senior notes due January 2030 (“Senior Notes AAA”), (ii) $1.0 billion principal amount of senior notes due January 2051 (“Senior Notes BBB”) and (iii) $1.0 billion principal amount of senior notes due January 2060 (“Senior Notes CCC”). Net proceeds from this offering were used by EPO for the repayment of $500 million principal amount of its Senior Notes Q that matured in January 2020, temporary repayment of amounts outstanding under its commercial paper program and for general company purposes. In addition, net proceeds from this offeringquality specifications will be ~~used by EPO for~~consistent with WTI crude oil originating from the ~~repayment of $1.0 billion principal amount of its Senior Notes Y upon their maturity~~Permian Basin with delivery capabilities at either our ECHO terminal in ~~September 2020.~~

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Houston or Magellan’s East Houston terminal.

Selected Energy Commodity Price Data

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

							Polymer	Refinery	Indicative Gas							Polymer	Refinery	Indicative Gas
	Natural			Normal		Natural	Grade	Grade	Processing	Natural			Normal		Natural	Grade	Grade	Processing
	Gas,	Ethane,	Propane,	Butane,	Isobutane,	Gasoline,	Propylene,	Propylene,	Gross Spread	Gas,	Ethane,	Propane,	Butane,	Isobutane,	Gasoline,	Propylene,	Propylene,	Gross Spread
	$/MMBtu	$/gallon	$/gallon	$/gallon		$/gallon	$/pound	$/pound	$/gallon	$/MMBtu	$/gallon	$/gallon	$/gallon		$/gallon	$/pound	$/pound	$/gallon
	(1)	(2)	(2)	(2)		(2)	(3)	(3)	(4)	(1)	(2)	(2)	(2)		(2)	(3)	(3)	(4)
2019 by quarter:
2020 by quarter:
1st Quarter	$3.15	$0.30	$0.67	$0.82	$0.85	$1.16	$0.38	$0.24	$0.31	$1.95	$0.14	$0.37	$0.57	$0.63	$0.93	$0.31	$0.18	$0.19
2nd Quarter	$2.64	$0.21	$0.55	$0.63	$0.65	$1.21	$0.37	$0.24	$0.25	$1.71	$0.19	$0.41	$0.43	$0.44	$0.41	$0.26	$0.11	$0.17
3rd Quarter	$2.23	$0.17	$0.44	$0.51	$0.66	$1.06	$0.38	$0.23	$0.21	$1.98	$0.22	$0.50	$0.58	$0.60	$0.80	$0.35	$0.17	$0.25
4th Quarter	$2.50	$0.19	$0.50	$0.68	$0.82	$1.20	$0.35	$0.21	$0.25	$2.67	$0.21	$0.57	$0.76	$0.68	$0.92	$0.41	$0.24	$0.22
2019 Averages	$2.63	$0.22	$0.54	$0.66	$0.75	$1.16	$0.37	$0.23	$0.26
2020 Averages										$2.08	$0.19	$0.46	$0.59		$0.77	$0.33	$0.18	$0.21

2020 by quarter:
2021 by quarter:
1st Quarter	$1.95	$0.14	$0.37	$0.57	$0.63	$0.93	$0.31	$0.18	$0.19	$2.71	$0.24	$0.89	$0.94	$0.93	$1.33	$0.73	$0.44	$0.38

(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 (“RGP”) prices represent weighted-average spot prices for such product as reported by IHS Chemical.
(4)	The “Indicative Gas Processing Gross Spread” represents aour 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~~Louisiana. Our estimate of the ~~table above). The~~ indicative spread does not consider the operating costs incurred by a natural gas processing facility 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.

The weighted-average indicative market price for NGLs was $0.61 per gallon in the first quarter of 2021 versus $0.35 per gallon in the first quarter of ~~2020 versus $0.57 per gallon during the first quarter~~2020.

Table of ~~2019.~~ Contents

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

	WTI	Midland	Houston	LLS	WTI	Midland	Houston	LLS
	Crude Oil,		Crude Oil	Crude Oil,	Crude Oil,		Crude Oil	Crude Oil,
	$/barrel				$/barrel
	(1)	(2)		(3)	(1)	(2)		(3)
2019 by quarter:
2020 by quarter:
1st Quarter	$54.90	$53.70	$61.19	$62.35	$46.17	$45.51	$47.81	$48.15
2nd Quarter	$59.81	$57.62	$66.47	$67.07	$27.85	$28.22	$29.68	$30.12
3rd Quarter	$56.45	$56.12	$59.75	$60.64	$40.93	$41.05	$41.77	$42.47
4th Quarter	$56.96	$57.80	$60.04	$60.76	$42.66	$43.07	$43.63	$44.08
2019 Averages	$57.03	$56.31	$61.86	$62.71
2020 Averages					$39.40	$39.46	$40.72	$41.21

2020 by quarter:
2021 by quarter:
1st Quarter	$46.17	$45.51	$47.81	$48.15	$57.84	$59.00	$59.51	$59.99

(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.

The decline in commodity prices since the beginning of 2020 is attributable to the ongoing effects of the COVID-19 pandemic and, with respect to crude oil, the recent oil price dispute between Saudi Arabia and Russia. See “~~Update on 2020 Outlook – Coronavirus and Oil Price Shock” within this Item 2 for information regarding these events.~~

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Fluctuations in our consolidated revenues and cost of sales amounts are explained in large part by changes in energy commodity prices. ~~A decrease~~An increase in our consolidated marketing revenues due to ~~lower~~higher energy commodity sales prices may not result in ~~a decrease~~an increase in gross operating margin or cash available for distribution, since our consolidated cost of sales amounts would also ~~decrease~~increase due to comparable ~~decreases~~increases in the purchase prices of the underlying energy commodities. The same type of correlation would be true in the case of ~~higher~~lower energy commodity sales prices and purchase costs.

We attempt to mitigate commodity price exposure through our hedging activities and the use of fee-based arrangements. See Note 1413 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report and “Quantitative and Qualitative Disclosures About Market Risk” under Part I, Item 3 of this quarterly report for information regarding our commodity hedging activities.

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Income Statement Highlights

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

For the Three Months
Ended March 31,

2020 2019
Revenues $ 7,482.5 $ 8,543.5
Costs and expenses:
Operating costs and expenses:
Cost of sales 4,823.0 5,835.6
Other operating costs and expenses 752.8 728.8
Depreciation, amortization and accretion expenses 482.8 450.9
Net losses (gains) attributable to asset sales 0.1 (0.4 )
Asset impairment and related charges 1.6 4.8
Total operating costs and expenses 6,060.3 7,019.7
General and administrative costs 55.5 52.2
Total costs and expenses 6,115.8 7,071.9
Equity in income of unconsolidated affiliates 140.8 154.6
Operating income 1,507.5 1,626.2
Interest expense (317.5 ) (277.2 )
Change in fair value of Liquidity Option (2.3 ) (57.8 )
Other, net 8.1 1.5
Benefit from (provision for) income taxes 179.2 (12.3 )
Net income 1,375.0 1,280.4
Net income attributable to noncontrolling interests (24.9 ) (19.9 )
Net income attributable to limited partners $ 1,350.1 $ 1,260.5

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	For the Three Months Ended March 31,
	2021			2020
Revenues	$	9,155.3		$	7,482.5
Costs and expenses:
Operating costs and expenses:
Cost of sales		6,263.0			4,823.0
Depreciation, amortization and accretion expenses		498.7			482.8
Asset impairment charges		65.5			1.6
Other operating costs and expenses		726.2			752.9
Total operating costs and expenses		7,553.4			6,060.3
General and administrative costs		56.3			55.5
Total costs and expenses		7,609.7			6,115.8
Equity in income of unconsolidated affiliates		148.9			140.8
Operating income		1,694.5			1,507.5
Other income (expense):
Interest expense		(322.8	)		(317.5	)
Other, net		0.9			5.8
Total other expense, net		(321.9	)		(311.7	)
Income before income taxes		1,372.6			1,195.8
Benefit from (provision for) income taxes		(10.0	)		179.2
Net income		1,362.6			1,375.0
Net income attributable to noncontrolling interests		(21.3	)		(24.9	)
Net income attributable to preferred units		(0.9	)		–
Net income attributable to common unitholders	$	1,340.4		$	1,350.1

Revenues

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

	For the Three Months Ended March 31,				For the Three Months Ended March 31,
	2020		2019		2021		2020
NGL Pipelines & Services:
Sales of NGLs and related products	$	2,419.2	$	2,671.2	$	3,005.6	$	2,419.2
Midstream services		548.9		643.2		577.9		548.9
Total		2,968.1		3,314.4		3,583.5		2,968.1
Crude Oil Pipelines & Services:
Sales of crude oil		1,696.9		2,328.4		1,838.9		1,696.9
Midstream services		342.0		278.9		326.6		342.0
Total		2,038.9		2,607.3		2,165.5		2,038.9
Natural Gas Pipelines & Services:
Sales of natural gas		399.2		655.7		1,335.3		399.2
Midstream services		271.4		271.8		251.5		271.4
Total		670.6		927.5		1,586.8		670.6
Petrochemical & Refined Products Services:
Sales of petrochemicals and refined products		1,597.5		1,480.6		1,598.9		1,597.5
Midstream services		207.4		213.7		220.6		207.4
Total		1,804.9		1,694.3		1,819.5		1,804.9
Total consolidated revenues	$	7,482.5	$	8,543.5	$	9,155.3	$	7,482.5

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Total revenues for the first quarter of ~~2020 decreased $1.06~~2021 increased $1.67 billion when compared to the first quarter of ~~2019~~2020 primarily due to a net ~~$1.02~~$1.67 billion ~~decrease~~increase in marketing revenues. Revenues from the marketing of ~~crude oil and~~NGLs, natural gas, ~~decreased $888.0 million~~petrochemicals and refined products increased a combined $1.52 billion quarter-to-quarter primarily due to ~~lower~~higher average sales prices, which accounted for a ~~$610.0 million decrease, and~~$2.1 billion increase, partially offset by lower sales volumes, which accounted for ~~an additional $278.0~~a $580.3 million decrease. Revenues from the marketing of NGLs decreased a net $252.0 million quarter-to-quarter primarily due to lower sales prices, which accounted for a $962.4 million decrease, partially offset by the effects of higher sales volumes, which resulted in a $710.4 million increase. Revenues from the marketing of petrochemicals and refined productscrude oil increased ~~a net $116.9~~$142.0 million quarter-to-quarter primarily due to higher sales volumes, which accounted for a ~~$197.1~~$121.7 million increase, ~~partially offset by lower~~and higher average sales prices, which ~~resulted in~~accounted for an ~~$80.2~~additional $20.3 million ~~decrease.~~increase.

Revenues from midstream services for the first quarter of ~~2020 decreased $37.9~~2021 increased $6.9 million when compared to the first quarter of ~~2019.~~2020. Revenues from our ~~natural gas processing~~terminal facilities ~~decreased a net $45.3~~increased $30.2 million quarter-to-quarter primarily due to ~~the impact of lower NGL prices in the first quarter of 2020 compared to the first quarter of 2019 on the value of equity NGLs we receive as non-cash consideration for processing services.~~higher deficiency fee revenue. Revenues from our ~~Midland-to-ECHO 2~~ pipeline ~~which commenced limited service in February 2019 and full service in April 2019, increased $41.0 million quarter-to-quarter. Lastly, revenues from our Mont Belvieu NGL fractionation complex~~assets decreased ~~$35.8~~$24.6 million quarter-to-quarter primarily due to lower ~~fractionation fee revenues from third parties.~~demand for natural gas transportation services.

Operating costs and expenses

Total operating costs and expenses for the first quarter of ~~2020 decreased $959.4 million~~2021 increased $1.49 billion when compared to the first quarter of ~~2019~~2020 primarily due to ~~lower~~higher cost of sales.

Cost of sales

Cost of sales increased $1.44 billion for the first quarter of 2021 when compared to the first quarter of 2020. On a combined basis, the cost of sales associated with our marketing of NGLs, natural gas, petrochemicals and refined products increased a net $1.13 billion quarter-to-quarter primarily due to higher average purchase prices, which accounted for a $1.44 billion increase, partially offset by lower sales volumes, which accounted for a $313.7 million decrease. The cost of sales associated with our marketing of crude oil ~~and natural gas decreased a combined $703.1~~increased $311.6 million quarter-to-quarter primarily due to ~~lower~~higher average purchase prices, which accounted for a ~~$488.4~~$199.8 million ~~decrease,~~increase, and ~~lower~~higher sales volumes, which accounted for an additional ~~$214.7 million decrease. The cost of sales associated with our marketing of NGLs, petrochemicals and refined products decreased a combined net $309.5 million~~ ~~quarter-to-quarter~~ ~~primarily due to lower purchase prices, which accounted for a $1.02 billion decrease, partially offset by higher sales volumes, which accounted for a $706.6~~$111.8 million increase.

~~Other operating costs~~Depreciation, amortization and accretion expenses

Depreciation, amortization and accretion expense for the first quarter of ~~2020~~2021 increased ~~$24.0~~a combined $15.9 million ~~quarter-to-quarter primarily due~~when compared to ~~higher employee compensation costs and ad valorem taxes. Depreciation, amortization and accretion expense increased $31.9 million~~ ~~quarter-to-quarter~~the first quarter of 2020 primarily due to assets placed into full or limited service since the first quarter of ~~2019~~2020 (e.g., ~~the isobutane dehydrogenation (“iBDH”) plant, Mentone~~Chambers County Fracs X and ~~Orla facilities~~XI and the ~~Enterprise Navigator ethylene terminal)~~Midland-to-ECHO 3 pipeline).

Asset impairment charges

Non-cash asset impairment charges for the first quarter of 2021 increased $63.9 million when compared to the first quarter of 2020 primarily due to a $43.4 million charge attributable to a coal bed natural gas gathering system and related Val Verde treating facility, both of which were components of our San Juan Gathering System and classified as held-for-sale at March 31, 2021.

~~Table~~See Note 4 of ~~Contents~~the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report for additional information regarding our asset impairment charges.

Other operating costs and expenses

Other operating costs and expenses for the first quarter of 2021 decreased $26.7 million when compared the first quarter of 2020 primarily due to lower maintenance, chemical and facility charges.

General and administrative costs

General and administrative costs for the first quarter of ~~2020~~2021 increased $~~3.3~~ $0.8 million when compared to the first quarter of ~~2019~~2020 primarily due to higher employee compensation ~~costs and professional services expense.~~costs.

Equity in income of unconsolidated affiliates

Equity income from our unconsolidated affiliates for the first quarter of ~~2020 decreased $13.8~~ 2021 increased $8.1 million when compared to the first quarter of ~~2019~~2020 primarily due to ~~decreased~~increased earnings from our investments in crude oil pipelines.

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Operating income

Operating income for the first quarter of ~~2020 decreased~~ $~~118.7~~2021 increased $187.0 million when compared to the first quarter of ~~2019~~2020 due to the previously described quarter-to-quarter ~~changes in revenues, operating costs and expenses, general and administrative costs and equity in income of unconsolidated affiliates.~~changes.

Interest expense

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

	For the Three Months Ended March 31,						For the Three Months Ended March 31,
	2020			2019			2021			2020
Interest charged on debt principal outstanding	$	331.5		$	307.5		$	326.9		$	331.5
Impact of interest rate hedging program, including related amortization ~~(1)~~		9.6			(1.1	)		8.6			9.6
Interest costs capitalized in connection with construction projects ~~(2)~~(1)		(30.5	)		(36.2	)		(19.6	)		(30.5	)
Other ~~(3)~~(2)		6.9			7.0			6.9			6.9
Total	$	317.5		$	277.2		$	322.8		$	317.5

(1)	~~Amount presented for the first quarter of 2019 includes a $9.8 million benefit from swaption premiums.~~
~~(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 investment levels and the interest rates charged on borrowings.
~~(3)~~(2)	Primarily reflects facility commitment fees charged in connection with our revolving credit facilities and amortization of debt issuance costs.

Interest charged on debt principal outstanding, which is a key driver of interest expense, ~~increased~~decreased a net $~~24.0~~$4.6 million quarter-to-quarter primarily due to ~~increased debt principal amounts outstanding during~~ the ~~first quarter of 2020, which accounted for a~~ ~~$31.2~~ ~~million increase, partially offset by the effect~~effects of lower overall interest rates during the first quarter of ~~2020,~~2021, which accounted for an $8.9 million decrease, partially offset by higher debt principal amounts outstanding during the first quarter of 2021, which accounted for a $~~7.2~~$4.3 million ~~decrease.~~increase. Our weighted-average debt principal balance for the first quarter of ~~2020~~2021 was $~~29.39~~$29.96 billion compared to ~~$26.76~~$29.39 billion for the first quarter of ~~2019.~~2020. In general, our debt principal balances have increased over time due to the partial debt financing of our capital investments.

For additional information regarding our debt obligations, see Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report. For a discussion of our capital projects, see “Capital Investments” within this Part I, Item 2.

~~Change in fair value of Liquidity Option~~Income taxes

~~For~~The following table presents the ~~period~~components of our consolidated benefit from (provision for) income taxes for the periods indicated (dollars in ~~which~~millions):

	For the Three Months Ended March 31,
	2021			2020
Deferred tax benefit (expense) attributable to OTA	$	(6.3	)	$	187.2
Texas Margin Tax		(3.3	)		(7.7	)
Other		(0.4	)		(0.3	)
Benefit from (provision for) income taxes	$	(10.0	)	$	179.2

On February 25, 2020, we received notice from Marquard & Bahls AG (“M&B”) of its election to exercise its rights under the Liquidity Option ~~was outstanding, we recognized non-cash expense in connection with accretion~~Agreement among the Partnership, OTA Holdings, Inc. (a Delaware corporation previously named Oiltanking Holding Americas, Inc. (“OTA”)), and ~~changes in management estimates that affected the valuation of the Liquidity~~M&B dated October 1, 2014 (the “Liquidity Option ~~liability. As discussed in the following section,~~ ~~Income taxes, our~~Agreement”). The Partnership settled its obligations under the Liquidity Option Agreement ~~were settled~~ on March 5, ~~2020.~~

2020 and indirectly assumed the deferred tax liability of OTA, which reflects OTA’s outside basis difference in the limited partner interests it received from the Partnership in October 2014.

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~~Expense attributable to changes~~At March 5, 2020, the Partnership’s liability recognized in ~~the fair value of~~connection with the Liquidity Option ~~were $2.3~~Agreement was $511.9 million ~~and $57.8 million during~~(referred to as the ~~first quarters of 2020 and 2019, respectively. Expense for the first quarter of 2020 primarily reflects accretion expense for the period in which the Liquidity~~“Liquidity Option liability was outstanding before it was settled on March 5, 2020. The higher level of expense recognized in the first quarter of 2019 was primarily due to a decrease in the discount factor used in determining the present value of the liability.

~~Income taxes~~

~~We recognized a non-cash benefit from income taxes in the first quarter of 2020 in the amount of $179.2 million primarily due to~~liability”). Upon settlement of the Liquidity Option liability on March 5, 2020, which accounted for $72.2 million of the benefit, and a subsequent decrease in the related deferred income tax amounts through March 31, 2020, which accounted for an additional $115.0 million benefit.

~~On March 5, 2020, we settled the Liquidity Option (see “Other Recent Developments” within this Item 2) and assumed OTA’s deferred tax liability, which mainly comprised the outside basis difference of OTA in the 54,807,352 EPD common units it received in October 2014.~~ ~~Upon settlement of the Liquidity Option,~~Agreement, the Liquidity Option liability was effectively replaced by the deferred tax liability of OTA as calculated in accordance with ASC 740, Income Taxes. ~~At March 5, 2020, the Liquidity Option liability amount was $511.9 million.~~ Since the book value of the Liquidity Option liability exceeded OTA’s estimated deferred tax liability of $439.7 million on that date, we recognized a non-cash benefit in earnings of $72.2 million, which is reflected in the “Benefit from (provision for) income ~~taxes”~~tax” line on our Unaudited Condensed Statement of Consolidated Operations for the ~~three months ended~~first quarter of 2020. OTA recognized an additional net, non-cash deferred income tax benefit of $115.0 million primarily due to a decrease in the outside basis difference of its investment in the Partnership attributable to a decline in the market price of the Partnership’s common units subsequent to March 5, 2020 through March 31, 2020. ~~At March 31,~~In total, our earnings for the first quarter of 2020 reflect $187.2 million of deferred income tax benefit attributable to OTA.

On September 30, 2020, OTA exchanged the Partnership common units it owned for non-publicly traded preferred units having a stated value of $1,000 per unit. As a result, beginning September 30, 2020, OTA’s deferred tax liability ~~decreased to $324.7 million primarily~~no longer fluctuates due to ~~a decline~~market price changes in ~~the fair value of OTA’s assets, which resulted in an additional non-cash benefit of $115.0 million in income tax expense for the first quarter of 2020.~~

~~For additional information regarding income taxes, see Note 11 of the~~ ~~Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.~~our common units.

Business Segment Highlights

Our operations are reported under four business segments: (i) NGL Pipelines & Services, (ii) Crude Oil Pipelines & Services, (iii) Natural Gas Pipelines & Services and (iv) Petrochemical & Refined Products Services. Our business segments are generally organized and managed according to the types of services rendered (or technologies employed) and products produced and/or sold.

We evaluate segment performance based on our non-generally accepted accounting principle (“non-GAAP”) financial measure of gross operating margin. Gross operating margin is an important performance measure of the core profitability of our operations and forms the basis of our internal financial reporting. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results.

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

	For the Three Months Ended March 31,					For the Three Months Ended March 31,
	2020			2019		2021		2020
Gross operating margin by segment:
NGL Pipelines & Services	$	1,042.0		$	959.2	$	1,086.4	$	1,042.0
Crude Oil Pipelines & Services		452.9			662.3		400.2		452.9
Natural Gas Pipelines & Services		283.8			264.3		535.2		283.8
Petrochemical & Refined Products Services		278.5			242.6		281.5		278.5
Total segment gross operating margin (1)		2,057.2			2,128.4		2,303.3		2,057.2
Net adjustment for shipper make-up rights		(9.7	)		5.3		20.0		(9.7	)
Total gross operating margin (non-GAAP)	$	2,047.5		$	2,133.7	$	2,323.3	$	2,047.5

(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 under Note 10 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

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Total gross operating margin includes equity in the earnings of unconsolidated affiliates, but is exclusive of other income and expense transactions, income taxes, the cumulative effect of changes in accounting principles and extraordinary charges. Total gross operating margin is presented on a 100% basis before any allocation of earnings to noncontrolling interests. Our calculation of gross operating margin may or may not be comparable to similarly titled measures used by other companies. Segment gross operating margin for NGL Pipelines & Services and Crude Oil Pipelines & Services reflect adjustments for shipper make-up rights that are included in management’s evaluation of segment results. However, these adjustments are excluded from non-GAAP total gross operating margin.

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

	For the Three Months Ended March 31,					For the Three Months Ended March 31,
	2020		2019			2021		2020
Operating income	$	1,507.5	$	1,626.2		$	1,694.5	$	1,507.5
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(1)		482.8		450.9			496.1		482.8
Asset impairment and related charges in operating costs and expenses		1.6		4.8
Net losses (gains) attributable to asset sales in operating costs and expenses		0.1		(0.4	)
Asset impairment charges in operating costs and expenses							65.5		1.6
Net losses attributable to asset sales and related matters in operating costs and expenses							10.9		0.1
General and administrative costs		55.5		52.2			56.3		55.5
Total gross operating margin (non-GAAP)	$	2,047.5	$	2,133.7		$	2,323.3	$	2,047.5

(1)	Excludes amortization of major maintenance costs for reaction-based plants, which are a component of gross operating margin.

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

NGL Pipelines & Services

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

	For the Three Months Ended March 31,				For the Three Months Ended March 31,
	2020		2019		2021		2020
Segment gross operating margin:
Natural gas processing and related NGL marketing activities	$	252.3	$	292.7	$	294.3	$	252.3
NGL pipelines, storage and terminals		653.3		557.3		626.6		653.3
NGL fractionation		136.4		109.2		165.5		136.4
Total	$	1,042.0	$	959.2	$	1,086.4	$	1,042.0

Selected volumetric data:
NGL pipeline transportation volumes (MBPD)		3,762		3,436		3,271		3,762
NGL marine terminal volumes (MBPD)		742		540		652		742
NGL fractionation volumes (MBPD)		1,133		969		1,190		1,133
Equity NGL production volumes (MBPD) (1)		140		154		162		140
Fee-based natural gas processing volumes (MMcf/d) (2,3)		4,659		4,758		4,018		4,659

(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 natural gas processing ~~facilities.~~plants.
(3)	Fee-based natural gas processing volumes are measured at either the wellhead or plant inlet in MMcf/d. For the second, third and fourth quarters of 2019, fee-based natural gas processing volumes measured in this manner were 4,705 MMcf/d, 4,724 MMcf/d and 4,763 MMcf/d, respectively, and averaged 4,738 MMcf/d for 2019 and 4,430 MMcf/d for 2018.

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Natural gas processing and related NGL marketing activities

Gross operating margin from natural gas processing and related NGL marketing activities for the first quarter of ~~2020 decreased $40.4~~ 2021 increased $42.0 million when compared to the first quarter of ~~2019.~~ 2020.

Gross operating margin from our ~~South Texas natural gas processing facilities decreased $24.8~~NGL marketing activities increased $96.7 million quarter-to-quarter primarily due to higher average sales margins (including the impact of hedging activities), which accounted for a $53.7 million increase, and higher sales volumes, which accounted for an additional $46.6 million increase. Results from marketing strategies that optimize our transportation, storage and plant assets increased a combined $95.4 million quarter-to-quarter, partially offset by lower earnings from the optimization of our export assets, which accounted for a $47.1 million decrease.

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Gross operating margin from our Permian Basin natural gas processing facilities increased $10.0 million quarter-to-quarter primarily due to higher fee-based processing volumes, which accounted for a $6.7 million increase, and higher average processing margins (including the impact of hedging activities), which accounted for an ~~$18.6~~additional $3.5 million increase. Fee-based processing volumes and equity NGL production at our Permian Basin natural gas processing facilities increased 193 MMcf/d and 31 MBPD, respectively, quarter-to-quarter.

Gross operating margin from our South Texas natural gas processing facilities decreased $41.2 million quarter-to-quarter primarily due to lower equity NGL production of 6 MBPD, which accounted for a $28.8 million decrease, ~~and~~ lower average processing fees and volumes, which accounted for decreases of $12.3 million and $3.7 million, respectively, and higher operating and maintenance costs, which accounted for an additional ~~$5.2~~$6.1 million decrease. Partially offsetting these negative impacts were higher average processing margins (including the impact of hedging activities), which accounted for a $9.8 million quarter-to-quarter increase. Fee-based processing volumes at our South Texas natural gas processing facilities decreased 213 MMcf/d quarter-to-quarter.

Gross operating margin from our Rockies natural gas processing facilities (Meeker, Pioneer and Chaco) decreased a combined $~~17.9~~ $21.5 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $~~21.9~~$19.4 million decrease, and lower fee-based processing volumes, which accounted for an additional $6.2 million decrease, partially offset by ~~higher processing and other fees,~~lower operating costs, which accounted for a ~~$5.2~~$4.1 million increase. On a combined basis, fee-based natural gas processing volumes ~~and equity NGL production volumes~~ decreased ~~181~~402 MMcf/d ~~and~~ 16 ~~MBPD, respectively,~~ quarter-to-quarter.

~~Gross operating margin from our Permian Basin natural gas processing facilities decreased $14.4~~ million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $13.1 million decrease, and higher operating costs, which accounted for an additional $7.6 million decrease, partially offset by higher fee-based natural gas processing volumes, which accounted for an $11.0 million increase. Fee-based processing volumes at our Permian Basin natural gas processing facilities increased 273 MMcf/d quarter-to-quarter primarily due to processing volumes contributed by the third processing train at our Orla natural gas processing facility and our Mentone natural gas processing facility, which were placed into service in July 2019 and December 2019, respectively.

Gross operating margin from our Louisiana and Mississippi natural gas processing facilities decreased ~~$5.4~~$1.2 million quarter-to-quarter primarily due to lower average processing margins, which accounted for a $7.7 million decrease, and lower processing volumes, which accounted for an additional $1.5 million decrease, partially offset by higher average processing fees, which accounted for a $3.9 million increase.fees. Net to our interest, fee-based natural gas processing volumes and equity NGL production decreased ~~208~~184 MMcf/d and 5 MBPD, respectively, quarter-to-quarter. Gross operating margin from our Carthage natural gas processing facilities (Panola and Bulldog) decreased $4.1 million quarter-to-quarter primarily due to lower average processing margins. Fee-based natural gas processing volumes at these facilities increased 70 MMcf/d.

~~Gross operating margin from our NGL marketing activities increased a net $25.5~~ ~~million quarter-to-quarter primarily~~ due to higher sales volumes, which accounted for a $78.7 million increase, partially offset by lower average sales margins, which accounted for a $52.7 million decrease. Results from marketing strategies that optimize our export, storage and plant assets increased a combined $41.5 million quarter-to-quarter, partially offset by lower earnings from the optimization of our transportation assets, which accounted for a $3.4 million decrease. In addition, results from NGL marketing decreased $12.6 million quarter-to-quarter due to non-cash, mark-to-market losses of $12.2 million in the first quarter of 2020.

NGL pipelines, storage and terminals

Gross operating margin from our NGL pipelines, storage and terminal assets during the first quarter of ~~2020 increased $96.0~~2021 decreased $26.7 million when compared to the first quarter of ~~2019.~~ 2020.

A number of our pipelines, including the Mid-America Pipeline System, Seminole NGL Pipeline, Chaparral NGL Pipeline, Shin Oak NGL Pipeline, Texas Express Pipeline and Front Range Pipeline, serve Permian Basin and/or Rocky Mountain producers. On a combined basis, gross operating margin from these pipelines decreased a net $21.8 million quarter-to-quarter primarily due to lower transportation volumes of 213 MBPD (net to our interest), which accounted for a $44.0 million decrease, partially offset by higher average transportation fees, which accounted for an $18.6 million increase.

Gross operating margin from LPG-related activities at EHT ~~increased $33.0~~decreased $15.1 million quarter-to-quarter primarily due to ~~higher~~lower export volumes of ~~205~~95 MBPD. ~~The increase in export volumes is attributable to an LPG expansion project at EHT that we completed in the third quarter of 2019.~~ Gross operating margin from our related Houston Ship Channel Pipeline System ~~increased $8.2~~ decreased $3.6 million quarter-to-quarter primarily due to a ~~208~~144 MBPD ~~increase~~decrease in transportation volumes. Our marine terminal operations on the Houston Ship Channel were halted for 3 days due to closure of the ship channel during the February 2021 winter storms.

Gross operating margin from our South Texas NGL Pipeline System decreased $4.9 million quarter-to-quarter primarily due to lower transportation volumes of 55 MBPD.

Gross operating margin from our ~~Shin Oak NGL Pipeline~~South Louisiana storage facilities increased ~~$24.7~~$4.6 million quarter-to-quarter primarily due to higher ~~direct tariff transportation volumes, which accounted for a $22.4 million increase. Net to our interest, direct tariff movements on the Shin Oak NGL Pipeline increased 26 MBPD quarter-to-quarter.~~product blending revenues. Gross operating margin from our ~~Chaparral NGL Pipeline~~Chambers County storage complex increased ~~$14.2~~a net $4.4 million quarter-to-quarter primarily due to higher ~~transportation volumes of 43 MBPD,~~storage fees, which accounted for a ~~$9.9~~$15.1 million increase, partially offset by lower throughput fee revenues, which accounted for an $8.4 million decrease, and higher ~~average transportation fees,~~operating costs, which accounted for an additional ~~$2.9~~$3.4 million ~~increase.~~decrease.

NGL fractionation

Gross operating margin from NGL fractionation during the first quarter of 2021 increased $29.1 million when compared to the first quarter of 2020. Gross operating margin from our ~~Aegis Pipeline~~Chambers County NGL fractionation complex increased ~~$19.0~~$41.2 million quarter-to-quarter primarily due to ~~a 154~~higher volumes, including contributions from Frac X, which entered service in late March 2020, and Frac XI, which entered service in September 2020. NGL fractionation volumes increased 159 MBPD ~~increase in transportation volumes.~~

quarter-to-quarter (net to our interest). Gross operating margin from our South Texas NGL fractionators decreased $4.7 million quarter-to-quarter primarily due to lower NGL fractionation volumes of 49 MBPD.

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~~Gross operating margin from our equity investment in the Front Range Pipeline increased $~~3.9 million quarter-to-quarter primarily due to higher average transportation fees, which accounted for a $2.9 million increase, and higher transportation volumes of 14 MBPD (net to our interest), which accounted for an additional $2.8 million increase. Gross operating margin from our Morgan’s Point Ethane Export Terminal increased $3.7 million quarter-to-quarter primarily due to lower utility and compensation costs. Gross operating margin from our Dixie Pipeline and related terminals increased a combined $3.0 million quarter-to-quarter primarily due to higher transportation volumes of 24 MBPD.

Gross operating margin from our Appalachia-to-Texas Express, or “ATEX,” pipeline decreased $10.3 million quarter-to-quarter primarily due to lower transportation volumes, which decreased 32 MBPD quarter-to-quarter.

~~Gross operating margin from our Mont Belvieu storage facility decreased $7.4 million quarter-to-quarter primarily due to lower handling fee revenues.~~

~~NGL fractionation~~

~~Gross operating margin from NGL fractionation~~ ~~during the first quarter of 2020 increased $27.2 million when compared to the first quarter of 2019.~~ ~~Gross operating margin at our Hobbs NGL fractionator increased $18.5~~ ~~million quarter-to-quarter primarily due to lower major maintenance costs, which accounted for a $14.4~~ ~~million increase, and higher fractionation volumes of 18 MBPD, which accounted for an additional $3.5~~ million increase. The first quarter of 2019 included downtime for major maintenance activities at Hobbs. Gross operating margin at our Norco NGL fractionator increased $5.3 million quarter-to-quarter primarily due to lower maintenance and other operating costs, which accounted for a $2.5 million increase, and higher fractionation volumes of 13 MBPD, which accounted for an additional $2.0 million increase.

Gross operating margin from our Mont Belvieu NGL fractionation complex was essentially flat quarter-to-quarter primarily due to lower product blending revenues, which accounted for a $7.6 million decrease, being nearly offset by the impact of higher fractionation volumes, which accounted for a $7.4 million increase. NGL fractionation volumes increased 87 MBPD quarter-to-quarter (net to our interest) in part due to start-up of the first fractionation train at our newly constructed NGL fractionation facility located in Chambers County, Texas (“Frac X”).

Crude Oil Pipelines & Services

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

For the Three Months
Ended March 31,

2020 2019
Segment gross operating margin:
   Midland-to-ECHO System:
      Midland-to-ECHO 1 pipeline and related business activities, excluding associated
         non-cash mark-to-market results
$ 60.2 $ 99.7
      Non-cash mark-to-market gain attributable to the Midland-to-ECHO 1 pipeline 0.9 67.2
      Total Midland-to-ECHO 1 pipeline and related business activities 61.1 166.9
      Midland-to-ECHO 2 pipeline 29.3 17.4
      Total Midland-to-ECHO System 90.4 184.3
   Other crude oil pipelines, terminals and related marketing results 362.5 478.0
   Total $ 452.9 $ 662.3

Selected volumetric data:
   Crude oil pipeline transportation volumes (MBPD) 2,393 2,227
   Crude oil marine terminal volumes (MBPD) 985 886

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	For the Three Months Ended March 31,
	2021		2020
Segment gross operating margin:
Midland-to-ECHO System and related business activities	$	79.0	$	90.4
Other crude oil pipelines, terminals and related marketing results		321.2		362.5
Total	$	400.2	$	452.9

Selected volumetric data:
Crude oil pipeline transportation volumes (MBPD)		1,935		2,393
Crude oil marine terminal volumes (MBPD)		572		985

Gross operating margin from our Crude Oil Pipelines & Services segment for the first quarter of ~~2020~~2021 decreased ~~$209.4~~$52.7 million when compared to the first quarter of ~~2019.~~ 2020.

Gross operating margin from our ~~Midland-to-ECHO 1 pipeline and related business activities~~South Texas Crude Oil Pipeline System decreased ~~$105.8~~$25.7 million quarter-to-quarter primarily due to lower ~~non-cash mark-to-market earnings,~~transportation and other fees, which accounted for a ~~$66.3~~$15.3 million decrease, and lower ~~earnings from related marketing activities,~~transportation volumes of 49 MBPD, which accounted for an additional ~~$44.9~~$12.4 million decrease. Gross operating margin from our ~~Midland-to-ECHO 2 pipeline increased $11.9~~equity investment in the Eagle Ford Crude Oil Pipeline decreased $11.3 million quarter-to-quarter primarily due to ~~higher~~lower transportation volumes of 6493 MBPD ~~which accounted for a $22.2 million increase, partially offset by higher operating costs of $10.6 million.~~(net to our interest).

Gross operating margin from ~~other crude oil marketing~~our West Texas Pipeline System decreased $19.9 million quarter-to-quarter primarily due to lower transportation volumes of 57 MBPD, which accounted for an $8.4 million decrease, and lower average fees, which accounted for an additional $7.9 million decrease.

Gross operating margin from our Midland-to-ECHO System and related business activities decreased ~~$118.0~~$11.4 million quarter-to-quarter primarily due to lower average sales margins from marketing activities (including the impact of hedging activities), which accounted for a ~~$94.9~~$21.2 million decrease, partially offset by lower chemical and ~~lower non-cash mark-to-market earnings,~~other operating costs, which accounted for a $12.1 million increase. Transportation volumes for our Midland-to-ECHO System decreased an ~~additional $22.8~~aggregate 6 MBPD quarter-to-quarter (net to our interest).

Gross operating margin from our ECHO terminal decreased $4.9 million ~~decrease.~~quarter-to-quarter primarily due to lower terminaling and storage revenues.

Gross operating margin from our other crude oil marketing activities increased $16.6 million quarter-to-quarter primarily due to higher average sales margins (including the impact of hedging activities).

Gross operating margin from crude oil activities at EHT increased $8.9 million quarter-to-quarter primarily due to lower operating costs. Loading volumes at EHT decreased 380 MBPD in the first quarter of 2021 due to lower export activity.

Gross operating margin from our equity investment in the Seaway Pipeline ~~decreased $16.5~~increased slightly quarter-to-quarter. Higher capacity and other fees of $9.0 million quarter-to-quarter ~~primarily due~~were substantially offset by the effects of lower transportation volumes of 182 MBPD (net to ~~lower average transportation fees,~~our interest), which accounted for a ~~$9.9~~$7.7 million ~~decrease, and lower transportation volumes, which accounted for an additional $8.1 million~~ decrease. Transportation volumes on the Seaway Pipeline decreased 52 MBPD quarter-to-quarter (net to our interest). Gross operating margin from our South Texas Crude Oil Pipeline System decreased $9.5 million quarter-to-quarter primarily due to lower deficiency fees in the first quarter of 2020. Transportation volumes on the South Texas Crude Oil Pipeline System increased 10 MBPD quarter-to-quarter.

~~Gross operating margin from our West Texas System increased $13.4 million quarter-to-quarter primarily due to higher transportation volumes~~

Table of ~~74 MBPD. Lastly, gross operating margin from crude oil activities at EHT increased $15.4 million quarter-to-quarter primarily due to higher net export volumes of 64 MBPD.~~Contents

Natural Gas Pipelines & Services

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

	For the Three Months Ended March 31,
	2020			2019			For the Three Months Ended March 31,
							2021		2020
Segment gross operating margin		$	283.8		$	264.3	$	535.2	$	283.8

Selected volumetric data:
Natural gas pipeline transportation volumes (BBtus/d)			13,854			14,197		13,704		13,854

Gross operating margin from our Natural Gas Pipelines & Services segment for the first quarter of ~~2020~~2021 increased ~~$19.5~~$251.4 million when compared to the first quarter of ~~2019.~~2020. As noted previously, two major winter storms impacted Texas and the southern U.S. in mid-February 2021. Given the high demand for natural gas during the storms, we sold natural gas to assist electricity generators, natural gas utilities and industrial customers in meeting their requirements. Gross operating margin from ~~our~~ natural gas marketing activities increased ~~$31.6~~$265.9 million quarter-to-quarter primarily due to higher ~~non-cash mark-to-market earnings.~~average sales margins (including the impact of hedging activities) in connection with these unusual storm events.

Gross operating margin from our Permian Basin Gathering System increased ~~$10.9~~$14.1 million quarter-to-quarter primarily due to higher average condensate sales prices, which accounted for a ~~$7.2~~$6.1 million increase, higher condensate sales volumes, which accounted for a $4.5 million increase, and ~~a 306 BBtus/d increase in~~higher natural gas gathering volumes of 361 BBtus/d, which accounted for an additional ~~$5.5~~$4.3 million ~~increase.~~increase, partially offset by lower average gathering fees, which accounted for a $2.9 million decrease. The quarter-to-quarter increase in gathering volumes is attributable to deliveries at our Orla and Mentone facilities.

On a combined basis, gross operating margin from our Jonah Gathering System, Piceance Basin Gathering System, and San Juan Gathering System in the Rocky Mountains increased a net $0.8 million quarter-to-quarter primarily due to higher average gathering and other fees, which accounted for a $6.9 million increase, and lower operating costs, which accounted for an additional $3.6 million increase, partially offset by lower gathering volumes of 503 BBtus/d, which accounted for a $9.7 million decrease.

Gross operating margin from our ~~Haynesville Gathering~~Acadian Gas System decreased ~~$13.2~~$14.2 million ~~quarter-to-quarter~~ primarily due to ~~lower gathering, compression and other fee revenues,~~a one-time producer payment in the first quarter of 2020, which accounted for a ~~$10.0~~$12.5 million quarter-to-quarter decrease, and lower ~~gathering volumes of 245 BBtus/d,~~capacity reservation fees, which accounted for an additional ~~$3.9~~$4.9 million decrease. Transportation volumes for the Acadian Gas System decreased 60 BBtus/d quarter-to-quarter.

Gross operating margin from our Texas Intrastate System decreased ~~$8.8~~$12.1 million quarter-to-quarter primarily due to lower capacity reservation ~~fees.~~revenues. Transportation volumes on our Texas Intrastate System ~~increased 31~~decreased 11 BBtus/d.

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Petrochemical & Refined Products Services

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

	For the Three Months Ended March 31,				For the Three Months Ended March 31,
	2020		2019		2021		2020
Segment gross operating margin:
Propylene production and related activities	$	108.6	$	102.3	$	146.0	$	108.6
Butane isomerization and related operations		16.1		24.0		11.2		16.1
Octane enhancement and related plant operations		69.0		24.3		15.5		69.0
Refined products pipelines and related activities		75.1		81.9		102.3		75.1
Marine transportation and other services		9.7		10.1
Ethylene exports and other services						6.5		9.7
Total	$	278.5	$	242.6	$	281.5	$	278.5

Selected volumetric data:
Propylene production volumes (MBPD)		98		90		83		98
Butane isomerization volumes (MBPD)		105		111		63		105
Standalone DIB processing volumes (MBPD)		105		93
Standalone deisobutanizer (“DIB”) processing volumes (MBPD)						139		105
Octane enhancement and related plant sales volumes (MBPD) (1)		34		24		29		34
Pipeline transportation volumes, primarily refined products & petrochemicals (MBPD)		712		810
Pipeline transportation volumes, primarily refined products and petrochemicals (MBPD)						749		712
Marine terminal volumes, primarily refined products and petrochemicals (MBPD)		271		338		266		271

(1)	Reflects aggregate sales volumes for our octane additive and iBDH facilities located at our ~~Mont Belvieu~~Chambers County complex and our ~~high-purity isobutylene production~~HPIB facility located adjacent to the Houston Ship Channel.

Propylene production and related activities

Gross operating margin from propylene production and related activities for the first quarter of ~~2020~~2021 increased ~~$6.3~~$37.4 million when compared to the first quarter of ~~2019.~~ 2020.

Gross operating margin from our ~~initial propane dehydrogenation (“PDH 1”) facility~~propylene production facilities increased ~~$12.2~~a combined $27.8 million quarter-to-quarter primarily due to higher propylene fractionation fees, which accounted for a $24.7 million increase, and lower operating costs, which accounted for an additional $10.2 million increase, partially offset by lower propylene and associated by-product sales ~~volumes. Plant production~~volumes, which accounted for an $8.2 million decrease. Propylene and associated by-product volumes at these facilities decreased a combined 16 MBPD quarter-to-quarter (net to our interest) primarily due to planned major maintenance activities at our PDH 1 ~~which includes by-products, increased 5 MBPD quarter-to-quarter.~~ facility during the first quarter of 2021. The PDH 1 facility returned to service during the second half of March 2021.

Gross operating margin from our ~~Mont Belvieu~~ propylene ~~splitters decreased $3.6~~pipelines in Louisiana increased $6.3 million quarter-to-quarter primarily due to higher ~~major maintenance costs incurred during the first quarter~~transportation volumes of ~~2020. Propylene production volumes from our splitter units increased 3 MBPD (net to our interest).~~22 MBPD.

~~Isomerization~~Butane isomerization and related operations

Gross operating margin from butane isomerization and related operations decreased ~~$7.9~~$4.9 million quarter-to-quarter primarily due to lower ~~average by-product sales prices.~~isomerization volumes, which accounted for a $6.4 million decrease.

Octane enhancement and related plant operations

Gross operating margin from our octane enhancement and related plant operations ~~which includes our recently completed iBDH facility, increased $44.7~~decreased $53.5 million quarter-to-quarter primarily due to ~~higher~~lower average sales margins (including the impact of hedging), which accounted for a $32.4 million decrease, and lower sales volumes, which accounted for ~~a $26.0 million increase, and higher average sales margins, which accounted for~~ an additional ~~$24.1~~$21.1 million ~~increase, partially offset by higher operating expenses,~~decrease. Volumes at these facilities were lower in the first quarter of 2021 due to planned major maintenance activities, which ~~accounted~~were completed in the last week of January 2021 for ~~a $6.5 million decrease.~~our HPIB plant and the beginning of May 2021 for our octane enhancement plant.

Refined products pipelines and related activities

Gross operating margin from refined products pipelines and related activities during the first quarter of ~~2020 decreased $6.8~~2021 increased $27.2 million when compared to the first quarter of ~~2019 primarily due to lower storage revenues~~2020. Gross operating margin from our refined products ~~terminal in Beaumont, Texas. Terminaling~~marketing activities increased $28.2 million quarter-to-quarter primarily due to higher sales volumes, ~~at Beaumont decreased~~which accounted for a ~~net 36 MBPD quarter-to-quarter.~~$34.9 million increase, partially offset by lower average sales margins (including the impact of hedging activities), which accounted for a $6.6 million decrease.

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~~Marine transportation~~Ethylene exports and other services

Gross operating margin from ~~marine transportation~~ethylene exports and other services ~~during~~for the first quarter of ~~2020~~2021 decreased ~~$0.4~~a net $3.2 million when compared to the first quarter of ~~2019.~~2020. Gross operating margin from ~~our~~ marine transportation ~~business increased $2.1~~decreased $11.4 million quarter-to-quarter primarily due to ~~higher day~~lower fleet utilization rates. Gross operating margin from our ethylene export terminal and its related operations ~~was a $2.7~~increased $8.2 million ~~loss in the first quarter of 2020~~quarter-to-quarter primarily due to ~~operating expenses incurred for the start-up~~higher loading volumes of 6 MBPD (net to our ~~ethylene export terminal, which was placed into limited service in December 2019.~~

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interest).

Liquidity and Capital Resources

Based on current market conditions (as of the filing date of this quarterly report), we believe wethat the Partnership and its consolidated businesses will have sufficient liquidity, cash flow from operations and access to capital markets to fund ~~our~~their capital investments and working capital needs for the reasonably foreseeable future. At March 31, ~~2020,~~2021, we had ~~$7.0~~$5.11 billion of consolidated liquidity, which was comprised of ~~$5.0~~$4.88 billion of available borrowing capacity under EPO’s revolving credit facilities and ~~$2.0~~ b~~illion~~$229.4 million of unrestricted cash on hand. ~~On April 3, 2020, our liquidity position was enhanced when EPO entered into its April 2020 364-Day Credit Agreement, which provides EPO with an incremental $1.0 billion of borrowing capacity (see “Other Recent Developments” within this Item 2). EPO’s aggregate borrowing capacity under its revolving credit facilities, including that of the April 2020 364-Day Credit Agreement, is now $6.0 billion.~~

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

~~Common Unit Buyback Program~~Enterprise Declares Cash Distribution for First Quarter of 2021

~~EPD repurchased 6,357,739~~ On April 8, 2021, we announced that the Board declared a quarterly cash distribution of $0.45 per common ~~units under its 2019~~ ~~Buyback Program through open market purchases in~~unit, or $1.80 per unit on an annualized basis, to be paid to the Partnership’s common unitholders with respect to the first quarter of ~~2020.~~2021. The quarterly distribution is payable on May 12, 2021 to unitholders of record as of the close of business on April 30, 2021. The total ~~purchase price~~amount to be paid is $991.5 million, which includes $8.1 million for distribution equivalent rights on phantom unit awards.

The payment of ~~these repurchases (including commissions and fees) was $140.1~~ ~~million, and represented 1.9~~%quarterly cash distribution is subject to management’s evaluation of our ~~consolidated CFFO for the twelve months ended March 31, 2020. The repurchased units were cancelled immediately upon acquisition. As~~financial condition, results of ~~March 31, 2020, the remaining available capacity under the 2019 Buyback Program was $1.78 billion.~~

operations and cash flows in connection with such payments and Board approval. In ~~addition to the 2019 Buyback Program, privately held affiliates~~light of ~~EPCO acquired 1,459,000 of EPD’s common units~~current economic conditions, management will evaluate any future increases in cash distributions on ~~the open market during the first quarter of 2020. In the aggregate, 7,816,739~~ ~~common units were purchased on the open market during the first quarter of 2020 under the 2019 Buyback Program and by privately held affiliates of EPCO.~~a quarterly basis.

Consolidated Debt

At March 31, 2021, the average maturity of EPO’s consolidated debt obligations was approximately 21 years. The following table presents the scheduled maturities of ~~our~~principal amounts of EPO’s consolidated debt obligations ~~outstanding~~ at March 31, ~~2020~~2021 for the years indicated (dollars in millions):

			Scheduled Maturities of Debt
	Total		Remainder of 2021		2022		2023		2024		2025		Thereafter
Commercial Paper Notes	$	115.0	$	115.0	$	–	$	–	$	–	$	–	$	–
Senior Notes		26,175.0		–		1,400.0		1,250.0		850.0		1,150.0		21,525.0
Junior Subordinated Notes		2,646.4		–		–		–		–		–		2,646.4
Total	$	28,936.4	$	115.0	$	1,400.0	$	1,250.0	$	850.0	$	1,150.0	$	24,171.4

~~At March 31, 2020, there were no borrowings outstanding under EPO’s revolving credit facilities.~~

~~As discussed under “Other Recent Developments” within this Item 2,~~In February 2021, EPO ~~issued $3.0 billion aggregate~~repaid all of the $750.0 million in principal amount of ~~senior notes in January 2020. The net proceeds from this debt offering were used (i)~~its Senior Notes TT using remaining cash on hand attributable to repay $500 million principal amount of senior notes maturing in January 2020, (ii) for the temporary repayment of amounts outstanding under EPO’s commercial paper program and (iii) for general company purposes. In addition, net proceeds from the Januaryits August 2020 senior notes offering ~~will be used for~~and proceeds from the ~~repayment~~issuance of ~~$1.0 billion~~short-term notes under its commercial paper program.

In March 2021, EPO redeemed all of the $575.0 million outstanding principal amount of ~~senior~~its Senior Notes RR one month prior to their scheduled maturity in April 2021. These notes ~~maturing in September 2020.~~were redeemed at par (i.e., at a redemption price equal to the outstanding principal amount of such notes to be redeemed, plus accrued and unpaid interest thereon) using proceeds from the issuance of short-term notes under its commercial paper program.

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

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Credit Ratings

As of May ~~8, 2020,~~7, 2021, the investment-grade credit ratings of EPO’s long-term senior unsecured debt securities were BBB+ from Standard and Poor’s, Baa1 from Moody’s and BBB+ from Fitch Ratings. In addition, the credit ratings of EPO’s short-term senior unsecured debt securities were A-2 from Standard and Poor’s, P-2 from Moody’s and F-2 from Fitch Ratings. EPO’s credit ratings reflect only the view of a rating agency and should not be interpreted as a recommendation to buy, sell or hold any of our securities. A credit rating can be revised upward or downward or withdrawn at any time by a rating agency, if it determines that circumstances warrant such a change. A credit rating from one rating agency should be evaluated independently of credit ratings from other rating agencies.

~~Issuance of~~ Common ~~Units~~Unit Repurchases Under 2019 Buyback Program

~~On March 5, 2020,~~In January 2019, we settled our obligations under the Liquidity Option Agreement. As a result, EPD issued 54,807,352 of its common units to Skyline and indirectly reacquired the 54,807,352 EPD common units owned by OTA. For additional information regarding this transaction, see “~~Other Recent Developments – Settlement of Liquidity Option” within this Item 2.~~

~~EPD has registration statements on file with the SEC in connection with its distribution reinvestment plan (“DRIP”) and employee unit purchase plan (“EUPP”). In July 2019, EPD~~ announced that ~~beginning~~the Board had approved a $2.0 billion multi-year unit buyback program (the “2019 Buyback Program”), which provides the Partnership with ~~the quarterly distribution payment paid in August 2019, it would use common units purchased on the open market, rather than issuing new common units,~~an additional method to ~~satisfy its delivery obligations under the DRIP and EUPP. This election is subject~~return capital to ~~change in future quarters depending on the partnership’s need for equity capital. In February 2020, a total of 1,422,063~~ ~~common units were purchased on the open market and delivered to participants in connection with the DRIP and EUPP. Apart from $0.5~~ ~~million~~ attributable to the plan discount available to all participants in the EUPP, the funds used to effect these purchases were sourced from the DRIP and EUPP participants. No other partnership funds were used to satisfy these obligations. We plan to use open market purchases to satisfy DRIP and EUPP reinvestments in connection with the distribution expected to be paid on May 12, 2020.

~~EPD issued and delivered a combined 1,516,779 common units in~~investors. During the first quarter of 2021, the Partnership settled open market repurchase transactions initiated in December 2020 involving an aggregate 709,816 common units. The total cost of these repurchases was $13.9 million including commissions and fees. As of March 31, 2021, the remaining available capacity under the 2019 ~~in connection with the DRIP and EUPP, which generated net cash proceeds totaling $42.7 million.~~

~~Cash Distributions~~

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Buyback Program was $1.72 billion.

Cash Flow Statement Highlights

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

	For the Three Months Ended March 31,					For the Three Months Ended March 31,
	2020		2019			2021				2020
Net cash flows provided by operating activities	$	2,012.2	$	1,160.4			$	2,023.1			$	2,012.2
Cash used in investing activities		1,071.7		1,174.5				657.0				1,071.7
Cash provided by (used in) financing activities		765.1		(288.5	)			(2,189.8	)			765.1

Net cash flows provided by operating activities are largely dependent on earnings from our consolidated business activities. Changes in energy commodity prices may impact the demand for natural gas, NGLs, crude oil, petrochemical and refined products, which could impact sales of our products and the demand for our midstream services. Changes in demand for our products and services may be caused by other factors, including prevailing economic conditions, reduced demand by consumers for the end products made with hydrocarbon products, increased competition, public health emergencies, adverse weather conditions and government regulations affecting prices and production levels. We may also incur credit and price risk to the extent customers do not fulfill their contractual obligations to us in connection with our marketing activities and long-term take-or-pay agreements. For a more complete discussion of these and other risk factors, ~~pertinent to our business,~~ see “Risk Factors” included under Part I, Item 1A of the ~~2019~~2020 Form ~~10-K and~~10-K.

For additional information regarding our cash flow amounts, please refer to our Unaudited Condensed Statements of Consolidated Cash Flows included under Part ~~II,~~I, Item 1A1 of this quarterly report.

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

Operating activities

Net cash flows provided by operating activities for the first quarter of ~~2020~~2021 increased a net $~~851.8~~$10.9 million when compared to the first quarter of ~~2019~~2020 primarily due to:

a ~~$901.5~~$362.7 million quarter-to-quarter increase ~~primarily due~~in cash related to the timing of cash receipts and payments related to operations; and

a $268.6 million quarter-to-quarter increase resulting from higher partnership earnings (determined by adjusting our $12.4 million quarter-to-quarter decrease in net income for changes in the non-cash items identified on our Unaudited Condensed Statements of Consolidated Cash Flows); partially offset by

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•

~~a $37.6~~ million quarter-to-quarter decrease resulting from lower partnership earnings in the first quarter of 2020 when compared to the first quarter of 2019 (determined by adjusting our $94.6 million quarter-to-quarter increase in net income for changes in the non-cash items identified on our Unaudited Condensed Statements of Consolidated Cash Flows).

a $605.4 million quarter-to-quarter decrease in cash receipts attributable to the return of working capital employed in our marketing activities, which was $638.4 million in the first quarter of 2020 compared to $33.0 million in the first quarter of 2021.

For information regarding significant quarter-to-quarter changes in our consolidated net income and underlying segment results, see “Income Statement Highlights” and “Business Segment Highlights” within this Part I, Item 2.

Investing activities

Cash used in investing activities ~~for~~during the first quarter of ~~2020~~2021 decreased ~~a net $102.8 million~~$414.7 million when compared to the first quarter of ~~2019~~2020 primarily due ~~to:~~

•

~~a $69.4 million quarter-to-quarter decrease in expenditures for consolidated property, plant and equipment (see “Capital Investments” within this Part I, Item 2 for additional information); and~~

to a ~~$25.8~~$400.5 million quarter-to-quarter decrease in investments ~~in unconsolidated affiliates primarily related to NGL~~for property, plant and ~~crude oil pipeline projects.~~

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equipment (see “Capital Investments” within this Part I, Item 2 for additional information).

Financing activities

Cash used in financing activities during the first quarter of 2021 was $2.19 billion compared to cash provided by financing activities ~~for~~of $765.1 million in the first quarter of 2020. The $2.95 billion quarter-to-quarter change in financing cash flows was primarily due to a net cash outflow of $1.13 billion related to debt during the first quarter of 2021 compared to a net cash inflow of $1.94 billion related to debt during the first quarter of 2020. During the first quarter of 2021, we repaid $1.33 billion aggregate principal amount of senior notes. During the first quarter of 2020, ~~was $765.1~~we issued $3.0 billion aggregate principal amount of senior notes, partially offset by the repayment of $500 million ~~compared to cash used in financing activities~~principal amount of $~~288.5 million in~~senior notes. In addition, net issuances of short term notes under EPO’s commercial paper program were $115.0 million during the first quarter of ~~2019. The $1.05 billion quarter-to-quarter change in~~2021 compared to net repayments of $481.8 million during the first quarter of 2020. In addition, cash ~~flow from financing activities was primarily due to:~~

•

a net $1.25 billion quarter-to-quarter increase in net cash inflows attributable to debt. During the first quarter of 2020, we issued $3.0 billion aggregate principal amount of senior notes, partially offset by the repayment of $500 million principal amount of senior notes. During the first quarter of 2019, we repaid $700 million principal amount of senior notes. In addition, net repayments of short term notes under EPO’s commercial paper program were $481.7 million in the first quarter of 2020 compared to net issuances of $1.39 billion in first quarter of 2019~~; partially offset by~~

•

~~an $88.5~~ ~~million quarter-to-quarter increase in cash used to acquire~~ ~~common units under our 2019 Buyback Program;~~

•

a $~~42.7~~ million quarter-to-quarter decrease in net cash proceeds from the issuance of common units in connection with the DRIP and EUPP. As noted previously, EPD announced in July 2019 that, beginning with the quarterly distribution payment paid in August 2019, it would use common units purchased on the open market, rather than issuing new common units, to satisfy its delivery obligations under the DRIP and EUPP;

•

~~a $29.6~~ ~~million quarter-to-quarter decrease in cash contributions from noncontrolling interests.~~ C~~ash contributions from noncontrolling interests in connection with the construction of our ethylene export facility decreased $31.5 million quarter-to-quarter; and~~

•

~~a $23.8~~ ~~million quarter-to-quarter increase in cash distributions paid to limited partners primarily due to an increase in the quarterly cash distribution rate per unit.~~

used to acquire Partnership common units under the 2019 Buyback Program decreased $126.2 million quarter-to-quarter.

Non-GAAP Cash Flow Measures

Distributable Cash Flow

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

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

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

Our use of DCF for the limited purposes described above and in this quarterly report is not a substitute for net cash flows provided by operating activities, which is the most comparable GAAP ~~measure.~~measure to DCF. For a discussion of net cash flows provided by operating activities, see “Cash Flow Statement Highlights” within this Part I, Item 2.

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

	For the Three Months Ended March 31,						For the Three Months Ended March 31,
	2020			2019			2021			2020
Net income attributable to limited partners (GAAP) (1)	$	1,350.1		$	1,260.5
Adjustments to net income attributable to limited partners to derive DCF (addition or subtraction indicated by sign):
Net income attributable to common unitholders (GAAP) (1)							$	1,340.4		$	1,350.1
Adjustments to net income attributable to common unitholders to derive DCF (addition or subtraction indicated by sign):
Depreciation, amortization and accretion expenses		509.0			474.5			525.0			509.0
Cash distributions received from unconsolidated affiliates (2)		137.2			143.5			130.5			137.2
Equity in income of unconsolidated affiliates		(140.8	)		(154.6	)		(148.9	)		(140.8	)
Asset impairment charges								65.6			1.6
Change in fair market value of derivative instruments		(29.5	)		(96.3	)		(15.6	)		(29.5	)
Change in fair value of Liquidity Option		2.3			57.8			–			2.3
Deferred income tax expense (benefit)		(184.1	)		1.8			4.6			(184.1	)
Sustaining capital expenditures (3)		(68.9	)		(61.6	)		(143.8	)		(68.9	)
Other, net		11.0			1.1
Subtotal DCF, before proceeds from asset sales and monetization of interest rate derivative instruments accounted for as cash flow hedges		1,586.3			1,626.7
Other, net (4)								(101.9	)		9.4
Operational DCF (5)							$	1,655.9		$	1,586.3
Proceeds from asset sales		0.6			1.7			6.2			0.6
Monetization of interest rate derivative instruments accounted for as cash flow hedges		(33.3	)		–			75.2			(33.3	)
DCF (non-GAAP)	$	1,553.6		$	1,628.4		$	1,737.3		$	1,553.6

Cash distributions paid to limited partners with respect to period	$	979.9		$	963.5
Cash distributions paid to common unitholders with respect to period, including distribution equivalent rights on phantom unit awards							$	991.5		$	979.8

Cash distribution per unit declared by Enterprise GP with respect to period (4)	$	0.4450		$	0.4375
Cash distribution per common unit declared by Enterprise GP with respect to period (6)							$	0.4500		$	0.4450

Total DCF retained by partnership with respect to period (5)	$	573.7		$	664.9
Total DCF retained by the Partnership with respect to period (7)							$	745.8		$	573.8

Distribution coverage ratio (6)		1.6	x		1.7	x
Distribution coverage ratio (8)								1.8	x		1.6	x

(1)	For a discussion of the primary drivers of changes in our comparative income statement amounts, see “Income Statement Highlights” within this Part I, Item 2.
(2)	Reflects aggregate distributions received from unconsolidated affiliates attributable to both earnings and the return of capital.
(3)	Sustaining capital expenditures include cash payments and accruals applicable to the period.
(4)	First quarter of 2021 includes $107.0 million of accounts receivable that we do not expect to collect in the normal billing cycle.
(5)	Represents DCF before proceeds from asset sales and the monetization of interest rate derivative instruments accounted for as cash flow hedges.
(6)	See Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 21 of this quarterly report for ~~additional~~ information regarding our ~~quarterly~~ cash distributions declared with respect to the ~~years~~periods indicated.
~~(5)~~(7)	~~At the sole discretion of Enterprise GP, cash~~Cash retained by the ~~partnership with respect to each of these periods was primarily reinvested in growth~~Partnership may be used for capital ~~projects.~~ ~~This retainage~~investments, debt service, working capital, operating expenses, common unit repurchases, commitments and contingencies and other amounts. The retention of cash ~~substantially reduced~~reduces our reliance on the ~~equity~~ capital ~~markets to fund such expenditures.~~ markets.
~~(6)~~(8)	Distribution coverage ratio is determined by dividing DCF by total cash distributions paid to ~~limited partners~~common unitholders and in connection with distribution equivalent rights with respect to the period.

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

For the Three Months
Ended March 31,

2020 2019
Net cash flows provided by operating activities (GAAP) $ 2,012.2 $ 1,160.4
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 (341.7 ) 559.8
      Sustaining capital expenditures (68.9 ) (61.6 )
      Distributions received from unconsolidated affiliates attributable to the return of capital 10.3 4.5
      Proceeds from asset sales 0.6 1.7
      Net income attributable to noncontrolling interest (24.9 ) (19.9 )
      Monetization of interest rate derivative instruments accounted for as cash flow hedges (33.3 ) –
      Other, net (0.7 ) (16.5 )
DCF (non-GAAP) $ 1,553.6 $ 1,628.4

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	For the Three Months Ended March 31,
	2021			2020
Net cash flows provided by operating activities (GAAP)	$	2,023.1		$	2,012.2
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		(99.0	)		(341.7	)
Sustaining capital expenditures		(143.8	)		(68.9	)
Distributions received from unconsolidated affiliates attributable to the return of capital		18.6			10.3
Proceeds from asset sales		6.2			0.6
Net income attributable to noncontrolling interests		(21.3	)		(24.9	)
Monetization of interest rate derivative instruments accounted for as cash flow hedges		75.2			(33.3	)
Other, net		(121.7	)		(0.7	)
DCF (non-GAAP)	$	1,737.3		$	1,553.6

Free Cash Flow

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

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

Our use of FCF for the limited purposes described above and in this report is not a substitute for net cash flows provided by operating activities, which is the most comparable GAAP ~~measure.~~measure to FCF.

FCF fluctuates quarter-to-quarter based on ~~our~~a number of factors including earnings, the level of investing activities, ~~we undertake each period, and~~ the timing of operating cash receipts and payments. In addition to providing the quarterly amounts presented below, we also provide a calculation of aggregate FCF over the twelve months ended March 31, 2020 in order to measure FCF over a longer term.payments, and contributions from noncontrolling interests. The following table summarizes our calculation of FCF for the periods indicated (dollars in millions):

	For the Three Months Ended March 31,						For the Twelve Months Ended March 31,			For the Three Months Ended March 31,
	2020			2019			2020			2021			2020
Net cash flows provided by operating activities (GAAP)	$	2,012.2		$	1,160.4		$	7,372.3		$	2,023.1		$	2,012.2
Adjustments to net cash flows provided by operating activities to derive FCF (addition or subtraction indicated by sign):
Cash used in investing activities		(1,071.7	)		(1,174.5	)		(4,472.7	)		(657.0	)		(1,071.7	)
Cash contributions from noncontrolling interests		5.2			34.8			603.2			13.1			5.2
Cash distributions paid to noncontrolling interests		(29.9	)		(18.0	)		(118.1	)		(29.8	)		(29.9	)
FCF (non-GAAP)	$	915.8		$	2.7		$	3,384.7		$	1,349.4		$	915.8

The elements used in calculating FCF are sourced directly from our Unaudited Condensed Statements of Consolidated Cash Flows presented under Part I, Item 1 of this quarterly report. For a discussion of ~~primary drivers of~~significant quarter-to-quarter changes in our ~~quarterly net~~ cash ~~flows provided by operating activities and cash used in investing activities,~~flow statement amounts, see “Cash Flow Statement Highlights” within this Part I, Item 2.

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Capital Investments

As previously discussed, capital investing activity throughout the domestic energy industry is being significantly reduced in response to the demand and supply disruptions attributable to COVID-19 and the oil price shock. We, along with many other midstream energy companies, have reviewedThe following table summarizes our ~~planned~~ capital investments for the periods indicated (dollars in ~~light~~millions):

	For the Three Months Ended March 31,
	2021		2020

Capital investments for property, plant and equipment: (1)
Growth capital projects (2)	$	573.5	$	1,006.5
Sustaining capital projects (3)		105.5		73.0
Total	$	679.0	$	1,079.5

Investments in unconsolidated affiliates	$	1.3	$	3.3

(1)	Growth and sustaining capital amounts are presented on a cash basis. In total, these amounts represent “Capital expenditures” as presented on our Unaudited Condensed Statements of Consolidated Cash Flows.
(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 projects 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. Sustaining capital amounts include the costs of major maintenance activities accounted for using the deferral method.

We currently have $3.6 billion of ~~these adverse macroeconomic events.~~growth capital projects scheduled to be completed by the end of 2023, which includes completion of a natural gasoline hydrotreater facility at our Chambers County complex in the fourth quarter of 2021, the Gillis Lateral natural gas pipeline and related infrastructure in the fourth quarter of 2021, and our PDH 2 facility in the second quarter of 2023.

~~As previously noted and based~~Based on information currently available, we ~~now~~ expect our total capital investments for ~~2020~~2021, net of expected contributions from noncontrolling interests, to approximate ~~$2.8~~$2.1 billion, ~~to $3.3 billion (previously $3.4 billion to $4.4 billion),~~ which reflects growth capital investments of ~~$2.5~~$1.6 billion ~~to $3.0 billion (previously $3.0 billion to $4.0 billion)~~ and ~~approximately $300 million for~~ sustaining capital expenditures ~~(previously $400 million). Based on sanctioned projects,~~of $440 million. In addition, we currently expect our growth capital investments in 2022 and 2023 for ~~2021 and 2022~~sanctioned projects to approximate ~~$2.5 billion~~$800 million and ~~$1.5 billion,~~$400 million, respectively. These amounts do not include capital investments associated with SPOT, our proposed deepwater offshore crude oil terminal, which remains subject to governmental approvals. We currently anticipate receiving approval for SPOT as early as the second half of 2021; however, we can give no assurance as to whether the project will ultimately be approved or the timing of such decision.

Our ~~revised~~ forecast of capital investments for ~~2020~~2021 through 2023 is based on announced strategic operating and growth plans (through the filing date of this quarterly report), which are dependent upon our ability to generate the required funds from either operating cash flows or other means, including borrowings under debt agreements, the issuance of additional equity and debt securities, and potential divestitures. We may revise our forecast of capital investments due to factors beyond our control, such as adverse economic conditions, weather-related issues and changes in supplier prices. Furthermore, our forecast of capital investments may change due to decisions made by management at a later date, which may include unforeseen acquisition opportunities.

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

We placed a tenth NGL fractionator (“Frac X”) located in Chambers County, Texas into service in the first quarter of 2020. In addition, expansion projects on our Texas Express Pipeline and Front Range Pipeline were placed into commercial service in April 2020. We currently have $6.9 billion of growth capital projects scheduled to be completed by the end of 2023 including the following major projects:

~~an eleventh NGL fractionator in Chambers County, Texas (“Frac XI,” third quarter of 2020);~~

~~components of our Midland-to-ECHO System (third quarter of 2020 into 2021);~~

~~expansion of our natural gas pipeline network in northeast Texas in support of our Carthage natural gas processing facilities (fourth quarter of 2020);~~

~~completion of the Baymark ethylene pipeline in South Texas (fourth quarter of 2020);~~

~~expansion of our ethylene export capabilities at Morgan’s Point (fourth quarter of 2020);~~

~~expansion and extension of Acadian Gas System (Gillis Lateral and related projects) (fourth quarter of 2021);~~

~~an eighth deep-water ship dock at EHT for loading crude oil (fourth quarter of 2021); and~~

~~construction of our PDH 2 facility (second quarter of 2023).~~

~~The following table summarizes our capital investments for the periods indicated (dollars in millions):~~

For the Three Months
Ended March 31,

2020 2019
Capital investments for property, plant and equipment: (1)

   Growth capital projects (2) $ 1,006.5 $ 1,077.4
   Sustaining capital projects (3) 73.0 71.5
   Total $ 1,079.5 $ 1,148.9

Investments in unconsolidated affiliates $ 3.3 $ 29.1

~~(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.

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Comparison of ~~Three Months Ended March 31,~~First Quarter of 2021 with the First Quarter of 2020 ~~with Three Months Ended March 31, 2019~~

Fluctuations in investments attributable to our growth capital projects and those of our unconsolidated affiliates are explained in large part by increases or decreases in the funding of announced major expansion projects. Fluctuations in investments attributable to sustaining capital projects are primarily due to the timing and cost of pipeline integrity and similar projects.

In total, investments in growth capital projects decreased ~~$70.9~~$433.0 million quarter-to-quarter primarily due to the ~~following (all of which occurred since the first quarter of 2019):~~following:

completion of projects at our Chambers County complex (e.g., the ~~Shin Oak NGL Pipeline,~~completion of Frac X and Frac XI), which accounted for a ~~$154.8~~$193.4 million decrease;

completion of projects associated with crude oil pipelines (e.g., expansion projects involving the Midland-to-ECHO System and related crude oil-related infrastructure supporting Permian Basin producers), which accounted for a combined $121.4 million decrease;

lower investments in Permian Basin natural gas processing facilities and related infrastructure, ~~that support Permian Basin production,~~ which accounted for ~~an additional $114.6~~a $52.4 million ~~decrease. We completed the last phase of our Orla plant in July 2019 and placed our Mentone I plant into service in December 2019; partially offset by,~~

decrease;

~~higher~~lower investments in ~~crude oil pipelines, including those comprising~~projects attributable to our ~~Midland-to-ECHO System, and related infrastructure that support Permian Basin production,~~ethylene business, which accounted for ~~an overall $96.9~~a $26.7 million ~~increase;~~

decrease; and,

~~higher~~lower investments in natural gas pipelines and related infrastructure in support of East Texas and Louisiana ~~production,~~producers, which accounted for a ~~$48.5~~net $25.1 million ~~increase; and~~

~~higher investments in propylene production, NGL fractionation and other related plant assets and infrastructure at our Mont Belvieu complex, which accounted for a combined $42.3 million increase.~~

decrease.

Investments ~~in our unconsolidated affiliates decreased $25.8~~attributable to sustaining capital projects increased $32.5 million quarter-to-quarter primarily due to ~~lower spending on~~major maintenance activities performed during the first quarter of 2021 at our ~~Texas Express Pipeline expansion project, which accounted for a $10.5 million decrease,~~PDH 1, octane enhancement and ~~lower spending on our joint venture dock infrastructure at Corpus Christi, which accounted for an additional $8.2 million decrease.~~high purity isobutylene facilities. The remaining change is primarily due to changes in the timing and cost of pipeline integrity and similar projects.

Critical Accounting Policies and Estimates

A discussion of our critical accounting policies and estimates is included in our ~~2019~~2020 Form 10-K. The following types of estimates, in our opinion, are subjective in nature, require the exercise of professional judgment and involve complex analysis:

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

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

valuation and amortization methods of customer relationships and contract-based intangible assets;

~~amortization methods and estimated useful lives of qualifying intangible assets;~~

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

related assets; and

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

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

Other Items

Parent-Subsidiary Guarantor Relationship

The Partnership (the “Parent Guarantor”) has guaranteed the payment of principal and interest on the consolidated debt obligations of EPO (the “Subsidiary Issuer”), with the exception of the remaining debt obligations of TEPPCO Partners, L.P. (collectively, the “Guaranteed Debt”). If EPO were to default on any of its Guaranteed Debt, the Partnership would be responsible for full and unconditional repayment of such obligations. At March 31, 2021, the total amount of Guaranteed Debt was $29.15 billion, which was comprised of $26.18 billion of EPO’s senior notes, $115.0 million of short-term commercial paper notes, $2.63 billion of EPO’s junior subordinated notes and $224.2 million of related accrued interest.

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~~Other Items~~The Partnership’s guarantees of EPO’s senior note obligations, commercial paper notes and borrowings under bank credit facilities represent unsecured and unsubordinated obligations of the Partnership that rank equal in right of payment to all other existing or future unsecured and unsubordinated indebtedness of the Partnership. In addition, these guarantees effectively rank junior in right of payment to any existing or future indebtedness of the Partnership that is secured and unsubordinated, to the extent of the assets securing such indebtedness.

The Partnership’s guarantees of EPO’s junior subordinated notes represent unsecured and subordinated obligations of the Partnership that rank equal in right of payment to all other existing or future subordinated indebtedness of the Partnership and senior in right of payment to all existing or future equity securities of the Partnership. The Partnership’s guarantees of EPO’s junior subordinated notes effectively rank junior in right of payment to (i) any existing or future indebtedness of the Partnership that is secured, to the extent of the assets securing such indebtedness and (ii) all other existing or future unsecured and unsubordinated indebtedness of the Partnership.

The Partnership may be released from its guarantee obligations only in connection with EPO’s exercise of its legal or covenant defeasance options as described in the underlying agreements.

Selected Financial Information of Obligor Group

The following tables present summarized financial information of the Partnership (as Parent Guarantor) and EPO (as Subsidiary Issuer) on a combined basis (collectively, the “Obligor Group”), after the elimination of intercompany balances and transactions among the Obligor Group.

In accordance with Rule 13.01 of Regulation S-X, the summarized financial information of the Obligor Group excludes the Obligor Group’s equity in income and investments in the consolidated subsidiaries of EPO that are not party to the guarantee obligations (the “Non-Obligor Subsidiaries”). The total carrying value of the Obligor Group’s investments in the Non-Obligor Subsidiaries was $45.86 billion at March 31, 2021. The Obligor Group’s equity in the earnings of the Non-Obligor Subsidiaries for the first quarter of 2021 was $878.0 million. Although the net assets and earnings of the Non-Obligor Subsidiaries are not directly available to the holders of the Guaranteed Debt to satisfy the repayment of such obligations, there are no significant restrictions on the ability of the Non-Obligor Subsidiaries to pay distributions or make loans to EPO or the Partnership. EPO exercises control over the Non-Obligor Subsidiaries. We continue to believe that the unaudited condensed consolidated financial statements of the Partnership presented under Part I, Item 1 of this quarterly report provide a more appropriate view of our credit standing. Our investment grade credit ratings are based on the Partnership’s consolidated financial statements and not the Obligor Group financial information presented below.

The following table presents summarized balance sheet information for the combined Obligor Group at the dates indicated (dollars in millions):

Selected asset information:	March 31, 2021		December 31, 2020
Current receivables from Non-Obligor Subsidiaries	$	1,346.9	$	775.4
Other current assets		5,590.3		5,805.7
Long-term receivables from Non-Obligor Subsidiaries		187.3		187.3
Other noncurrent assets, excluding investments in Non-Obligor Subsidiaries of $45.86 billion at March 31, 2021 and $45.98 billion at December 31, 2020		8,456.2		8,198.5

Selected liability information:
Current portion of Guaranteed Debt, including interest of $224.2 million at March 31, 2021 and $455.6 million at December 31, 2020	$	1,737.5	$	1,780.6
Current payables to Non-Obligor Subsidiaries		1,617.8		1,129.0
Other current liabilities		4,611.7		3,858.6
Noncurrent portion of Guaranteed Debt, principal only		27,406.8		28,806.8
Noncurrent payables to Non-Obligor Subsidiaries		27.0		27.0
Other noncurrent liabilities		54.0		42.9

Mezzanine equity of Obligor Group:
Preferred units	$	49.3	$	49.3

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The following table presents summarized income statement information for the combined Obligor Group for the periods indicated (dollars in millions):

	For the three months ended March 31, 2021		For the twelve months ended December 31, 2020
Revenues from Non-Obligor Subsidiaries	$	3,365.1	$	2,602.4
Revenues from other sources		3,423.5		15,361.4
Operating income of Obligor Group		799.3		1,069.7
Net income (loss) of Obligor Group excluding equity in earnings of Non-Obligor Subsidiaries of $878.0 million for the three months ended March 31, 2021 and $3.54 billion for the twelve months ended December 31, 2020		461.9		(157.0	)

Contractual Obligations

~~The principal amount of our consolidated debt obligations were~~ ~~$29.90~~$19.34 billion at March 31, ~~2020 compared~~2021 primarily due to ~~$27.88 billion at December 31, 2019. See “Other Recent Developments” within this Item 2 for information regarding EPO’s senior notes offering~~an increase in ~~January 2020~~crude oil and NGL prices between the ~~related use of proceeds.~~two reporting dates.

Off-Balance Sheet Arrangements

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

Related Party Transactions

For information regarding our related party transactions, see Note 1514 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES

ABOUT MARKET RISK.

General

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

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

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

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

the hedged forecasted transaction occurs within the expected time period.

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

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

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Commodity Hedging Activities

The ~~prices~~price of energy commodities such as 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.

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

Volume (1) Accounting
Derivative Purpose
Current (2)
Long-Term (2)
Treatment
Derivatives designated as hedging instruments:
Natural gas processing:
Forecasted natural gas purchases for plant thermal reduction (Bcf) 11.9 n/a Cash flow hedge
Octane enhancement:
Forecasted purchase of NGLs (MMBbls) 0.7 n/a Cash flow hedge
Forecasted sales of octane enhancement products (MMBbls) 13.6 n/a Cash flow hedge
Natural gas marketing:
Forecasted purchase of natural gas (Bcf) 4.5 n/a Cash flow hedge
Natural gas storage inventory management activities (Bcf) 4.4 n/a Fair value hedge
NGL marketing:
Forecasted purchases of NGLs and related hydrocarbon products (MMBbls) 126.3 0.4 Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products (MMBbls) 140.0 2.2 Cash flow hedge
NGLs inventory management activities (MMBbls) 0.8 n/a Fair value hedge
Refined products marketing:
Forecasted purchases of refined products (MMBbls) 5.1 n/a Cash flow hedge
Forecasted sales of refined products (MMBbls) 6.8 n/a Cash flow hedge
Refined products inventory management activities (MMBbls) 0.5 n/a Fair value hedge
Crude oil marketing:
Forecasted purchases of crude oil (MMBbls) 24.5 n/a Cash flow hedge
Forecasted sales of crude oil (MMBbls) 31.4 n/a Cash flow hedge
Propylene marketing:
Forecasted sales of NGLs for propylene marketing activities (MMBbls) 0.6 n/a Cash flow hedge
Commercial energy:
Forecasted purchases of power related to asset operations (terawatt hours (“TWh”)) 0.2 n/a Cash flow hedge
Derivatives not designated as hedging instruments:
Natural gas risk management activities (Bcf) (3) 54.5 0.3 Mark-to-market
NGL risk management activities (MMBbls) (3) 15.7 n/a Mark-to-market
Refined products risk management activities (MMBbls) (3) 5.1 n/a Mark-to-market
Crude oil risk management activities (MMBbls) (3) 33.9 9.0 Mark-to-market
Commercial energy risk management activities (TWh) (3) 0.1 n/a 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 2021, December 2020 and December 2022, respectively.
~~(3)~~	~~Reflects the use of derivative instruments to manage risks associated with transportation, processing, storage assets and end use power requirements.~~

At March 31, ~~2020,~~2021, 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 the fair value of commodity products held in inventory and (iii) hedging natural gas processing margins.

~~Table~~For a summary of ~~Contents~~

our portfolio of commodity derivative instruments outstanding, see Note 13 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

Sensitivity Analysis

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

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

Natural gas marketing portfolio

		Portfolio Fair Value at											Portfolio Fair Value at
Scenario	Resulting Classification	December 31, 2019				March 31, 2020			April 15, 2020			Resulting Classification	December 31, 2020			March 31, 2021			April 15, 2021
Fair value assuming no change in underlying commodity prices	Asset (Liability)		$	1.1			$	28.8		$	31.5	Asset (Liability)		$	3.7		$	2.8		$	2.2
Fair value assuming 10% increase in underlying commodity prices	Asset (Liability)			(4.3	)			24.9			27.7	Asset (Liability)			2.6			2.1			1.6
Fair value assuming 10% decrease in underlying commodity prices	Asset (Liability)			6.6				32.8			35.2	Asset (Liability)			4.9			3.5			2.9

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

		Portfolio Fair Value at											Portfolio Fair Value at
Scenario	Resulting Classification	December 31, 2019				March 31, 2020			April 15, 2020			Resulting Classification	December 31, 2020				March 31, 2021				April 15, 2021
Fair value assuming no change in underlying commodity prices	Asset (Liability)		$	43.7			$	119.8		$	86.5	Asset (Liability)		$	(388.2	)		$	(70.4	)		$	(151.6	)
Fair value assuming 10% increase in underlying commodity prices	Asset (Liability)			(19.0	)			85.6			51.3	Asset (Liability)			(521.0	)			(101.8	)			(186.8	)
Fair value assuming 10% decrease in underlying commodity prices	Asset (Liability)			106.4				154.0			121.7	Asset (Liability)			(255.4	)			(39.0	)			(116.4	)

Crude oil marketing portfolio

Portfolio Fair Value at
Scenario
Resulting
Classification
December 31,
2019

March 31,
2020

April 15,
2020

Fair value assuming no change in underlying commodity prices Asset (Liability) $ (9.6 ) $ 122.5 $ 125.7
Fair value assuming 10% increase in underlying commodity prices Asset (Liability) (50.6 ) 103.1 106.7
Fair value assuming 10% decrease in underlying commodity prices Asset (Liability) 31.5 142.0 144.7

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		Portfolio Fair Value at
Scenario	Resulting Classification	December 31, 2020				March 31, 2021				April 15, 2021
Fair value assuming no change in underlying commodity prices	Asset (Liability)		$	(184.3	)		$	(273.1	)		$	(333.9	)
Fair value assuming 10% increase in underlying commodity prices	Asset (Liability)			(266.5	)			(354.9	)			(421.5	)
Fair value assuming 10% decrease in underlying commodity prices	Asset (Liability)			(102.1	)			(191.4	)			(246.4	)

Interest Rate Hedging Activities

~~Sensitivity Analysis~~

AtAs a result of market conditions in March ~~31, 2020,~~2021, we terminated our interest rate hedging portfolio consisted of forward-starting swaps. Forward-starting swaps hedge the risk of an increase in underlying benchmark interest rates during the period of time between the inception date of the swap agreement and the future date of a debt issuance. Under the terms of the forward-starting swaps, we pay to the counterparties (at the expected settlement dates of the instruments) amounts based on a fixed interest rate applied to a notional amount and receive from the counterparties an amount equal to a variable interest rate (based on LIBOR or an equivalent index rate) on the same notional amount.

With respect to the tabular data below, the portfolio’s estimated economic value at a given date is based on a number of factors, including the number and types of derivatives outstanding at that date, the notional value of the swaps and associated interest rates. The following table summarizes ourentire portfolio of forward-starting swaps, ~~at March 31, 2020 (dollars~~representing an aggregate $1.08 billion in ~~millions):~~

Hedged Transaction
Number and Type
of Derivatives
Outstanding
Notional
Amount
Expected
Settlement
Date
Weighted-Average
Fixed Rate
Locked
Accounting
Treatment
Future long-term debt offering 1 forward-starting swap $75.0 4/2021 2.41% Cash flow hedge
Future long-term debt offering 5 forward-starting swaps $500.0 4/2021
2.13%
Cash flow hedge
Future long-term debt offering 2 forward-starting swaps (1) $150.0 2/2022 1.72% Cash flow hedge
Future long-term debt offering 1 forward starting swap (1) $100.0 4/2021 1.46% Cash flow hedge
Future long-term debt offering 2 forward starting swaps (1) $150.0 2/2022 1.48% Cash flow hedge
Future long-term debt offering 2 forward starting swaps (1) $100.0 2/2022 0.95% Cash flow hedge

~~(1)~~

~~These swaps were entered into during the first quarter~~notional value. As of ~~2020.~~

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

Forward-Starting Swap
Portfolio Fair Value at

Scenario
Resulting
Classification
December 31,
2019

March 31,
2020

April 15,
2020

Fair value assuming no change in underlying interest rates Asset (Liability) $ (13.5 ) $ (258.3 ) $ (249.2 )
Fair value assuming 10% increase in underlying interest rates Asset (Liability) 38.2 (229.8 ) (220.0 )
Fair value assuming 10% decrease in underlying interest rates Asset (Liability) (68.3 ) (287.6 ) (279.3 )

~~The $235.7 million decrease in the fair value~~filing date of this ~~portfolio from December 31, 2019 to April 15, 2020 was primarily due to declining~~quarterly report, we do not have any interest rates relative to the fixed rates specified in the swap agreements. Upon settlement, we would expect that any loss on these swaps would ultimately be offset by lower interest rates on future debt issuances.rate hedging derivative instruments outstanding.

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ITEM 4. CONTROLS AND PROCEDURES.

Disclosure Controls and Procedures

As of the end of the period covered by this quarterly report, our management carried out an evaluation, with the participation of (i) A. James Teague, Co-Chief Executive Officer of Enterprise GP and (ii) W. Randall Fowler, Co-Chief Executive Officer and Chief Financial Officer of Enterprise GP, of the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 of the Securities Exchange Act of 1934. ~~Mr. Teague is our co-principal executive officer (together with Mr. Fowler) and Mr. Fowler is our other co-principal executive officer and our principal financial officer.~~ Based on this evaluation, as of the end of the period covered by this quarterly report, Messrs. Teague and Fowler concluded:

(i)

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

(ii)	that our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

There were no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) during the first quarter of ~~2020,~~2021, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

The containment measures enacted by local, state and national governmental authorities in response to COVID-19 have had minimal impact on our internal controls over financial reporting to date. As a result of prior emergency planning efforts, we had effective processes in place that ensured the continuity of our operations, including our accounting, risk control and information technology functions.

Section 302 and 906 Certifications

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

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

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

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

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ITEM 1A. RISK FACTORS.

An investment in our securities involves certain risks. Security holders and potential investors in our securities should carefully consider the risks described under ~~“Risk Factors”~~“Risk Factors” set forth in Part I, Item 1A of our ~~2019~~2020 Form 10-K, in addition to other information in such annual report and this quarterly ~~report (including the additional risk factor set forth below).~~report. The risk factors set forth in our ~~2019~~2020 Form 10-K ~~and as set forth below~~ are important factors that could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us or on our behalf.

The impacts from the outbreak of COVID-19 and certain developments in the global oil markets have had, and may continue to have, material adverse consequences for general economic, financial and business conditions, and could materially and adversely affect our business, financial condition, results of operations and liquidity and those of our customers, suppliers and other counterparties.

The recent outbreak of COVID-19 and the responses of governmental authorities, companies and the self-imposed restrictions by many individuals across the world to slow the spread of the virus have significantly reduced global economic activity. The dramatic decrease in the number of businesses open for operation and people traveling for work, school or other activities has resulted in a substantial reduction in airline flights and the number of vehicles on the road. As a result, there has been an unprecedented decline in the near-term demand for, and corresponding decline in the market prices of, crude oil and certain refined products that we process, transport and store. It is currently unknown how long government mandates and travel restrictions will be in effect. These declines have been exacerbated by the production dispute between Russia and the members of OPEC, particularly Saudi Arabia, and the subsequent actions taken by such countries as a result thereof, including Saudi Arabia’s subsequent discounting of the price of its crude oil exports. Crude oil prices further collapsed in April 2020 as refiners cut back gasoline and other fuel production due to COVID-19.

Responses to COVID-19 have affected business operations across the world, decreased demand for crude oil and other hydrocarbons, contributed to increased market and oil price volatility, led to expected domestic and international production cuts, and have diminished near-term expectations and prospects for the global economy. These factors, coupled with the emergence of decreasing business and consumer confidence and increasing unemployment resulting from the COVID-19 outbreak and the recent abrupt crude oil price decline, may precipitate a prolonged economic slowdown and recession. Any prolonged period of economic slowdown or recession, or a protracted period of depressed demand or prices for crude oil or other products that we handle, could have significant adverse consequences for our financial condition and the financial condition of our customers, suppliers and other counterparties, and could diminish our liquidity and negatively affect the volumes of products handled by our pipelines and other facilities.

The ultimate extent and manner of the impact of COVID-19 and responses by our customers on our business, financial condition, results of operation and liquidity will depend largely on future developments outside our control, including the duration and spread of the outbreak and the related impact on overall economic activity, all of which are uncertain and cannot be predicted with certainty at this time. To the extent COVID-19 adversely affects our business, financial condition, results of operation and liquidity, it may also have the effect of heightening many of the other risks described in Part I, Item 1A of our 2019 Form 10-K, as those risk factors are amended or supplemented by subsequent reports and documents we file with the SEC after the date of this quarterly report.

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

Recent Issuance of Unregistered Securities

~~On March 5, 2020, we settled~~Holders of our ~~obligations under~~Series A Cumulative Convertible Preferred Units are entitled to receive cumulative quarterly distributions at a rate of 7.25% per annum. We may satisfy our obligation to pay distributions to the ~~Liquidity Option Agreement. As~~preferred unitholders through the issuance, in whole or in part, of additional preferred units (referred to as paid-in kind or “PIK” distributions), with the remainder in cash, subject to certain rights of a ~~result, EPD issued 54,807,352~~holder to elect all cash and other conditions as described in our partnership agreement.

In February 2021, the Partnership made a quarterly distribution to preferred unitholders, including PIK distributions of ~~its common~~an aggregate of 15,931 restricted preferred units ~~(the “Liquidity Option Units”)~~consisting of 15,657 preferred units to OTA (which are accounted for as ~~consideration for our acquisition of 100% of the issued~~treasury units in consolidation) and ~~outstanding capital stock of OTA.~~ 274 preferred units to a privately held EPCO affiliate.

For additional information regarding ~~this transaction,~~the preferred units, see ~~“Other Recent Developments – Settlement~~Note 8 of ~~Liquidity Option” within~~the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 21 of this quarterly report.

The ~~issuance and sale~~issuances of the ~~Liquidity Option Units was exempt~~preferred units as PIK distributions during the three months ended March 31, 2021 were undertaken in reliance upon an exemption from the registration ~~under Section 4(a)(2)~~requirements of the Securities Act ~~because the transaction did not involve a public offering.~~of 1933, as amended, pursuant to Section 4(a)(2) thereof.

Other than as described above, there were no sales of unregistered equity securities during the ~~period ended March 31, 2020.~~first quarter of 2021.

Issuer Purchases of Equity Securities

The following table summarizes our equity repurchase activity during the first quarter of ~~2020:~~2021:

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)
   January 2020 – $ – 2,909,128 $ 1,918,911
   February 2020 – $ – 2,909,128 $ 1,918,911
   March 2020 6,357,739 $ 22.02 9,266,867 $ 1,778,911
Vesting of phantom unit awards:
   January 2020 – $ – n/a n/a
   February 2020 (2) 1,291,427 $ 25.96 n/a n/a
   March 2020 (3) 1,297 $ 23.34 n/a n/a

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)

January 2021

709,816

19.58

709,816

1,718,911

February 2021

–

1,718,911

March 2021

–

1,718,911

Vesting of phantom unit awards:

January 2021

–

n/a

February 2021 (2)

1,587,782

21.92

n/a

March 2021

–

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. Units repurchased under this program ~~during 2020 were~~are cancelled immediately upon acquisition.
(2)	Of the ~~4,200,676~~5,132,145 phantom unit awards that vested in February ~~2020~~2021 and converted to common units, 1,291,427 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 4,262 phantom unit awards that vested in March 2020 and converted to common units, 1,297~~1,587,782 units were sold back to us by employees to cover related withholding tax requirements. These repurchases are not part of any announced program. We cancelled these units immediately upon acquisition.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

None.

ITEM 4. MINE SAFETY DISCLOSURES.

Not applicable.

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ITEM 5. OTHER INFORMATION.

None.

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ITEM 6. EXHIBITS.

Exhibit Number	Exhibit*
2.1	Merger Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form 8-K filed December 15, 2003).
2.2	Amendment No. 1 to Merger Agreement, dated as of August 31, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form 8-K filed September 7, 2004).
2.3	Parent Company Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.2 to Form 8-K filed December 15, 2003).
2.4	Amendment No. 1 to Parent Company Agreement, dated as of April 19, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.1 to Form 8-K filed April 21, 2004).
2.5	Purchase and Sale Agreement (Gas Plants), dated as of December 15, 2003, by and between El Paso Corporation, El Paso Field Services Management, Inc., El Paso Transmission, L.L.C., El Paso Field Services Holding Company and Enterprise Products Operating L.P. (incorporated by reference to Exhibit 2.4 to Form 8-K filed December 15, 2003).
2.6	Agreement and Plan of Merger, dated as of June 28, 2009, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Sub B LLC, TEPPCO Partners, L.P. and Texas Eastern Products Pipeline Company, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed June 29, 2009).
2.7	Agreement and Plan of Merger, dated as of June 28, 2009, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Sub A LLC, TEPPCO Partners, L.P. and Texas Eastern Products Pipeline Company, LLC (incorporated by reference to Exhibit 2.2 to Form 8-K filed June 29, 2009).
2.8	Agreement and Plan of Merger, dated as of September 3, 2010, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise ETE LLC, Enterprise GP Holdings L.P. and EPE Holdings, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed September 7, 2010).
2.9	Agreement and Plan of Merger, dated as of September 3, 2010, by and among Enterprise Products GP, LLC, Enterprise GP Holdings L.P. and EPE Holdings, LLC (incorporated by reference to Exhibit 2.2 to Form 8-K filed September 7, 2010).
2.10	Contribution Agreement, dated as of September 30, 2010, by and between Enterprise Products Company and Enterprise Products Partners L.P. (incorporated by reference to Exhibit 2.1 to Form 8-K filed October 1, 2010).

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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).

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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~~Seventh 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~~	~~Amendment No. 5 to the Sixth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated as of March 5,~~September 30, 2020 (incorporated by reference to Exhibit 3.1 to Form 8-K filed ~~March 5,~~October 1, 2020).
~~3.9~~3.4	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).
~~3.10~~3.5	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).
~~3.11~~3.6	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).
~~3.12~~3.7	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).
~~3.13~~3.8	Amendment No. 2 to Fifth Amended and Restated Limited Liability Company Agreement of Enterprise Products Holdings LLC, dated effective as of November 6, 2019 (incorporated by reference to Exhibit 3.12 to Form 10-Q filed November 8, 2019).
~~3.14~~3.9	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).
~~3.15~~3.10	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).
~~3.16~~3.11	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)~~October 1, 2020).
4.2	Description of the Registrant’s Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934 (incorporated by reference to Exhibit 4.2 to Form 10-K filed February 28, 2020).

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4.3	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).
4.4	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).
4.5	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).
4.6	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).
4.7	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).
4.8	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).
4.9	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).
4.10	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).
~~4.11~~	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).
~~4.12~~4.11	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).
~~4.13~~4.12	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).
~~4.14~~4.13	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).
~~4.15~~4.14	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).
~~4.16~~4.15	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).

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~~4.17~~4.16	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).
~~4.18~~4.17	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).
~~4.19~~4.18	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).
~~4.20~~4.19	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).
~~4.21~~4.20	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).
~~4.22~~4.21	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).
~~4.23~~4.22	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).
~~4.24~~4.23	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).
~~4.25~~4.24	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).
~~4.26~~4.25	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).
~~4.27~~4.26	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).
~~4.28~~4.27	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).
~~4.29~~4.28	Thirty-Fourth Supplemental Indenture, dated as of January 15, 2020, 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 January 15, 2020).

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4.29	Thirty-Fifth Supplemental Indenture, dated as of August 7, 2020, 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 August 7, 2020).
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).

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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 ~~$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).~~
~~4.34~~	~~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).
~~4.35~~4.34	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).
~~4.36~~4.35	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).
~~4.37~~4.36	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).
~~4.38~~4.37	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).
~~4.39~~4.38	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).
~~4.40~~4.39	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).
~~4.41~~4.40	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).
~~4.42~~4.41	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).
~~4.43~~4.42	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).
~~4.44~~4.43	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).
~~4.45~~4.44	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).
~~4.46~~4.45	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).

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~~4.47~~4.46	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).
~~4.48~~4.47	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).

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~~4.49~~	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).
~~4.50~~4.48	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).
~~4.51~~4.49	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).
~~4.52~~4.50	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).
~~4.53~~4.51	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).
~~4.54~~4.52	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).
~~4.55~~4.53	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).
~~4.56~~4.54	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).
~~4.57~~4.55	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).
~~4.58~~4.56	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).
~~4.59~~4.57	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).
~~4.60~~4.58	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).
~~4.61~~4.59	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).
~~4.62~~4.60	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).
~~4.63~~4.61	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).
~~4.64~~4.62	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).

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~~4.65~~4.63	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).
~~4.66~~4.64	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).

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~~4.67~~4.65	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).
~~4.68~~4.66	Form of Global Note representing $1,000.0 million principal amount of 2.800% Senior Notes due 2030 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed January 15, 2020).
~~4.69~~4.67	Form of Global Note representing $1,000.0 million principal amount of 3.700% Senior Notes due 2051 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed January 15, 2020).
~~4.70~~4.68	Form of Global Note representing $1,000.0 million principal amount of 3.950% Senior Notes due 2060 with attached Guarantee (incorporated by reference to Exhibit C to Exhibit 4.3 to Form 8-K filed January 15, 2020).
4.69	Form of Global Note representing $250.0 million principal amount of 2.800% Senior Notes due 2030 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed January 15, 2020).
4.70	Form of Global Note representing $1,000.0 million principal amount of 3.200% Senior Notes due 2052 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.4 to Form 8-K filed August 7, 2020).
4.71	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).
4.72	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).
4.73	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).
4.74	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).
4.75	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).
4.76	Seventh Supplemental Indenture, dated March 27, 2008, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.13 to the Form 10-Q filed by TEPPCO Partners, L.P. on May 8, 2008).

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4.77	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).
4.78	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).
4.79	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).
4.80	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).

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4.81	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).
4.82	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).
4.83	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).
4.84	Registration Rights Agreement, dated as of March 5, 2020, between Enterprise Products Partners L.P. and Skyline North Americas, Inc. (incorporated by reference to Exhibit 4.1 to Form 8-K filed March 5, 2020).
~~10.1~~4.85	~~April 2020 364-Day Revolving Credit~~Equity Distribution Agreement, dated ~~as of April 3,~~June 24, 2020, by and among Enterprise Products Partners L.P., Enterprise Products OLPGP, Inc., Enterprise Products Operating LLC, ~~the Lenders party thereto,~~Skyline North Americas, Inc. and ~~Citibank, N.A. as Administrative Agent~~Morgan Stanley & Co. LLC. (incorporated by reference to Exhibit ~~10.1~~1.1 to Form 8-K filed ~~April 6,~~June 25, 2020).
~~10.2~~4.86	~~Guaranty~~Specimen Unit Certificate for the Series A Cumulative Convertible Preferred Units, (incorporated by reference to Exhibit B to Exhibit 3.1 to Form 8-K filed October 1, 2020).
4.87	Registration Rights Agreement, dated as of ~~April 3,~~September 30, 2020, by and among Enterprise Products Partners L.P. and the Purchasers party thereto. (incorporated by reference to Exhibit 4.2 to Form 8-K filed October 1, 2020).
22.1#	List of Issuers of Debt Securities Guaranteed by Enterprise Products Partners L.P. ~~in favor of Citibank, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.2 to Form 8-K filed April 6, 2020).~~and Associated Securities at March 31, 2021.
31.1#	Sarbanes-Oxley Section 302 certification of A. James Teague for Enterprise Products Partners L.P.’s quarterly report on Form 10-Q for the three months ended March 31, ~~2020.~~2021.
31.2#	Sarbanes-Oxley Section 302 certification of W. Randall Fowler for Enterprise Products Partners L.P.’s quarterly report on Form 10-Q for the three months ended March 31, ~~2020.~~2021.

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32.1#	Sarbanes-Oxley Section 906 certification of A. James Teague for Enterprise Products Partners L.P.’s quarterly report on Form 10-Q for the three months ended March 31, ~~2020.~~2021.
32.2#	Sarbanes-Oxley Section 906 certification of W. Randall Fowler for Enterprise Products Partners L.P.’s quarterly report on Form 10-Q for the three months ended March 31, ~~2020.~~2021.
101#	Interactive data files pursuant to Rule 405 of Regulation S-T formatted in iXBRL (Inline Extensible Business Reporting Language) in this Form 10-Q ~~includes:~~include the: (i) ~~the~~ Unaudited Condensed Consolidated Balance Sheets, (ii) ~~the~~ Unaudited Condensed Statements of Consolidated Operations, (iii) ~~the~~ Unaudited Condensed Statements of Consolidated Comprehensive Income, (iv) ~~the~~ Unaudited Condensed Statements of Consolidated Cash Flows, (v) ~~the~~ Unaudited Condensed Statements of Consolidated Equity and (vi) Notes to the Unaudited Condensed Consolidated Financial Statements.
104#	Cover Page Interactive Data File (embedded within the ~~Inline XBRL~~iXBRL document).

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

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on May ~~8, 2020.~~7, 2021.

		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:	Executive Vice President – Accounting, Risk Control and Information Technology of the General Partner

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

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

Large Accelerated Filer ☑	Accelerated filer ☐
Non-accelerated filer ☐	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~~Operations	78
	2. Summary of Significant Accounting Policies	89
	3. Inventories	9
	4. Property, Plant and Equipment	10
	5. Investments in Unconsolidated Affiliates	1112
	6. Intangible Assets and Goodwill	12
	7. Debt Obligations	1314
	8. ~~Equity and Distributions~~Capital Accounts	1516
	9. Revenues	18
	10. Business Segments and Related Information	20
	11. ~~Income Taxes~~Earnings Per Unit	2324
	12. ~~Earnings Per Unit~~Equity-Based Awards	2 524
	13. ~~Equity-Based Awards~~Hedging Activities and Fair Value Measurements	26
	14. ~~Derivative Instruments, Hedging Activities and Fair Value Measurements~~Related Party Transactions	2732
	15. ~~Related Party Transactions~~Income Taxes	33
	16. Commitments and ~~Contingencies~~Contingent Liabilities	3435
	17. Supplemental Cash Flow Information	37
	~~18. Condensed Consolidating Financial Information~~	38
	~~19. Subsequent Events~~	43
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	4438
Item 3.	Quantitative and Qualitative Disclosures About Market Risk.	7160
Item 4.	Controls and Procedures.	7562

PART II. OTHER INFORMATION.
Item 1.	Legal Proceedings.	7562
Item 1A.	Risk Factors.	7662
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	7763
Item 3.	Defaults Upon Senior Securities.	7763
Item 4.	Mine Safety Disclosures.	7763
Item 5.	Other Information.	7764
Item 6.	Exhibits.	7864

Signatures		8673

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

	Limited Partner Common Units Outstanding			Treasury Units
Units outstanding at December 31, 2019		2,189,226,130			–
Common units issued in connection with settlement of Liquidity Option		54,807,352			–
Treasury units acquired in connection with settlement of Liquidity Option		(54,807,352	)		54,807,352
Common unit repurchases under 2019 Buyback Program		(6,357,739	)		–
Common units issued in connection with the vesting of phantom unit awards, net		2,912,214			–
Other		19,638			–
Units outstanding at March 31, 2020		2,185,800,243			54,807,352

Deferred tax liability at March 5, 2020				$	439.7
Impact of change in fair value of units on deferred tax liability:
Change in fair value of 54,807,352 EPD common units held by OTA (1)	$	(513.5	)
Multiplied by estimated blended federal and state tax rate		22.4	%		(114.8	)
Other, including interim allocations of taxable income					(0.2	)
Deferred tax liability at March 31, 2020				$	324.7

Hedged Transaction	Number and Type of Derivatives Outstanding	Notional Amount	Expected Settlement Date	Weighted-Average Fixed Rate Locked	Accounting Treatment
Future long-term debt offering	1 forward-starting swap	$75.0	4/2021	2.41%	Cash flow hedge
Future long-term debt offering	5 forward-starting swaps	$500.0	4/2021	2.13%	Cash flow hedge
Future long-term debt offering	2 forward-starting swaps (1)	$150.0	2/2022	1.72%	Cash flow hedge
Future long-term debt offering	1 forward starting swap (1)	$100.0	4/2021	1.46%	Cash flow hedge
Future long-term debt offering	2 forward starting swaps (1)	$150.0	2/2022	1.48%	Cash flow hedge
Future long-term debt offering	2 forward starting swaps (1)	$100.0	2/2022	0.95%	Cash flow hedge

Total Number of Units	Percentage of Total Units Outstanding
701,956,852	32.1%

	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	$	1,897.3	$	230.2	$	(12.0	)	$	2,115.5	$	0.1	$	–		$	2,115.6
Accounts receivable – trade, net		1,026.1		2,268.9		(1.2	)		3,293.8		–		–			3,293.8
Accounts receivable – related parties		235.3		871.8		(924.3	)		182.8		–		(180.9	)		1.9
Inventories		1,080.8		458.5		(0.5	)		1,538.8		–		–			1,538.8
Derivative assets		324.0		61.8		(20.0	)		365.8		–		–			365.8
Prepaid and other current assets		217.3		249.7		(64.8	)		402.2		0.8		0.2			403.2
Total current assets		4,780.8		4,140.9		(1,022.8	)		7,898.9		0.9		(180.7	)		7,719.1
Property, plant and equipment, net		6,537.2		35,664.4		(42.5	)		42,159.1		–		–			42,159.1
Investments in unconsolidated affiliates		46,002.5		4,781.6		(48,175.6	)		2,608.5		25,229.5		(25,229.5	)		2,608.5
Intangible assets, net		631.9		2,794.9		(17.4	)		3,409.4		–		–			3,409.4
Goodwill		459.5		5,285.7		–			5,745.2		–		–			5,745.2
Other assets		553.0		313.9		(243.8	)		623.1		0.9		–			624.0
Total assets	$	58,964.9	$	52,981.4	$	(49,502.1	)	$	62,444.2	$	25,231.3	$	(25,410.2	)	$	62,265.3

LIABILITIES AND EQUITY
Current liabilities:
Current maturities of debt	$	1,750.0	$	–	$	–		$	1,750.0	$	–	$	–		$	1,750.0
Accounts payable – trade		157.7		769.9		(11.8	)		915.8		–		–			915.8
Accounts payable – related parties		895.0		111.9		(937.5	)		69.4		180.9		(180.9	)		69.4
Accrued product payables		1,379.2		1,788.7		(1.6	)		3,166.3		–		–			3,166.3
Accrued interest		238.2		3.2		(3.1	)		238.3		–		–			238.3
Derivative liabilities		208.1		81.1		(20.0	)		269.2		–		–			269.2
Other current liabilities		191.5		378.3		(63.4	)		506.4		–		–			506.4
Total current liabilities		4,819.7		3,133.1		(1,037.4	)		6,915.4		180.9		(180.9	)		6,915.4
Long-term debt		27,841.3		14.6		–			27,855.9		–		–			27,855.9
Deferred tax liabilities		24.6		400.8		(0.6	)		424.8		–		3.4			428.2
Other long-term liabilities		579.4		619.0		(246.8	)		951.6		–		–			951.6
Commitments and contingencies
Equity:
Partners’ and other owners’ equity		25,699.9		48,749.4		(49,253.5	)		25,195.8		25,050.4		(25,195.8	)		25,050.4
Noncontrolling interests		–		64.5		1,036.2			1,100.7		–		(36.9	)		1,063.8
Total equity		25,699.9		48,813.9		(48,217.3	)		26,296.5		25,050.4		(25,232.7	)		26,114.2
Total liabilities and equity	$	58,964.9	$	52,981.4	$	(49,502.1	)	$	62,444.2	$	25,231.3	$	(25,410.2	)	$	62,265.3

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)
January 2020		–	$	–		2,909,128	$	1,918,911
February 2020		–	$	–		2,909,128	$	1,918,911
March 2020		6,357,739	$	22.02		9,266,867	$	1,778,911
Vesting of phantom unit awards:
January 2020		–	$	–		n/a		n/a
February 2020 (2)		1,291,427	$	25.96		n/a		n/a
March 2020 (3)		1,297	$	23.34		n/a		n/a