EPD 10-Q Quarterly Report June 30, 2020 | Alphaminr
ENTERPRISE PRODUCTS PARTNERS L.P.
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EPD 10-Q Quarter ended June 30, 2020

Balance Sheet
Cash Flow
Income Statement
Debt
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PROXIES
DEF 14A
Filed on Nov. 22, 2022
DEF 14A
Filed on Oct. 24, 2022
DEF 14A
Filed on Aug. 26, 2013

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-Q

☑ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2020

OR
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___  to  ___.

Commission file number: 1-14323

ENTERPRISE PRODUCTS PARTNERS L.P.
(Exact Name of Registrant as Specified in Its Charter)

Delaware
76-0568219
(State or Other Jurisdiction of Incorporation or Organization)
(I.R.S. Employer Identification No.)
1100 Louisiana Street, 10th Floor
Houston , Texas 77002
(Address of Principal Executive Offices, including Zip Code)
( 713 ) 381-6500
(Registrant’s Telephone Number, including Area Code)

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

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

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

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

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

Large Accelerated Filer ☑
Accelerated filer ☐
Non-accelerated filer ☐
Smaller reporting company ☐
Emerging growth company ☐

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

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

There were 2,185,896,433 common units of Enterprise Products Partners L.P. outstanding at the close of business on July 31, 2020.

ENTERPRISE PRODUCTS PARTNERS L.P.
TABLE OF CONTENTS

Page No.

1

PART I.  FINANCIAL INFORMATION.

ITEM 1.  FINANCIAL STATEMENTS.

EN TERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)

June 30,
2020
December 31,
2019
ASSETS
Current assets:
Cash and cash equivalents
$
1,298.5
$
334.7
Restricted cash
138.1
75.3
Accounts receivable – trade, net of allowance for doubtful accounts
of $ 13.9 at June 30, 2020 and $ 12.4 at December 31, 2019
2,907.7
4,873.6
Accounts receivable – related parties
2.6
2.5
Inventories
2,024.1
2,091.4
Derivative assets
209.7
127.2
Prepaid and other current assets
535.6
358.2
Total current assets
7,116.3
7,862.9
Property, plant and equipment, net
42,538.4
41,603.4
Investments in unconsolidated affiliates
2,547.4
2,600.2
Intangible assets, net of accumulated amortization of $ 1,763.7 at
June 30, 2020 and $ 1,687.5 at December 31, 2019 (see Note 6)
3,379.4
3,449.0
Goodwill (see Note 6)
5,745.2
5,745.2
Other assets
617.8
472.5
Total assets
$
61,944.5
$
61,733.2
LIABILITIES AND EQUITY
Current liabilities:
Current maturities of debt (see Note 7)
$
2,325.0
$
1,981.9
Accounts payable – trade
902.5
1,004.5
Accounts payable – related parties
89.3
162.3
Accrued product payables
2,803.5
4,915.7
Accrued interest
461.7
431.7
Derivative liabilities
385.4
122.4
Other current liabilities
515.0
511.2
Total current liabilities
7,482.4
9,129.7
Long-term debt (see Note 7)
27,285.2
25,643.2
Deferred tax liabilities (see Note 11)
481.6
100.4
Other long-term liabilities
753.9
1,032.4
Commitments and contingencies (see Note 16)
Equity: (see Note 8)
Partners’ equity:
Limited partners:
Common units ( 2,240,703,785 units issued and 2,185,896,433 units outstanding at
June 30, 2020, 2,189,226,130 units issued and outstanding at December 31, 2019)
26,321.1
24,692.6
Treasury units, at cost ( 54,807,352 units at June 30, 2020) (see Note 8)
( 1,297.3
)
–
Accumulated other comprehensive income (loss)
( 147.1
)
71.4
Total  partners’ equity
24,876.7
24,764.0
Noncontrolling interests
1,064.7
1,063.5
Total equity
25,941.4
25,827.5
Total liabilities and equity
$
61,944.5
$
61,733.2



See Notes to Unaudited Condensed Consolidated Financial Statements.
2

ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS
(Dollars in millions, except per unit amounts)

For the Three Months
Ended June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
Revenues:
Third parties
$
5,745.3
$
8,250.5
$
13,211.8
$
16,781.7
Related parties
5.7
25.8
21.7
38.1
Total revenues (see Note 9)
5,751.0
8,276.3
13,233.5
16,819.8
Costs and expenses:
Operating costs and expenses:
Third parties
4,063.9
6,469.5
9,799.2
13,124.8
Related parties
306.5
331.4
631.5
695.8
Total operating costs and expenses
4,370.4
6,800.9
10,430.7
13,820.6
General and administrative costs:
Third parties
23.8
21.4
46.8
41.8
Related parties
33.2
31.1
65.7
62.9
Total general and administrative costs
57.0
52.5
112.5
104.7
Total costs and expenses (see Note 10)
4,427.4
6,853.4
10,543.2
13,925.3
Equity in income of unconsolidated affiliates
113.3
137.4
254.1
292.0
Operating income
1,436.9
1,560.3
2,944.4
3,186.5
Other income (expense):
Interest expense
( 320.2
)
( 290.1
)
( 637.7
)
( 567.3
)
Change in fair market value of Liquidity Option
–
( 26.6
)
( 2.3
)
( 84.4
)
Interest income
2.9
0.7
10.1
2.0
Other, net
0.9
1.9
1.8
2.1
Total other expense, net
( 316.4
)
( 314.1
)
( 628.1
)
( 647.6
)
Income before income taxes
1,120.5
1,246.2
2,316.3
2,538.9
Benefit from (provision for) income taxes (see Note 11)
( 59.7
)
( 9.7
)
119.5
( 22.0
)
Net income
1,060.8
1,236.5
2,435.8
2,516.9
Net income attributable to noncontrolling interests
( 26.1
)
( 21.8
)
( 51.0
)
( 41.7
)
Net income attributable to limited partners
$
1,034.7
$
1,214.7
$
2,384.8
$
2,475.2
Earnings per unit: (see Note 12)
Basic and diluted earnings per unit
$
0.47
$
0.55
$
1.08
$
1.12


















See Notes to Unaudited Condensed Consolidated Financial Statements.
3


ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED
COMPREHENSIVE INCOME
(Dollars in millions)

For the Three Months
Ended June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
Net income
$
1,060.8
$
1,236.5
$
2,435.8
$
2,516.9
Other comprehensive income (loss):
Cash flow hedges: (see Note 14)
Commodity hedging derivative instruments:
Changes in fair value of cash flow hedges
( 78.2
)
81.5
396.9
( 13.7
)
Reclassificatio n of gains to ne t income
( 208.7
)
( 2.2
)
( 364.3
)
( 60.5
)
Interest rate hedging derivative instruments:
Changes in fair value of cash flow hedges
7.8
( 5.2
)
( 284.2
)
( 5.2
)
Reclassification of losses to net income
9.7
9.2
33.2
18.4
Total cash flow hedges
( 269.4
)
83.3
( 218.4
)
( 61.0
)
Other
–
–
( 0.1
)
( 0.6
)
Total other comprehens ive income (loss)
( 269.4
)
83.3
( 218.5
)
( 61.6
)
Comprehensive income
791.4
1,319.8
2,217.3
2,455.3
Comprehensive income attributable to noncontrolling interests
( 26.1
)
( 21.8
)
( 51.0
)
( 41.7
)
Comprehensive income attributable to limited partners
$
765.3
$
1,298.0
$
2,166.3
$
2,413.6





























See Notes to Unaudited Condensed Consolidated Financial Statements.
4


ENTERPRISE PRODUCT S PARTNERS L.P.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(Dollars in millions)

For the Six Months
Ended June 30,
2020
2019
Operating activities:
Net income
$
2,435.8
$
2,516.9
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion
1,031.7
963.1
Asset impairment and related charges
13.4
11.8
Equity in income of unconsolidated affiliates
( 254.1
)
( 292.0
)
Distributions received from unconsolidated affiliates attributable to earnings
257.6
291.1
Net gains attributable to asset sales
( 1.5
)
( 2.5
)
Deferred income tax expense (benefit)
( 130.7
)
4.2
Change in fair market value of derivative instruments
( 91.4
)
( 83.8
)
Change in fair market value of Liquidity Option
2.3
84.4
Non-cash expense related to long-term operating leases (see Note 16)
19.8
21.7
Net effect of changes in operating accounts (see Note 17)
( 89.0
)
( 332.0
)
Other operating activities
( 0.1
)
0.8
Net cash flows provided by operating activities
3,193.8
3,183.7
Investing activities:
Capital expenditures
( 1,975.9
)
( 2,260.8
)
Investments in unconsolidated affiliates
( 7.3
)
( 59.9
)
Distributions received from unconsolidated affiliates attributable to the return of capital
58.0
23.4
Proceeds from asset sales
4.1
16.1
Other investing activities
( 9.4
)
( 5.3
)
Cash used in investing activities
( 1,930.5
)
( 2,286.5
)
Financing activities:
Borrowings under debt agreements
5,411.8
40,318.1
Repayments of debt
( 3,406.6
)
( 39,617.3
)
Debt issuance costs
( 32.2
)
( 0.3
)
Monetization of interest rate derivative instruments
( 33.3
)
–
Cash distributions paid to limited partners (see Note 8)
( 1,946.9
)
( 1,907.9
)
Cash payments made in connection with distribution equivalent rights
( 12.9
)
( 10.5
)
Cash distributions paid to noncontrolling interests
( 61.8
)
( 46.9
)
Cash contributions from noncontrolling interests
19.7
99.6
Net cash proceeds from the issuance of common units
–
82.2
Repurchase of common units under 2019 Buyback Program (see Note 8)
( 140.1
)
( 81.1
)
Other financing activities
( 34.4
)
( 35.9
)
Cas h used in financing ac tivities
( 236.7
)
( 1,200.0
)
Net change in cash and cash equivalents, including restricted cash
1,026.6
( 302.8
)
Cash and cash equivalents, including restricted cash, at beginning of period
410.0
410.1
Cash and cash equivalents, including restricted cash, at end of period
$
1,436.6
$
107.3











See Notes to Unaudited Condensed Consolidated Financial Statements.
5



ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY
FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2020
(Dollars in millions)

Partners’ Equity
Limited
Partners
Treasury
Units
Accumulated
Other
Comprehensive
Income (Loss)
Noncontrolling
Interests
Total
For the Three Months Ended June 30, 2020:
Balance, March 31, 2020
$
26,225.4
$
( 1,297.3
)
$
122.3
$
1,063.8
$
26,114.2
Net income
1,034.7
–
–
26.1
1,060.8
Cash distributions paid to limited partners
( 972.7
)
–
–
–
( 972.7
)
Cash payments made in connection with
distribution equivalent rights
( 7.1
)
–
–
–
( 7.1
)
Cash distributions paid to noncontrolling interests
–
–
–
( 31.9
)
( 31.9
)
Cash contributions from noncontrolling interests
–
–
–
14.5
14.5
Amortization of fair value of equity-based awards
41.5
–
–
–
41.5
Cash flow hedges
–
–
( 269.4
)
–
( 269.4
)
Other, net
( 0.7
)
–
–
( 7.8
)
( 8.5
)
Balance, June 30, 2020
$
26,321.1
$
( 1,297.3
)
$
( 147.1
)
$
1,064.7
$
25,941.4



Partners’ Equity
Limited
Partners
Treasury
Units
Accumulated
Other
Comprehensive
Income (Loss)
Noncontrolling
Interests
Total
For the Six Months Ended June 30, 2020:
Balance, December 31, 2019
$
24,692.6
$
–
$
71.4
$
1,063.5
$
25,827.5
Net income
2,384.8
–
–
51.0
2,435.8
Cash distributions paid to limited partners
( 1,946.9
)
–
–
–
( 1,946.9
)
Cash payments made in connection with
distribution equivalent rights
( 12.9
)
–
–
–
( 12.9
)
Cash distributions paid to noncontrolling interests
–
–
–
( 61.8
)
( 61.8
)
Cash contributions from noncontrolling interests
–
–
–
19.7
19.7
Amortization of fair value of equity-based awards
80.6
–
–
–
80.6
Repurchase and cancellation of common units under
2019 Buyback Program (see Note 8)
( 140.1
)
–
–
–
( 140.1
)
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
–
–
( 218.4
)
–
( 218.4
)
Other, net
( 34.3
)
–
( 0.1
)
( 7.7
)
( 42.1
)
Balance, June 30, 2020
$
26,321.1
$
( 1,297.3
)
$
( 147.1
)
$
1,064.7
$
25,941.4












See Notes to Unaudited Condensed Consolidated Financial Statements.  For information regarding Unit History and
Accumulated Other Comprehensive Income (Loss), see Note 8.
6

ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY
FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2019
(Dollars in millions)

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


Partners’ Equity
Limited
Partners
Accumulated
Other
Comprehensive
Income (Loss)
Noncontrolling
Interests
Total
For the Six Months Ended June 30, 2019:
Balance, December 31, 2018
$
23,802.6
$
50.9
$
438.7
$
24,292.2
Net income
2,475.2
–
41.7
2,516.9
Cash distributions paid to limited partners
( 1,907.9
)
–
–
( 1,907.9
)
Cash payments made in connection with distribution equivalent rights
( 10.5
)
–
–
( 10.5
)
Cash distributions paid to noncontrolling interests
–
–
( 46.9
)
( 46.9
)
Cash contributions from noncontrolling interests
–
–
99.6
99.6
Net cash proceeds from the issuance of common units
82.2
–
–
82.2
Common units issued in connection with employee compensation
45.6
–
–
45.6
Repurchase and cancellation of common units under
2019 Buyback Program (see Note 8)
( 81.1
)
–
–
( 81.1
)
Amortization of fair value of equity-based awards
70.5
–
–
70.5
Cash flow hedges
–
( 61.0
)
–
( 61.0
)
Other
( 26.1
)
( 0.6
)
2.5
( 24.2
)
Balance, June 30, 2019
$
24,450.5
$
( 10.7
)
$
535.6
$
24,975.4














See Notes to Unaudited Condensed Consolidated Financial Statements. For information regarding Unit History and
Accumulated Other Comprehensive Income (Loss), see Note 8.

7

ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

With the exception of per unit amounts, or as noted within the context of each disclosure,
the dollar amounts presented in the tabular data within these disclosures are
stated in millions of dollars.

KEY REFERENCES USED IN THESE
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unless the context requires otherwise, references to “we,” “us,” “our” or “Enterprise” are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries.  References to “EPD” 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 June 30, 2020.


Note 1.  Partnership Organization and Basis of Presentation

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

We conduct substantially all of our business through EPO and are owned 100 % by EPD’s limited partners from an economic perspective.  Enterprise GP manages our partnership and owns a non-economic general partner interest in us.  We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates under the collective common control of the DD LLC Trustees and the EPCO Trustees.  Like many publicly traded partnerships, we have no employees.  All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement (the “ASA”) or by other service providers.  See Note 15 for information regarding related party matters.

Our results of operations for the six months ended June 30, 2020 are not necessarily indicative of results expected for the full year of 2020.  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”).

8

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  (the “2019 Form 10-K”) filed with the SEC on February 28, 2020.


Note 2.  Summary of Significant Accounting Policies

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

Cash, Cash Equivalents and Restricted Cash

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

June 30,
2020
December 31,
2019
Cash and cash equivalents
$
1,298.5
$
334.7
Restricted cash
138.1
75.3
Total cash, cash equivalents and restricted cash shown in the
Unaudited Condensed Statements of Consolidated Cash Flows
$
1,436.6
$
410.0

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 14 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 as the current expected credit loss model, requires the measurement of  expected credit losses for financial assets (e.g., accounts receivable) held 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.

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.

The adoption of this new guidance on January 1, 2020 did not have a material impact on our consolidated financial statements.  See Note 14 for information regarding our fair value measurements.
9

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:

June 30,
2020
December 31,
2019
NGLs
$
840.0
$
1,094.9
Petrochemicals and refined products
649.9
311.5
Crude oil
519.3
674.2
Natural gas
14.9
10.8
Total
$
2,024.1
$
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 June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
Cost of sales (1)
$
3,195.2
$
5,609.4
$
8,018.2
$
11,445.0
Lower of cost or net realizable value adjustments
recognized in cost of sales
13.2
4.9
51.2
10.3

(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.



10

ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Note 4.  Property, Plant and Equipment

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

Estimated
Useful Life
in Years
June 30,
2020
December 31,
2019
Plants, pipelines and facilities (1)
3 - 45
(5)
$
48,072.1
$
47,201.2
Underground and other storage facilities (2)
5 - 40
(6)
4,104.9
3,965.5
Transportation equipment (3)
3 - 10
204.5
198.9
Marine vessels (4)
15 - 30
906.8
905.9
Land
375.9
372.3
Construction in progress
3,279.4
2,641.2
Total
56,943.6
55,285.0
Less accumulated depreciation
14,405.2
13,681.6
Property, plant and equipment, net
$
42,538.4
$
41,603.4

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

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

For the Three Months
Ended June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
Depreciation expense (1)
$
418.7
$
389.3
$
830.9
$
769.9
Capitalized interest (2)
31.9
32.8
62.4
69.0

(1)
Depreciation expense is a component of “Costs and expenses” as presented on our Unaudited Condensed Statements of Consolidated Operations.
(2)
We capitalize interest costs incurred on funds used to construct property, plant and equipment while the asset is in its construction phase.  The capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset’s estimated useful life as a component of depreciation expense.  When capitalized interest is recorded, it reduces interest expense from what it would be otherwise.

Asset Retirement Obligations

Property, plant and equipment at June 30, 2020 and December 31, 2019 includes $ 70.3 million and $ 69.6 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, 2019:

ARO liability balance, December 31, 2019
$
132.1
Liabilities incurred
3.1
Liabilities settled
( 0.2
)
Revisions in estimated cash flows
4.1
Accretion expense
4.0
ARO liability balance, June 30, 2020
$
143.1


11

ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Note 5.  Investments in Unconsolidated Affiliates

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


June 30,
2020
December 31,
2019
NGL Pipelines & Services
$
685.9
$
703.8
Crude Oil Pipelines & Services
1,828.7
1,866.5
Natural Gas Pipelines & Services
28.5
27.3
Petrochemical & Refined Products Services
4.3
2.6
Total
$
2,547.4
$
2,600.2

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

For the Three Months
Ended June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
NGL Pipelines & Services
$
28.8
$
26.7
$
61.5
$
56.8
Crude Oil Pipelines & Services
84.1
111.0
191.4
235.6
Natural Gas Pipelines & Services
1.3
1.6
2.9
3.3
Petrochemical & Refined Products Services
( 0.9
)
( 1.9
)
( 1.7
)
( 3.7
)
Total
$
113.3
$
137.4
$
254.1
$
292.0


12

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:

June 30, 2020
December 31, 2019
Gross
Value
Accumulated
Amortization
Carrying
Value
Gross
Value
Accumulated
Amortization
Carrying
Value
NGL Pipelines & Services:
Customer relationship intangibles
$
447.8
$
( 213.4
)
$
234.4
$
447.8
$
( 206.3
)
$
241.5
Contract-based intangibles
162.6
( 49.6
)
113.0
162.6
( 43.9
)
118.7
Segment total
610.4
( 263.0
)
347.4
610.4
( 250.2
)
360.2
Crude Oil Pipelines & Services:
Customer relationship intangibles
2,203.5
( 274.8
)
1,928.7
2,203.5
( 243.5
)
1,960.0
Contract-based intangibles
283.5
( 243.4
)
40.1
276.9
( 235.0
)
41.9
Segment total
2,487.0
( 518.2
)
1,968.8
2,480.4
( 478.5
)
2,001.9
Natural Gas Pipelines & Services:
Customer relationship intangibles
1,350.3
( 497.2
)
853.1
1,350.3
( 481.6
)
868.7
Contract-based intangibles
468.0
( 399.7
)
68.3
468.0
( 395.5
)
72.5
Segment total
1,818.3
( 896.9
)
921.4
1,818.3
( 877.1
)
941.2
Petrochemical & Refined Products Services:
Customer relationship intangibles
181.4
( 60.7
)
120.7
181.4
( 57.5
)
123.9
Contract-based intangibles
46.0
( 24.9
)
21.1
46.0
( 24.2
)
21.8
Segment total
227.4
( 85.6
)
141.8
227.4
( 81.7
)
145.7
Total intangible assets
$
5,143.1
$
( 1,763.7
)
$
3,379.4
$
5,136.5
$
( 1,687.5
)
$
3,449.0

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

For the Three Months
Ended June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
NGL Pipelines & Services
$
6.3
$
9.0
$
12.8
$
18.1
Crude Oil Pipelines & Services
18.8
24.1
39.7
46.1
Natural Gas Pipelines & Services
9.6
10.0
19.8
20.9
Petrochemical & Refined Products Services
1.9
2.2
3.9
4.4
Total
$
36.6
$
45.3
$
76.2
$
89.5

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
$
85.0
$
167.6
$
164.5
$
162.9
$
159.3

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 Form 10-K.

13

ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 7.  Debt Obligations

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

June 30,
2020
December 31,
2019
EPO senior debt obligations:
Commercial Paper Notes, variable-rates
$
–
$
482.0
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
Senior Notes RR, 2.85 % fixed-rate, due April 2021
575.0
575.0
April 2020 364-Day Revolving Credit Agreement, variable-rate, due April 2021
–
–
Senior Notes VV, 3.50 % fixed-rate, due February 2022
750.0
750.0
Senior Notes CC, 4.05 % fixed-rate, due February 2022
650.0
650.0
Senior Notes HH, 3.35 % fixed-rate, due March 2023
1,250.0
1,250.0
Senior Notes JJ, 3.90 % fixed-rate, due February 2024
850.0
850.0
Multi-Year Revolving Credit Agreement, variable-rate, due September 2024
–
–
Senior Notes MM, 3.75 % fixed-rate, due February 2025
1,150.0
1,150.0
Senior Notes PP, 3.70 % fixed-rate, due February 2026
875.0
875.0
Senior Notes SS, 3.95 % fixed-rate, due February 2027
575.0
575.0
Senior Notes WW, 4.15 % fixed-rate, due October 2028
1,000.0
1,000.0
Senior Notes YY, 3.125 % fixed-rate, due July 2029
1,250.0
1,250.0
Senior Notes AAA, 2.80 % fixed-rate, due January 2030
1,000.0
–
Senior Notes D, 6.875 % fixed-rate, due March 2033
500.0
500.0
Senior Notes H, 6.65 % fixed-rate, due October 2034
350.0
350.0
Senior Notes J, 5.75 % fixed-rate, due March 2035
250.0
250.0
Senior Notes W, 7.55 % fixed-rate, due April 2038
399.6
399.6
Senior Notes R, 6.125 % fixed-rate, due October 2039
600.0
600.0
Senior Notes Z, 6.45 % fixed-rate, due September 2040
600.0
600.0
Senior Notes BB, 5.95 % fixed-rate, due February 2041
750.0
750.0
Senior Notes DD, 5.70 % fixed-rate, due February 2042
600.0
600.0
Senior Notes EE, 4.85 % fixed-rate, due August 2042
750.0
750.0
Senior Notes GG, 4.45 % fixed-rate, due February 2043
1,100.0
1,100.0
Senior Notes II, 4.85 % fixed-rate, due March 2044
1,400.0
1,400.0
Senior Notes KK, 5.10 % fixed-rate, due February 2045
1,150.0
1,150.0
Senior Notes QQ, 4.90 % fixed-rate, due May 2046
975.0
975.0
Senior Notes UU, 4.25 % fixed-rate, due February 2048
1,250.0
1,250.0
Senior Notes XX, 4.80 % fixed-rate, due February 2049
1,250.0
1,250.0
Senior Notes ZZ, 4.20 % fixed-rate, due January 2050
1,250.0
1,250.0
Senior Notes BBB, 3.70 % fixed-rate, due January 2051
1,000.0
–
Senior Notes NN, 4.95 % fixed-rate, due October 2054
400.0
400.0
Senior Notes CCC, 3.95 % fixed rate, due January 2060
1,000.0
–
TEPPCO senior debt obligations:
TEPPCO Senior Notes, 7.55 % fixed-rate, due April 2038
0.4
0.4
Total principal amount of senior debt obligations
27,250.0
25,232.0
EPO Junior Subordinated Notes C, variable-rate, due June 2067 (1)
232.2
232.2
EPO Junior Subordinated Notes D, fixed/variable-rate, due August 2077 (2)
700.0
700.0
EPO Junior Subordinated Notes E, fixed/variable-rate, due August 2077 (3)
1,000.0
1,000.0
EPO Junior Subordinated Notes F, fixed/variable-rate, due February 2078 (4)
700.0
700.0
TEPPCO Junior Subordinated Notes, variable-rate, due June 2067 (1)
14.2
14.2
Total principal amount of senior and junior debt obligations
29,896.4
27,878.4
Other, non-principal amounts
( 286.2
)
( 253.3
)
Less current maturities of debt
( 2,325.0
)
( 1,981.9
)
Total long-term debt
$
27,285.2
$
25,643.2

(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.
14

ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


The following table presents the range of interest rates and weighted-average interest rates paid on our consolidated variable-rate debt during the six months ended June 30, 2020:

Range of Interest
Rates Paid
Weighted-Average
Interest Rate Paid
Commercial Paper Notes
1.78 % to 2.08 %
1.86 %
EPO Junior Subordinated Notes C and TEPPCO Junior Subordinated Notes
3.13 % to 4.68 %
4.26 %

Amounts borrowed under EPO’s 364-Day and Multi-Year Revolving Credit Agreements bear interest, at 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 EPO's debt ratings.

The following table presents the scheduled contractual maturities of principal amounts of our consolidated debt obligations at June 30, 2020 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

Expected Renewal of September 2019 364-Day Revolving Credit Agreement

EPO’s September 2019 364-Day Revolving Credit Agreement is scheduled to mature in September 2020.  As a result, EPO expects to renew this credit agreement during the third quarter of 2020.  At June 30, 2020, there were no principal amounts outstanding under the September 2019 364-Day Revolving Credit Agreement.

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 Revolving Credit Agreement ”). The new agreement provides EPO with an incremental $ 1.0 billion of borrowing capacity, thereby increasing its overall borrowing capacity under its revolving credit agreements to $ 6.0 billion. Under the terms of the April 2020 364-Day Revolving 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 Revolving Credit Agreement for working capital, capital expenditures, acquisitions and other company purposes.

Senior Notes Offering 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.

See Note 19 for a subsequent event involving the reopening of Senior Notes AAA and the issuance of $ 1.25 billion aggregate principal amount of new senior notes in August 2020.
15

ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Lender Financial Covenants

We were in compliance with the financial covenants of our consolidated debt agreements at June 30, 2020.

Letters of Credit

At June 30, 2020, EPO had $ 150.7 million of letters of credit outstanding primarily related to our commodity hedging activities.

Parent-Subsidiary Guarantor Relationships

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


Note 8.  Equity and Distributions

Partners’ Equity

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

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 issued in connection with the vesting of phantom unit awards, net
96,190
–
Units outstanding at June 30, 2020
2,185,896,433
54,807,352

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

In addition, EPD has a registration statement on file with the SEC covering the issuance of up to $ 2.54 billion of its common units in amounts, at prices and on terms to be determined by market conditions and other factors at the time of such offerings in connection with its at-the-market (“ATM”) program.  During the six months ended June 30, 2020 and 2019 , EPD did not issue any common units under its ATM program. After taking into account the aggregate sales price of common units sold under the ATM program through June 30, 2020, EPD has the capacity to issue additional common units under its ATM program up to an aggregate sales price of $ 2.54 billion.

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

16

ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


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, OTA Holdings, Inc., a Delaware corporation previously named 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 five registration statements and underwritten offerings.  In May 2020, we filed a registration statement on behalf of Skyline for the resale of up to 54,807,352 EPD common units. This registration statement is effective and, in June 2020, we filed a prospectus supplement to this registration statement that allows Skyline to sell up to $ 500 million of the EPD common units it owns in connection with an “at-the-market” program that it administers.   We will not receive any proceeds from such offerings.

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 , t he 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 with an additional method to return capital to investors. The 2019 Buyback Program authorizes EPD to repurchase its common units from time to time, including through open market purchases and negotiated transactions.  The timing and pace of buy backs under the program will be determined by a number of factors including (i) our financial performance and flexibility, (ii) organic growth and acquisition opportunities with higher potential returns on investment, (iii) EPD’s unit price and implied cash flow yield and (iv) maintaining targeted financial leverage with a debt-to-normalized adjusted EBITDA (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.
17

ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


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 2019 Buyback Program.  EPD repurchased 6,357,739 common units under the 2019 Buyback Program through open market purchases during the six months ended June 30, 2020 .  The total purchase price of these repurchases (including commissions and fees) was $ 140.1 million. During the six months ended June 30, 2019 , EPD repurchased 2,909,128 common units under the 2019 Buyback Program for a total purchase price of $ 81.1 million. The units repurchased during the six months ended June 30, 2020 and 2019 were immediately cancelled upon acquisition.  At June 30, 2020, the remaining available capacity under the 2019 Buyback Program was $ 1.78 billion.

Common Units Issued in Connection With the Vesting of Phantom Unit Awards
During the six months ended June 30, 2020 , after taking into account tax withholding requirements, EPD issued a net 3,008,404 new common units to employees in connection with the vesting of phantom unit awards.  See Note 13 for information regarding our phantom unit awards.

Common Units Delivered Under DRIP and EUPP
EPD has registration statements on file with the SEC in connection with its distribution reinvestment plan (“DRIP”) and employee unit purchase plan (“EUPP”). In July 2019, EPD 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 need for equity capital.  During the six months ended June 30, 2020, a total of 3,379,971 common units were purchased on the open market and delivered to participants in connection with the DRIP and EUPP.  Apart from $ 1.3 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 August 12, 2020.

Accumulated Other Comprehensive Income (Loss)

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

Cash Flow Hedges
Commodity
Derivative
Instruments
Interest Rate
Derivative
Instruments
Other
Total
Accumulated Other Comprehensive Income, December 31, 2019
$
55.1
$
13.9
$
2.4
$
71.4
Other comprehensive income (loss) for period, before reclassifications
396.9
( 284.2
)
( 0.1
)
112.6
Reclassification of losses (gains) to net income during period
( 364.3
)
33.2
–
( 331.1
)
Total other comprehensive income (loss) for period
32.6
( 251.0
)
( 0.1
)
( 218.5
)
Accumulated Other Comprehensive Income (Loss), June 30, 2020
$
87.7
$
( 237.1
)
$
2.3
$
( 147.1
)

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

18

ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


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

For the Three Months
Ended June 30,
For the Six Months
Ended June 30,
Losses (gains) on cash flow hedges:
Location
2020
2019
2020
2019
Interest rate derivatives
Interest expense
$
9.7
$
9.2
$
33.2
$
18.4
Commodity derivatives
Revenue
( 209.8
)
( 2.5
)
( 364.2
)
( 67.8
)
Commodity derivatives
Operating costs and expenses
1.1
0.3
( 0.1
)
7.3
Total
$
( 199.0
)
$
7.0
$
( 331.1
)
$
( 42.1
)

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

Cash Distributions

On July 7, 2020, we announced that the Board declared a quarterly cash distribution to be paid to our limited partners with respect to the second quarter of 2020 of $ 0.4450 per common unit, or $ 1.78 per unit on an annualized basis.  The quarterly distribution associated with the second quarter of 2020 is payable on August 12, 2020, to unitholders of record as of the close of business on July 31, 2020.  This distribution represents a 1.1 % increase over the distribution declared with respect to the second 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.






19

ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Note 9.  Revenues

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

For the Three Months
Ended June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
NGL Pipelines & Services:
Sales of NGLs and related products
$
1,934.1
$
2,659.4
$
4,353.3
$
5,330.6
Segment midstream services:
Natural gas processing and fractionation
181.9
288.2
370.4
557.7
Transportation
249.9
243.9
514.9
519.2
Storage and terminals
110.4
93.2
205.8
191.6
Total segment midstream services
542.2
625.3
1,091.1
1,268.5
Total NGL Pipelines & Services
2,476.3
3,284.7
5,444.4
6,599.1
Crude Oil Pipelines & Services:
Sales of crude oil
1,146.7
2,531.7
2,843.6
4,860.1
Segment midstream services:
Transportation
195.8
205.3
414.2
389.0
Storage and terminals
120.7
129.6
244.3
224.8
Total segment midstream services
316.5
334.9
658.5
613.8
Total Crude Oil Pipelines & Services
1,463.2
2,866.6
3,502.1
5,473.9
Natural Gas Pipelines & Services:
Sales of natural gas
347.7
531.4
746.9
1,187.1
Segment midstream services:
Transportation
237.5
287.9
508.9
559.7
Total segment midstream services
237.5
287.9
508.9
559.7
Total Natural Gas Pipelines & Services
585.2
819.3
1,255.8
1,746.8
Petrochemical & Refined Products Services:
Sales of petrochemicals and refined products
1,030.0
1,087.7
2,627.5
2,568.3
Segment midstream services:
Fractionation, and isomerization
38.6
41.5
74.4
82.3
Transportation, including marine logistics
115.4
132.2
250.3
258.8
Storage and terminals
42.3
44.3
79.0
90.6
Total segment midstream services
196.3
218.0
403.7
431.7
Total Petrochemical & Refined Products Services
1,226.3
1,305.7
3,031.2
3,000.0
Total consolidated revenues
$
5,751.0
$
8,276.3
$
13,233.5
$
16,819.8

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 June 30, 2020:

Contract Asset
Location
Balance
Unbilled revenue (current amount)
Prepaid and other current assets
$
151.5
Total
$
151.5

Contract Liability
Location
Balance
Deferred revenue (current amount)
Other current liabilities
$
136.0
Deferred revenue (noncurrent)
Other long-term liabilities
213.8
Total
$
349.8

20

ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


The following table presents significant changes in our unbilled revenue and deferred revenue balances during the six months ended June 30, 2020:

Unbilled
Revenue
Deferred
Revenue
Balance at December 31, 2019
$
17.6
$
314.9
Amount included in opening balance transferred to other accounts during period (1)
( 4.2
)
( 85.5
)
Amount recorded during period
160.1
315.1
Amounts recorded during period transferred to other accounts (1)
( 22.0
)
( 191.3
)
Other changes
–
( 3.4
)
Balance at June 30, 2020
$
151.5
$
349.8

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

Remaining Performance Obligations

The following table presents estimated fixed future consideration from 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 June 30, 2020.

Period
Fixed
Consideration
Six Months Ended December 31, 2020
$
1,980.1
One Year Ended December 31, 2021
3,741.3
One Year Ended December 31, 2022
3,350.2
One Year Ended December 31, 2023
3,057.1
One Year Ended December 31, 2024
2,866.6
Thereafter
14,626.2
Total
$
29,621.5



21

ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Note 10.  Business Segments and Related Information

Our operations are reported under four business segments: (i) NGL Pipelines & Services, (ii) Crude Oil Pipelines & Services, (iii) Natural Gas Pipelines & Services and (iv) Petrochemical & Refined Products Services.

Segment Gross Operating Margin

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

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

For the Three Months
Ended June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
Operating income
$
1,436.9
$
1,560.3
$
2,944.4
$
3,186.5
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
494.3
462.8
977.1
913.7
Asset impairment and related charges in operating costs and expenses
11.8
7.0
13.4
11.8
Net gains attributable to asset sales in operating costs and expenses
( 1.6
)
( 2.1
)
( 1.5
)
( 2.5
)
General and administrative costs
57.0
52.5
112.5
104.7
N on-refundable payments received from shippers attributable to make-up rights (1)
13.0
11.3
29.8
13.5
Subsequent recognition of revenues attributable to make-up rights (2)
( 8.5
)
( 5.6
)
( 15.6
)
( 13.1
)
Total segment gross operating margin
$
2,002.9
$
2,086.2
$
4,060.1
$
4,214.6

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

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

For the Three Months
Ended June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
Gross operating margin by segment:
NGL Pipelines & Services
$
968.1
$
966.3
$
2,010.1
$
1,925.5
Crude Oil Pipelines & Services
634.4
513.2
1,087.3
1,175.5
Natural Gas Pipelines & Services
208.9
301.8
492.7
566.1
Petrochemical & Refined Products Services
191.5
304.9
470.0
547.5
Total segment gross operating margin
$
2,002.9
$
2,086.2
$
4,060.1
$
4,214.6

22

ENTERPRISE PRODUCTS PARTNERS L.P.
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 June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
Mark-to-market gains (losses) in gross operating margin:
NGL Pipelines & Services
$
35.7
$
( 0.7
)
$
23.4
$
0.6
Crude Oil Pipelines & Services
8.1
( 14.6
)
18.8
85.2
Natural Gas Pipelines & Services
( 4.0
)
0.3
24.8
–
Petrochemical & Refined Products Services
22.1
2.5
24.4
( 2.0
)
Total mark-to-market impact on gross operating margin
$
61.9
$
( 12.5
)
$
91.4
$
83.8

For information regarding our hedging activities, see Note 14.

Summarized Segment Financial Information

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

Reportable Business Segments
NGL
Pipelines
& Services
Crude Oil
Pipelines
& Services
Natural Gas
Pipelines
& Services
Petrochemical
& Refined Products Services
Adjustments
and
Eliminations
Consolidated
Total
Revenues from third parties:
Three months ended June 30, 2020
$
2,474.7
$
1,461.3
$
583.0
$
1,226.3
$
–
$
5,745.3
Three months ended June 30, 2019
3,282.2
2,847.0
815.6
1,305.7
–
8,250.5
Six months ended June 30, 2020
5,441.0
3,489.0
1,250.6
3,031.2
–
13,211.8
Six months ended June 30, 2019
6,593.8
5,448.6
1,739.3
3,000.0
–
16,781.7
Revenues from related parties:
Three months ended June 30, 2020
1.6
1.9
2.2
–
–
5.7
Three months ended June 30, 2019
2.5
19.6
3.7
–
–
25.8
Six months ended June 30, 2020
3.4
13.1
5.2
–
–
21.7
Six months ended June 30, 2019
5.3
25.3
7.5
–
–
38.1
Intersegment and intrasegment revenues:
Three months ended June 30, 2020
5,947.7
4,039.9
92.9
709.7
( 10,790.2
)
–
Three months ended June 30, 2019
4,494.8
9,453.3
163.1
617.9
( 14,729.1
)
–
Six months ended June 30, 2020
11,728.4
11,880.2
208.0
1,517.8
( 25,334.4
)
–
Six months ended June 30, 2019
9,986.2
17,338.3
358.5
1,332.3
( 29,015.3
)
–
Total revenues:
Three months ended June 30, 2020
8,424.0
5,503.1
678.1
1,936.0
( 10,790.2
)
5,751.0
Three months ended June 30, 2019
7,779.5
12,319.9
982.4
1,923.6
( 14,729.1
)
8,276.3
Six months ended June 30, 2020
17,172.8
15,382.3
1,463.8
4,549.0
( 25,334.4
)
13,233.5
Six months ended June 30, 2019
16,585.3
22,812.2
2,105.3
4,332.3
( 29,015.3
)
16,819.8
Equity in income (loss) of unconsolidated affiliates:
Three months ended June 30, 2020
28.8
84.1
1.3
( 0.9
)
–
113.3
Three months ended June 30, 2019
26.7
111.0
1.6
( 1.9
)
–
137.4
Six months ended June 30, 2020
61.5
191.4
2.9
( 1.7
)
–
254.1
Six months ended June 30, 2019
56.8
235.6
3.3
( 3.7
)
–
292.0

Segment revenues include intersegment and intrasegment transactions, which are generally based on transactions made at market-based rates.  Our consolidated revenues reflect the elimination of intercompany transactions.  Substantially all of our consolidated revenues are earned in the U.S. and derived from a wide customer base.
23

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 June 30, 2020
$
16,885.9
$
6,412.8
$
8,429.7
$
7,530.6
$
3,279.4
$
42,538.4
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 June 30, 2020
685.9
1,828.7
28.5
4.3
–
2,547.4
At December 31, 2019
703.8
1,866.5
27.3
2.6
–
2,600.2
Intangible assets, net: (see Note 6)
At June 30, 2020
347.4
1,968.8
921.4
141.8
–
3,379.4
At December 31, 2019
360.2
2,001.9
941.2
145.7
–
3,449.0
Goodwill: (see Note 6)
At June 30, 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 June 30, 2020
20,570.9
12,051.3
9,675.9
8,632.9
3,279.4
54,210.4
At December 31, 2019
20,367.8
12,033.8
9,697.3
8,657.7
2,641.2
53,397.8

Supplemental Revenue and Expense Information

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

For the Three Months
Ended June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
Consolidated revenues:
NGL Pipelines & Services
$
2,476.3
$
3,284.7
$
5,444.4
$
6,599.1
Crude Oil Pipelines & Services
1,463.2
2,866.6
3,502.1
5,473.9
Natural Gas Pipelines & Services
585.2
819.3
1,255.8
1,746.8
Petrochemical & Refined Products Services
1,226.3
1,305.7
3,031.2
3,000.0
Total consolidated revenues
$
5,751.0
$
8,276.3
$
13,233.5
$
16,819.8
Consolidated costs and expenses
Operating costs and expenses:
Cost of sales
$
3,195.2
$
5,609.4
$
8,018.2
$
11,445.0
Other operating costs and expenses (1)
670.7
723.8
1,423.5
1,452.6
Depreciation, amortization and accretion
494.3
462.8
977.1
913.7
Asset impairment and related charges
11.8
7.0
13.4
11.8
Ne t gains attributable to asset sales
( 1.6
)
( 2.1
)
( 1.5
)
( 2.5
)
General and administrative costs
57.0
52.5
112.5
104.7
Total consolidated costs and expenses
$
4,427.4
$
6,853.4
$
10,543.2
$
13,925.3

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

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

24

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 six months ended June 30, 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 reflects 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 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 six months ended June 30, 2020 .

The deferred tax liability of OTA is subject to fluctuation due to changes in the market value of the EPD common units it owns relative to its underlying tax basis in the units.  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.  The following table presents changes in OTA’s deferred tax liability since the settlement date of March 5, 2020 to June 30, 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)
$
( 301.4
)
Multiplied by estimated blended federal and state tax rate
22.4
%
( 67.4
)
Other, including interim allocations of taxable income
2.9
Deferred tax liability at June 30, 2020
$
375.2

(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 $ 18.17 per unit on June 30, 2020.

As presented in the preceding table, OTA recognized a net deferred income tax benefit of $ 64.5 million through June 30, 2020 primarily due to a decrease in the market value of its investment in EPD common units since March 5, 2020. With respect to the second quarter of 2020, OTA recognized deferred income tax expense of $ 50.5 million primarily due to an increase in the market value of its investment in EPD common units since March 31, 2020.   The market price of EPD common units increased from $ 14.30 per unit at March 31, 2020 to $ 18.17 per unit on June 30, 2020.  In total, earnings for the six months ended June 30, 2020 reflect a net $ 136.7 million of deferred income tax benefit attributable to OTA.
25

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 June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
Current portion of income tax provision (benefit):
Federal
$
2.2
$
( 0.4
)
$
2.3
$
0.5
State
4.1
7.5
8.7
16.5
Foreign
–
0.2
0.2
0.8
Total current portion
6.3
7.3
11.2
17.8
Deferred portion of income tax provision (benefit):
Federal
46.4
–
( 126.4
)
( 0.1
)
State
7.0
2.6
( 4.3
)
4.5
Foreign
–
( 0.2
)
–
( 0.2
)
Total deferred portion
53.4
2.4
( 130.7
)
4.2
Total provision for (benefit from) income taxes
$
59.7
$
9.7
$
( 119.5
)
$
22.0

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 June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
Pre-Tax Net Book Income (“NBI”)
$
1,120.5
$
1,246.2
$
2,316.3
$
2,538.9
Texas Margin Tax (1)
7.0
10.1
14.7
21.0
State income tax provision (benefit), net of federal benefit (2)
3.2
0.1
( 8.1
)
0.3
Federal income tax provision (benefit) computed by applying
the federal statutory rate to NBI of corporate entities
49.5
( 0.5
)
( 58.3
)
0.7
Federal benefit attributable to settlement of
Liquidity Option (2)
–
–
( 67.8
)
–
Provision for (benefit from) income taxes
$
59.7
$
9.7
$
( 119.5
)
$
22.0
Effective income tax rate
5.3
%
0.8
%
( 5.2
)%
0.9
%

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

26

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:

June 30,
December 31,
2020
2019
Deferred tax liabilities:
Attributable to investment in OTA
$
375.2
Attributable to property, plant and equipment
105.6
$
100.2
Attributable to investments in other entities
3.4
3.3
Total deferred tax liabilities
484.2
103.5
Less deferred tax assets:
Net operating loss carryovers (1)
0.1
0.1
Temporary differences related to Texas Margin Tax
2.5
3.0
Total deferred tax assets
2.6
3.1
Total net deferred tax liabilities
$
481.6
$
100.4

(1)
These losses expire in various years between 2020 and 2037 and are subject to limitations on their utilization.


Note 12.  Earnings Per Unit

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

For the Three Months
Ended June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
BASIC EARNINGS PER UNIT
Net income attributable to limited partners
$
1,034.7
$
1,214.7
$
2,384.8
$
2,475.2
Earnings allocated to phantom unit awards (1)
( 7.5
)
( 7.4
)
( 17.4
)
( 15.2
)
Net income available to common unitholders
$
1,027.2
$
1,207.3
$
2,367.4
$
2,460.0
Basic weighted-average number of common units outstanding
2,185.9
2,189.1
2,187.4
2,188.1
Basic earnings per unit
$
0.47
$
0.55
$
1.08
$
1.12
DILUTED EARNINGS PER UNIT
Net income attributable to limited partners
$
1,034.7
$
1,214.7
$
2,384.8
$
2,475.2
Diluted weighted-average number of units outstanding:
Distribution-bearing common units
2,185.9
2,189.1
2,187.4
2,188.1
Phantom units (1)
16.0
13.5
15.6
13.0
Total
2,201.9
2,202.6
2,203.0
2,201.1
Diluted earnings per unit
$
0.47
$
0.55
$
1.08
$
1.12

(1)
Phantom units are considered participating securities for purposes of computing basic earnings per unit. See Note 13 for information regarding our phantom units.


27

ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Note 13.  Equity-Based Awards

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

For the Three Months
Ended June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
Equity-classified awards:
Phantom unit awards
$
39.6
$
35.5
$
75.8
$
64.9
Profits interest awards
2.1
3.0
5.0
5.6
Total
$
41.7
$
38.5
$
80.8
$
70.5

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

Phantom Unit Awards

Subject to customary forfeiture provisions, phantom unit awards allow recipients to acquire EPD 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)
Phantom unit awards at December 31, 2019
12,974,684
$
27.21
Granted (2)
7,400,345
$
25.72
Vested
( 4,333,916
)
$
26.34
Forfeited
( 63,539
)
$
26.82
Phantom unit awards at June 30, 2020
15,977,574
$
26.76

(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 was $ 190.3 million based on a grant date market price of EPD common units ranging from $ 17.24 to $ 25.76 per unit.  An estimated annual forfeiture rate of 2.4 % was applied to these awards.

Each phantom unit award includes a distribution equivalent right (“ 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 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 June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
Cash payments made in connection with DERs
$
7.1
$
6.0
$
12.9
$
10.5
Total intrinsic value of phantom unit awards that vested during period
2.2
4.7
111.4
101.7

For the EPCO group of companies, the unrecognized compensation cost associated with phantom unit awards was $ 237.1 million at June 30, 2020, of which our share of such cost is currently estimated to be $ 202.0 million.  Due to the graded vesting provisions of these awards, we expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 2.2 years.
28

ENTERPRISE PRODUCTS PARTNERS L.P.
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 June 30, 2020 , our share of the total unrecognized compensation cost related to the four remaining Employee Partnerships was $ 18.9 million, which we expect to recognize over a weighted-average period of 3.1 years.


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

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

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 of 30-year forward-starting swaps at June 30, 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 first quarter of 2020.

In total, the notional amount of forward-starting swaps outstanding at June 30, 2020 was $ 1.08 billion.  The weighted-average fixed interest rate of these derivative instruments is 1.83 %.

In January 2020, we terminated an aggregate $ 575 million notional amount of forward-starting swaps, which resulted in net cash payments of $ 33.3 million.  These swaps were unwound in connection with our issuance of Senior Notes BBB due January 2051.

29

ENTERPRISE PRODUCTS PARTNERS L.P.
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 June 30, 2020, 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.

The following table summarizes our portfolio of commodity derivative instruments outstanding at June 30, 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 (billion cubic feet (“Bcf”))
12.7
n/a
Cash flow hedge
Forecasted sales of NGLs (million barrels (“MMBbls”))
0.1
n/a
Cash flow hedge
Octane enhancement:
Forecasted purchase of NGLs (MMBbls)
0.6
n/a
Cash flow hedge
Forecasted sales of octane enhancement products (MMBbls)
8.9
n/a
Cash flow hedge
Natural gas marketing:
Forecasted purchase of natural gas (Bcf)
1.8
n/a
Cash flow hedge
Natural gas storage inventory management activities (Bcf)
5.9
n/a
Fair value hedge
NGL marketing:
Forecasted purchases of NGLs and related hydrocarbon products (MMBbls)
157.9
4.6
Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products (MMBbls)
162.4
15.6
Cash flow hedge
NGLs inventory management activities (MMBbls)
1.8
n/a
Fair value hedge
Refined products marketing:
Forecasted purchases of refined products (MMBbls)
46.8
15.4
Cash flow hedge
Forecasted sales of refined products (MMBbls)
52.5
18.7
Cash flow hedge
Refined products inventory management activities (MMBbls)
3.9
n/a
Fair value hedge
Crude oil marketing:
Forecasted purchases of crude oil (MMBbls)
78.2
n/a
Cash flow hedge
Forecasted sales of crude oil (MMBbls)
88.7
n/a
Cash flow hedge
Petrochemical marketing:
Forecasted sales of petrochemical products (MMBbls)
1.2
n/a
Cash flow hedge
Commercial energy:
Forecasted purchases of power related to asset operations (terawatt hours (“TWh”))
0.3
n/a
Cash flow hedge
Derivatives not designated as hedging instruments:
Natural gas risk management activities (Bcf) (3,4)
44.2
2.1
Mark-to-market
NGL risk management activities (MMBbls) (4)
21.4
8.4
Mark-to-market
Refined products risk management activities (MMBbls) (4)
4.0
n/a
Mark-to-market
Crude oil risk management activities (MMBbls) (4)
28.8
7.7
Mark-to-market
Commercial energy risk management activities (TWh) (4)
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, March 2021 and December 2022, respectively.
(3)
Current volumes include approximately 0.7 Bcf of physical derivatives instruments that are predominantly priced as index plus a premium or minus a discount.
(4)
Reflects the use of derivative instruments to manage risks associated with our transportation, processing, storage assets and end use power requirements.

The carrying amount of our inventories subject to fair value hedges was $ 233.8 million and $ 31.7 million at June 30, 2020 and December 31, 2019, respectively.

30

ENTERPRISE PRODUCTS PARTNERS L.P.
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
June 30, 2020
December 31, 2019
June 30, 2020
December 31, 2019
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
$
200.6
Current
liabilities
$
6.7
Interest rate derivatives
Other assets
–
Other assets
–
Other liabilities
49.9
Other liabilities
6.8
Total interest rate derivatives
–
–
250.5
13.5
Commodity derivatives
Current assets
165.3
Current assets
116.5
Current
liabilities
168.2
Current
liabilities
107.1
Commodity derivatives
Other assets
1.8
Other assets
–
Other liabilities
10.2
Other liabilities
–
Total commodity derivatives
167.1
116.5
178.4
107.1
Total derivatives designated as hedging instruments
$
167.1
$
116.5
$
428.9
$
120.6
Derivatives not designated as hedging instruments
Commodity derivatives
Current assets
$
44.4
Current assets
$
10.7
Current
liabilities
$
16.6
Current
liabilities
$
8.6
Commodity derivatives
Other assets
3.5
Other assets
0.6
Other liabilities
1.7
Other liabilities
0.5
Total commodity derivatives
47.9
11.3
18.3
9.1
Total derivatives not designated as hedging instruments
$
47.9
$
11.3
$
18.3
$
9.1

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

Offsetting of Financial Assets and Derivative Assets
Gross
Amounts of
Recognized
Assets
Gross
Amounts
Offset in the
Balance Sheet
Amounts
of Assets
Presented
in the
Balance Sheet
Gross Amounts Not Offset
in the Balance Sheet
Amounts That
Would Have
Been Presented
On Net Basis
Financial
Instruments
Cash
Collateral
Received
Cash
Collateral
Paid
(i)
(ii)
(iii) = (i) – (ii)
(iv)
(v) = (iii) + (iv)
As of June 30, 2020:
Commodity derivatives
$
215.0
$
–
$
215.0
$
( 188.6
)
$
–
$
( 24.0
)
$
2.4
As of December 31, 2019:
Commodity derivatives
$
127.8
$
–
$
127.8
$
( 115.3
)
$
–
$
( 11.0
)
$
1.5


Offsetting of Financial Liabilities and Derivative Liabilities
Gross
Amounts of
Recognized
Liabilities
Gross
Amounts
Offset in the
Balance Sheet
Amounts
of Liabilities
Presented
in the
Balance Sheet
Gross Amounts Not Offset
in the Balance Sheet
Amounts That
Would Have
Been Presented
On Net Basis
Financial
Instruments
Cash
Collateral
Received
Cash
Collateral
Paid
(i)
(ii)
(iii) = (i) – (ii)
(iv)
(v) = (iii) + (iv)
As of June 30, 2020:
Interest rate derivatives
$
250.5
$
–
$
250.5
$
–
$
–
$
–
$
250.5
Commodity derivatives
196.7
–
196.7
( 188.6
)
–
–
8.1
As of December 31, 2019:
Interest rate derivatives
$
13.5
$
–
$
13.5
$
–
$
–
$
–
$
13.5
Commodity derivatives
116.2
–
116.2
( 115.3
)
–
–
0.9
31

ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


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

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

Derivatives in Fair Value
Hedging Relationships
Location
Gain (Loss) Recognized in
Income on Derivative
For the Three Months
Ended June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
Interest rate derivatives
Interest expense
$
–
$
–
$
–
$
–
Commodity derivatives
Revenue
( 63.7
)
6.9
( 49.3
)
( 1.6
)
Total
$
( 63.7
)
$
6.9
$
( 49.3
)
$
( 1.6
)

Derivatives in Fair Value
Hedging Relationships
Location
Gain (Loss) Recognized in
Income on Hedged Item
For the Three Months
Ended June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
Interest rate derivatives
Interest expense
$
–
$
–
$
–
$
–
Commodity derivatives
Revenue
126.7
( 3.6
)
117.3
6.3
Total
$
126.7
$
( 3.6
)
$
117.3
$
6.3

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

Derivatives in Cash Flow
Hedging Relationships
Change in Value Recognized in
Other Comprehensive Income (Loss) on Derivative
For the Three Months
Ended June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
Interest rate derivatives
$
7.8
$
( 5.2
)
$
( 284.2
)
$
( 5.2
)
Commodity derivatives – Revenue (1)
( 75.9
)
84.3
401.9
( 2.4
)
Commodity derivatives – Operating costs and expenses (1)
( 2.3
)
( 2.8
)
( 5.0
)
( 11.3
)
Total
$
( 70.4
)
$
76.3
$
112.7
$
( 18.9
)

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

Derivatives in Cash Flow
Hedging Relationships
Location
Gain (Loss) Reclassified from
Accumulated Other Comprehensive Income (Loss) to Income
For the Three Months
Ended June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
Interest rate derivatives
Interest expense
$
( 9.7
)
$
( 9.2
)
$
( 33.2
)
$
( 18.4
)
Commodity derivatives
Revenue
209.8
2.5
364.2
67.8
Commodity derivatives
Operating costs and expenses
( 1.1
)
( 0.3
)
0.1
( 7.3
)
Total
$
199.0
$
( 7.0
)
$
331.1
$
42.1


32

ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Over the next twelve months, we expect to reclassify $ 40.3 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 $ 128.0 million of gains attributable to commodity derivative instruments from accumulated other comprehensive income to earnings, $ 132.5 million as an increase in revenue and $ 4.5 million as an increase in operating costs and expenses.

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

Derivatives Not Designated
as Hedging Instruments
Location
Gain (Loss) Recognized in
Income on Derivative
For the Three Months
Ended June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
Interest rate derivatives
Interest expense
$
–
$
–
$
–
$
–
Commodity derivatives
Revenue
45.7
( 20.2
)
98.7
74.9
Commodity derivatives
Operating costs and expenses
0.9
( 4.8
)
0.8
( 4.7
)
Total
$
46.6
$
( 25.0
)
$
99.5
$
70.2

The $ 99.5 million gain recognized for the six months ended June 30, 2020 (as noted in the preceding table) from derivatives not designated as hedging instruments consists of $ 35.8 million of realized gains and $ 63.7 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.

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.
33

ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



At June 30, 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
$
999.1
$
635.9
$
28.9
$
1,663.9
Impact of CME Rule 814
( 973.4
)
( 451.5
)
( 24.0
)
( 1,448.9
)
Total commodity derivatives
25.7
184.4
4.9
215.0
Total
$
25.7
$
184.4
$
4.9
$
215.0
Financial liabilities:
Interest rate derivatives
$
–
$
250.5
$
–
$
250.5
Commodity derivatives:
Value before application of CME Rule 814
1,207.1
605.3
48.9
1,861.3
Impact of CME Rule 814
( 1,181.6
)
( 447.9
)
( 35.1
)
( 1,664.6
)
Total commodity derivatives
25.5
157.4
13.8
196.7
Total
$
25.5
$
407.9
$
13.8
$
447.2

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 June 30, 2020 was a net derivative liability of $ 197.4 million prior to the impact of CME Rule 814.

Financial assets and liabilities recorded on the balance sheet at June 30, 2020 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.

34

ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Nonrecurring Fair Value Measurements

Non-cash asset impairment charges for the six months ended June 30, 2020 were $ 13.4 million compared to $ 11.8 million for the six months ended June 30, 2019. Charges for 2020 primarily relate to assets retired during the quarter whose operations have ceased.  Impairment charges are a component of “Operating costs and expenses” on our Unaudited Condensed Statements of Consolidated Operations.

Other Fair Value Information

The carrying amounts of cash and cash equivalents (including restricted cash balances), accounts receivable, commercial paper notes and accounts payable approximate their fair values based on their short-term nature.  The estimated total fair value of our fixed-rate debt obligations was $ 33.03 billion and $ 30.37 billion at June 30, 2020 and December 31, 2019, respectively.  The aggregate carrying value of these debt obligations was $ 29.65 billion and $ 27.15 billion at June 30, 2020 and December 31, 2019, 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.  Related Party Transactions

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

For the Three Months
Ended June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
Revenues – related parties:
Unconsolidated affiliates
$
5.7
$
25.8
$
21.7
$
38.1
Costs and expenses – related parties:
EPCO and its privately held affiliates
$
277.1
$
267.2
$
563.1
$
540.1
Unconsolidated affiliates
62.6
95.3
134.1
218.6
Total
$
339.7
$
362.5
$
697.2
$
758.7

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

June 30,
2020
December 31,
2019
Accounts receivable - related parties:
Unconsolidated affiliates
$
2.6
$
2.5
Accounts payable - related parties:
EPCO and its privately held affiliates
$
78.4
$
143.7
Unconsolidated affiliates
10.9
18.6
Total
$
89.3
$
162.3

We believe that the terms and provisions of our related party agreements are fair to us; however, such agreements and transactions may not be as favorable to us as we could have obtained from unaffiliated third parties.
35

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 June 30, 2020, 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
701,969,275
32.1 %

Of the total number of units held by EPCO and its privately held affiliates, 88,222,618 have been pledged as security under the credit facilities of EPCO and its privately held affiliates at June 30, 2020.  These credit facilities contain customary and other events of default, including defaults by us and other affiliates of EPCO.  An event of default, followed by a foreclosure on the pledged collateral, could ultimately result in a change in ownership of these units and affect the market price of EPD’s common units.

We and Enterprise GP are both separate legal entities apart from each other and apart from EPCO and its other affiliates, with assets and liabilities that are also separate from those of EPCO and its other affiliates.  EPCO and its privately held affiliates depend on the cash distributions they receive from us and other investments to fund their other activities and to meet their debt obligations.  During the six months ended June 30, 2020 and 2019, we paid EPCO and its privately held affiliates cash distributions totaling $ 605.5 million and $ 593.7 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 operating functions and general and administrative support services are provided by employees of EPCO pursuant to the ASA or by other service providers.  The following table presents our related party costs and expenses attributable to the ASA with EPCO for the periods indicated:

For the Three Months
Ended June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
Operating costs and expenses
$
241.9
$
233.6
$
493.1
$
472.7
General and administrative expenses
32.0
29.4
62.5
58.7
Total costs and expenses
$
273.9
$
263.0
$
555.6
$
531.4

We lease office space from privately held affiliates of EPCO.  The rental rates in these lease agreements approximate market rates.  For the three months ended June 30, 2020 and 2019, we recognized $ 2.9 million and $ 3.5 million, respectively, of related party operating lease expense in connection with these office space leases. For the six months ended June 30, 2020 and 2019, we recognized $ 6.3 million and $ 7.3 million, respectively, of related party operating lease expense in connection with these office space leases.


Note 16.  Commitments and Contingencies

Litigation

As part of our normal business activities, we may be named as defendants in legal proceedings, including those arising from regulatory and environmental matters.  Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to fully indemnify us against losses arising from future legal proceedings.  We will vigorously defend the partnership in litigation matters.
36

ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Our accruals for litigation contingencies were $ 0.2 million at June 30, 2020 and December 31, 2019, and recorded in our Unaudited Condensed Consolidated Balance Sheets as a component of “Other current liabilities.”

Energy Transfer Matter
As reported in our 2019 Form 10-K, we prevailed on our appeal on January 31, 2020 when the Supreme Court of Texas unanimously affirmed the opinion of the Dallas Court of Appeals.  On March 6, 2020, the Supreme Court of Texas issued its mandate to the Dallas County Civil District Court, 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 propane dehydrogenation (“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 billion and $ 27.88 billion at June 30, 2020 and December 31, 2019, respectively.  See Note 7 for additional information regarding our scheduled future maturities of debt principal.

Lease Accounting Matters
The following table presents information regarding operating leases where we are the lessee at June 30, 2020:

Asset Category
ROU
Asset
Carrying
Value (1)
Lease
Liability
Carrying
Value (2)
Weighted-
Average
Remaining
Term
Weighted-
Average
Discount
Rate (3)
Storage and pipeline facilities
$
134.0
$
134.7
16 years
4.3 %
Transportation equipment
41.5
43.8
3 years
3.5 %
Office and warehouse space
173.6
180.5
17 years
3.2 %
Total
$
349.1
$
359.0

(1)
Right-of-use (“ROU”) asset amounts are a component of “Other assets” on our Unaudited Condensed Consolidated Balance Sheet.
(2)
At June 30, 2020 , lease liabilities of $ 30.1 million and $ 328.9 million were included within “Other current liabilities” and “Other liabilities,” respectively.
(3)
The discount rate for each category of assets represents the weighted average of either (i) the implicit rate applicable to the underlying leases (where determinable) or (ii) our incremental borrowing rate adjusted for collateralization (if the implicit rate is not determinable).  In general, the discount rates are based on either (i) information available at the lease commencement date or (ii) January 1, 2019 for leases existing at the adoption date for ASC 842.

37

ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


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

For the Three Months
Ended June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
Long-term operating leases:
Fixed lease expense:
Non-cash lease expense (amortization of ROU assets)
$
9.8
$
10.7
$
19.8
$
21.7
Related accretion expense on lease liability balances
3.3
2.4
6.7
4.8
Total fixed lease expense
13.1
13.1
26.5
26.5
Variable lease expense
0.1
1.1
0.3
2.9
Subtotal operating lease expense
13.2
14.2
26.8
29.4
Short-term operating leases
11.8
11.7
25.0
23.5
Total operating lease expense
$
25.0
$
25.9
$
51.8
$
52.9

Fixed lease expense is charged to earnings on a straight-line basis over the contractual term, with any variable lease payments expensed as incurred.  Short-term operating lease expense is expensed as incurred.  Cash paid for operating lease liabilities recorded on our balance sheet was $ 7.9 million and $ 12.9 million for the three months ended June 30, 2020 and 2019, respectively.  For the six months ended June 30, 2020 and 2019 cash paid for operating lease liabilities was $ 18.3 million and $ 26.4 million, respectively.

We do not have any significant operating or direct financing leases where we are the lessor.  Our operating lease income for the three months ended June 30, 2020 and 2019 was $ 2.6 million and $ 2.4 million, respectively.  For the six months ended June 30, 2020 and 2019 operating lease income was $ 6.1 million and $ 7.2 million, respectively.  We do not have any sales-type leases.

Our operating lease commitments at June 30, 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 enforceable and legally binding agreements as of the reporting date.  Our product purchase commitments at June 30, 2020 declined by an estimated $ 8.63 billion when compared to those reported in our 2019 Form 10-K primarily due to lower NGL and crude oil prices in the six months ended June 30, 2020.  At June 30, 2020, our estimated long-term product purchase obligations totaled $ 11.94 billion after reflecting the decline in commodity prices, agreements added during the six months ended June 30, 2020 and those commitments that expired during the year.  At December 31, 2019, our estimated long-term product purchase obligations totaled $ 20.57 billion.

Settlement of Liquidity Option

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


38

ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Note 17.  Supplemental Cash Flow Information

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

For the Six Months
Ended June 30,
2020
2019
Decrease (increase) in:
Accounts receivable – trade
$
2,077.0
$
( 124.8
)
Accounts receivable – related parties
( 0.1
)
( 10.6
)
Inventories
161.4
( 56.4
)
Prepaid and other current assets
906.2
( 291.2
)
Other assets
87.7
( 12.4
)
Increase (decrease) in:
Accounts payable – trade
81.9
60.0
Accounts payable – related parties
( 73.1
)
( 21.0
)
Accrued product payables
( 2,119.4
)
107.6
Accrued interest
30.0
( 3.3
)
Other current liabilities
( 1,142.3
)
83.0
Other liabilities
( 98.3
)
( 62.9
)
Net effect of changes in operating accounts
$
( 89.0
)
$
( 332.0
)

We incurred liabilities for construction in progress that had not been paid at June 30, 2020 and December 31, 2019 of $ 306.6 million and $ 432.0 million, respectively.  Such amounts are not included under the caption “Capital expenditures” on the Unaudited Condensed Statements of Consolidated Cash Flows.



39

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
June 30, 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
$
1,256.8
$
201.7
$
( 22.0
)
$
1,436.5
$
0.1
$
–
$
1,436.6
Accounts receivable – trade, net
1,119.5
1,788.8
( 0.6
)
2,907.7
–
–
2,907.7
Accounts receivable – related parties
166.2
635.7
( 791.1
)
10.8
–
( 8.2
)
2.6
Inventories
1,465.2
559.1
( 0.2
)
2,024.1
–
–
2,024.1
Derivative assets
175.4
13.6
20.7
209.7
–
–
209.7
Prepaid and other current assets
273.6
395.0
( 133.5
)
535.1
0.5
–
535.6
Total current assets
4,456.7
3,593.9
( 926.7
)
7,123.9
0.6
( 8.2
)
7,116.3
Property, plant and equipment, net
6,607.0
35,972.9
( 41.5
)
42,538.4
–
–
42,538.4
Investments in unconsolidated affiliates
46,478.3
5,031.9
( 48,962.8
)
2,547.4
24,883.3
( 24,883.3
)
2,547.4
Intangible assets, net
627.6
2,768.8
( 17.0
)
3,379.4
–
–
3,379.4
Goodwill
459.5
5,285.7
–
5,745.2
–
–
5,745.2
Other assets
554.9
305.6
( 243.7
)
616.8
1.0
–
617.8
Total assets
$
59,184.0
$
52,958.8
$
( 50,191.7
)
$
61,951.1
$
24,884.9
$
( 24,891.5
)
$
61,944.5
LIABILITIES AND EQUITY
Current liabilities:
Current maturities of debt
$
2,325.0
$
–
$
–
$
2,325.0
$
–
$
–
$
2,325.0
Accounts payable – trade
296.2
619.6
( 13.3
)
902.5
–
–
902.5
Accounts payable – related parties
709.5
192.6
( 812.8
)
89.3
8.2
( 8.2
)
89.3
Accrued product payables
1,432.3
1,372.0
( 0.8
)
2,803.5
–
–
2,803.5
Accrued interest
461.7
0.8
( 0.8
)
461.7
–
–
461.7
Derivative liabilities
368.9
37.2
( 20.7
)
385.4
–
–
385.4
Other current liabilities
152.9
454.9
( 93.0
)
514.8
–
0.2
515.0
Total current liabilities
5,746.5
2,677.1
( 941.4
)
7,482.2
8.2
( 8.0
)
7,482.4
Long-term debt
27,270.6
14.6
–
27,285.2
–
–
27,285.2
Deferred tax liabilities
26.1
452.7
( 0.6
)
478.2
–
3.4
481.6
Other long-term liabilities
381.8
618.5
( 246.4
)
753.9
–
–
753.9
Commitments and contingencies
Equity:
Partners’ and other owners’ equity
25,759.0
49,132.0
( 50,042.1
)
24,848.9
24,876.7
( 24,848.9
)
24,876.7
Noncontrolling interests
–
63.9
1,038.8
1,102.7
–
( 38.0
)
1,064.7
Total equity
25,759.0
49,195.9
( 49,003.3
)
25,951.6
24,876.7
( 24,886.9
)
25,941.4
Total liabilities and equity
$
59,184.0
$
52,958.8
$
( 50,191.7
)
$
61,951.1
$
24,884.9
$
( 24,891.5
)
$
61,944.5

40

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

41

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 June 30, 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
Revenues
$
8,817.0
$
3,835.7
$
( 6,901.7
)
$
5,751.0
$
–
$
–
$
5,751.0
Costs and expenses:
Operating costs and expenses
8,582.9
2,689.9
( 6,902.4
)
4,370.4
–
–
4,370.4
General and administrative costs
14.6
41.0
0.7
56.3
0.7
–
57.0
Total costs and expenses
8,597.5
2,730.9
( 6,901.7
)
4,426.7
0.7
–
4,427.4
Equity in income of unconsolidated affiliates
1,370.8
154.9
( 1,412.4
)
113.3
1,035.2
( 1,035.2
)
113.3
Operating income
1,590.3
1,259.7
( 1,412.4
)
1,437.6
1,034.5
( 1,035.2
)
1,436.9
Other income (expense):
Interest expense
( 320.5
)
( 2.5
)
2.8
( 320.2
)
–
–
( 320.2
)
Other, net
4.8
238.2
( 239.3
)
3.7
0.1
–
3.8
Total other expense, net
( 315.7
)
235.7
( 236.5
)
( 316.5
)
0.1
–
( 316.4
)
Income before income taxes
1,274.6
1,495.4
( 1,648.9
)
1,121.1
1,034.6
( 1,035.2
)
1,120.5
Benefit from (provision for) income taxes
( 4.2
)
( 55.3
)
–
( 59.5
)
0.1
( 0.3
)
( 59.7
)
Net income
1,270.4
1,440.1
( 1,648.9
)
1,061.6
1,034.7
( 1,035.5
)
1,060.8
Net income attributable to noncontrolling interests
–
( 1.4
)
( 26.3
)
( 27.7
)
–
1.6
( 26.1
)
Net income attributable to entity
$
1,270.4
$
1,438.7
$
( 1,675.2
)
$
1,033.9
$
1,034.7
$
( 1,033.9
)
$
1,034.7


Enterprise Products Partners L.P.
Unaudited Condensed Consolidating Statement of Operations
For the Three Months Ended June 30, 2019

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

42

ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Enterprise Products Partners L.P.
Unaudited Condensed Consolidating Statement of Operations
For the Six Months Ended June 30, 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
Revenues
$
18,444.0
$
8,474.1
$
( 13,684.6
)
$
13,233.5
$
–
$
–
$
13,233.5
Costs and expenses:
Operating costs and expenses
17,802.3
6,314.5
( 13,686.1
)
10,430.7
–
–
10,430.7
General and administrative costs
20.4
89.4
1.4
111.2
1.3
–
112.5
Total costs and expenses
17,822.7
6,403.9
( 13,684.7
)
10,541.9
1.3
–
10,543.2
Equity in income of unconsolidated affiliates
2,048.9
308.0
( 2,102.8
)
254.1
2,315.9
( 2,315.9
)
254.1
Operating income
2,670.2
2,378.2
( 2,102.7
)
2,945.7
2,314.6
( 2,315.9
)
2,944.4
Other income (expense):
Interest expense
( 638.2
)
( 5.1
)
5.6
( 637.7
)
–
–
( 637.7
)
Other, net
13.0
( 272.8
)
271.4
11.6
( 2.0
)
–
9.6
Total other expense, net
( 625.2
)
( 277.9
)
277.0
( 626.1
)
( 2.0
)
–
( 628.1
)
Income before income taxes
2,045.0
2,100.3
( 1,825.7
)
2,319.6
2,312.6
( 2,315.9
)
2,316.3
Benefit from (provision for) income taxes
( 8.8
)
57.0
( 0.3
)
47.9
72.2
( 0.6
)
119.5
Net income
2,036.2
2,157.3
( 1,826.0
)
2,367.5
2,384.8
( 2,316.5
)
2,435.8
Net income attributable to noncontrolling interests
–
( 2.8
)
( 51.2
)
( 54.0
)
–
3.0
( 51.0
)
Net income attributable to entity
$
2,036.2
$
2,154.5
$
( 1,877.2
)
$
2,313.5
$
2,384.8
$
( 2,313.5
)
$
2,384.8


Enterprise Products Partners L.P.
Unaudited Condensed Consolidating Statement of Operations
For the Six Months Ended June 30, 2019

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


43

ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Enterprise Products Partners L.P.
Unaudited Condensed Consolidating Statement of Comprehensive Income
For the Three Months Ended June 30, 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
Comprehensive income
$
1,195.0
$
1,246.1
$
( 1,648.8
)
$
792.3
$
765.3
$
( 766.2
)
$
791.4
Comprehensive income attributable to noncontrolling interests
–
( 1.4
)
( 26.3
)
( 27.7
)
–
1.6
( 26.1
)
Comprehensive income attributable to entity
$
1,195.0
$
1,244.7
$
( 1,675.1
)
$
764.6
$
765.3
$
( 764.6
)
$
765.3

Unaudited Condensed Consolidating Statement of Comprehensive Income
For the Three Months Ended June 30, 2019

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

Unaudited Condensed Consolidating Statement of Comprehensive Income
For the Six Months Ended June 30, 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
Comprehensive income
$
1,684.1
$
2,291.0
$
( 1,826.0
)
$
2,149.1
$
2,166.3
$
( 2,098.1
)
$
2,217.3
Comp rehensive income attrib utable to noncontrolling interests
–
( 2.8
)
( 51.2
)
( 54.0
)
–
3.0
( 51.0
)
Comprehensive income attributable to entity
$
1,684.1
$
2,288.2
$
( 1,877.2
)
$
2,095.1
$
2,166.3
$
( 2,095.1
)
$
2,166.3

Unaudited Condensed Consolidating Statement of Comprehensive Income
For the Six Months Ended June 30, 2019
EPO and Subsidiaries
Subsidiary
Issuer
(EPO)
Other
Subsidiaries
(Non-
guarantor)
EPO and
Subsidiaries
Eliminations
and
Adjustments
Consolidated
EPO and
Subsidiaries
EPD
(Guarantor)
Eliminations
and
Adjustments
Consolidated
Total
Comprehensive income
$
2,589.9
$
2,473.8
$
( 2,521.8
)
$
2,541.9
$
2,413.6
$
( 2,500.2
)
$
2,455.3
Comprehensive income attributable to noncontrolling interests
–
( 3.4
)
( 41.1
)
( 44.5
)
–
2.8
( 41.7
)
Comprehensive income attributable to entity
$
2,589.9
$
2,470.4
$
( 2,562.9
)
$
2,497.4
$
2,413.6
$
( 2,497.4
)
$
2,413.6

44

ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Enterprise Products Partners L.P.
Unaudited Condensed Consolidating Statement of Cash Flows
For the Six Months Ended June 30, 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
$
2,036.2
$
2,157.3
$
( 1,826.0
)
$
2,367.5
$
2,384.8
$
( 2,316.5
)
$
2,435.8
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion
173.0
860.4
( 1.7
)
1,031.7
–
–
1,031.7
Equity in income of unconsolidated affiliates
( 2,048.9
)
( 308.0
)
2,102.8
( 254.1
)
( 2,315.9
)
2,315.9
( 254.1
)
Distributions received from unconsolidated affiliates attributable to earnings
765.5
132.3
( 640.2
)
257.6
2,159.0
( 2,159.0
)
257.6
Net effect of changes in operating accounts and other operating activities
1,704.0
( 1,604.7
)
( 307.3
)
( 208.0
)
( 69.3
)
0.1
( 277.2
)
Net cash flows provided by operating activities
2,629.8
1,237.3
( 672.4
)
3,194.7
2,158.6
( 2,159.5
)
3,193.8
Investing activities:
Capital expenditures
( 401.1
)
( 1,575.7
)
0.9
( 1,975.9
)
–
–
( 1,975.9
)
Proceeds from asset sales
0.5
3.6
–
4.1
–
–
4.1
Other investing activities
( 886.6
)
( 3.9
)
931.8
41.3
–
–
41.3
Cash used in investing activities
( 1,287.2
)
( 1,576.0
)
932.7
( 1,930.5
)
–
–
( 1,930.5
)
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
( 2,159.0
)
( 737.4
)
761.8
( 2,134.6
)
( 1,971.3
)
2,159.0
( 1,946.9
)
Cash payments made in connection with DERs
–
–
–
–
( 12.9
)
–
( 12.9
)
Cash distributions paid to noncontrolling interests
–
( 4.2
)
( 58.1
)
( 62.3
)
–
0.5
( 61.8
)
Cash contributions from noncontrolling interests
–
–
19.7
19.7
–
–
19.7
Repurchase of common units under 2019 Buyback Program
–
–
–
–
( 140.1
)
–
( 140.1
)
Cash contributions from owners
–
966.2
( 966.2
)
–
–
–
–
Other financing activities
( 41.2
)
–
( 24.4
)
( 65.6
)
( 34.3
)
–
( 99.9
)
Cash provided by (used in) financing activities
( 195.0
)
224.6
( 267.2
)
( 237.6
)
( 2,158.6
)
2,159.5
( 236.7
)
Net change in cash and cash equivalents,
including restricted cash
1,147.6
( 114.1
)
( 6.9
)
1,026.6
–
–
1,026.6
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
$
1,256.8
$
201.7
$
( 22.0
)
$
1,436.5
$
0.1
$
–
$
1,436.6

45

ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Enterprise Products Partners L.P.
Unaudited Condensed Consolidating Statement of Cash Flows
For the Six Months Ended June 30, 2019

EPO and Subsidiaries
Subsidiary
Issuer
(EPO)
Other
Subsidiaries
(Non-
guarantor)
EPO and
Subsidiaries
Eliminations
and
Adjustments
Consolidated
EPO and
Subsidiaries
EPD
(Guarantor)
Eliminations
and
Adjustments
Consolidated
Total
Operating activities:
Net income
$
2,568.1
$
2,557.2
$
( 2,521.8
)
$
2,603.5
$
2,475.2
$
( 2,561.8
)
$
2,516.9
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion
153.0
810.6
( 0.5
)
963.1
–
–
963.1
Equity in income of unconsolidated affiliates
( 2,475.0
)
( 329.7
)
2,512.7
( 292.0
)
( 2,561.2
)
2,561.2
( 292.0
)
Distributions received from unconsolidated affiliates attributable to earnings
742.1
163.8
( 614.8
)
291.1
2,021.2
( 2,021.2
)
291.1
Net effect of changes in operating accounts and other operating activities
1,246.9
( 1,718.2
)
43.9
( 427.4
)
131.9
0.1
( 295.4
)
Net cash flows provided by operating activities
2,235.1
1,483.7
( 580.5
)
3,138.3
2,067.1
( 2,021.7
)
3,183.7
Investing activities:
Capital expenditures
( 388.6
)
( 1,864.3
)
( 7.9
)
( 2,260.8
)
–
–
( 2,260.8
)
Proceeds from asset sales
0.8
15.3
–
16.1
–
–
16.1
Other investing activities
( 1,014.8
)
( 1.9
)
974.9
( 41.8
)
( 119.3
)
119.3
( 41.8
)
Cash used in investing activities
( 1,402.6
)
( 1,850.9
)
967.0
( 2,286.5
)
( 119.3
)
119.3
( 2,286.5
)
Financing activities:
Borrowings under debt agreements
40,318.1
–
–
40,318.1
–
–
40,318.1
Repayments of debt
( 39,617.2
)
( 0.1
)
–
( 39,617.3
)
–
–
( 39,617.3
)
Cash distributions paid to owners
( 2,021.2
)
( 679.8
)
679.8
( 2,021.2
)
( 1,907.9
)
2,021.2
( 1,907.9
)
Cash payments made in connection with DERs
–
–
–
–
( 10.5
)
–
( 10.5
)
Cash distributions paid to noncontrolling interests
–
( 4.9
)
( 42.5
)
( 47.4
)
–
0.5
( 46.9
)
Cash contributions from noncontrolling interests
–
–
99.6
99.6
–
–
99.6
Net cash proceeds from issuance of common units
–
–
–
–
82.2
–
82.2
Repurchase of common units under 2019 Buyback Program
–
–
–
–
( 81.1
)
–
( 81.1
)
Cash contributions from owners
119.3
1,097.0
( 1,097.0
)
119.3
–
( 119.3
)
–
Other financing activities
( 0.3
)
( 5.6
)
–
( 5.9
)
( 30.3
)
–
( 36.2
)
Cash provided by (used in) financing activities
( 1,201.3
)
406.6
( 360.1
)
( 1,154.8
)
( 1,947.6
)
1,902.4
( 1,200.0
)
Net change in cash and cash equivalents,
including restricted cash
( 368.8
)
39.4
26.4
( 303.0
)
0.2
–
( 302.8
)
Cash and cash equivalents, including
restricted cash, at beginning of period
393.4
50.3
( 33.6
)
410.1
–
–
410.1
Cash and cash equivalents, including
restricted cash, at end of period
$
24.6
$
89.7
$
( 7.2
)
$
107.1
$
0.2
$
–
$
107.3




46

ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Note 19.  Subsequent Events

Issuance of $ 1.25 Billion of Senior Notes in August 2020

In August 2020, EPO issued $ 1.0 billion in principal amount of 3.20 % senior notes due February 2052 (“Senior Notes DDD”) and $ 250.0 million in principal amount of 2.80 % reopened senior notes due January 2030 (“Senior Notes AAA”).  The reopened Senior Notes AAA and the Senior Notes DDD were issued at 107.211 % and 99.233 % of their principal amounts, respectively.

We received aggregate net proceeds of $ 1.25 billion from the sale of the notes after deducting underwriting discounts and other estimated offering expenses payable by us. Net proceeds from the issuance of these senior notes will be used for general company purposes, including for growth capital investments, and to repay all or part of $ 750.0 million in principal amount of Senior Notes TT, which mature in February 2021.

The reopened Senior Notes AAA represent a re-opening of an outstanding series of EPO’s senior notes. EPO originally issued $ 1.0 billion principal amount of Senior Notes AAA on January 15, 2020. The reopened Senior Notes AAA will form a single series with the original notes of that series, will trade under the same CUSIP number, and will have the same terms as to status, redemption or otherwise as the original notes of that series.

47


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

For the Three and Six Months Ended June 30, 2020 and 2019

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 (the “2019 Form 10-K”), as filed on February 28, 2020 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 June 30, 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 second quarter of 2020 compared to the second quarter of 2019.  Likewise, the phrase “period-to-period” means the six months ended June 30, 2020 compared to the six months ended June 30, 2019.
48


CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This quarterly report on Form 10-Q contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us.  When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “seek,” “goal,” “estimate,” “forecast,” “intend,” “could,” “should,” “would,” “will,” “believe,” “may,” “potential” and similar expressions and statements regarding our plans and objectives for future operations are intended to identify forward-looking statements.  Although we and our general partner believe that our expectations reflected in such forward-looking statements (including the 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, uncertainties and assumptions as described in more detail under Part I, Item 1A of our 2019 Form 10-K and within Part II, Item 1A of this quarterly report.  These risks include recent impacts of the coronavirus disease 2019 (“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.  If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected.  You should not put undue reliance on any forward-looking statements.  The forward-looking statements in this quarterly report speak only as of the date hereof.  Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason.

Overview of Business

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

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

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

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

Each of our business segments benefits from the supporting role of our related marketing activities.  The main purpose of our marketing activities is to support the utilization and expansion of assets across our midstream energy asset network by increasing the volumes handled by such assets, which results in additional fee-based earnings for each business segment.  In performing these support roles, our marketing activities also seek to participate in supply and demand opportunities as a supplemental source of gross operating margin, a non-generally accepted accounting principle (“non-GAAP”) financial measure, for the partnership.  The financial results of our marketing efforts fluctuate due to changes in volumes handled and overall market conditions, which are influenced by current and forward market prices for the products bought and sold.
49


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

Update on 2020 Outlook

As noted previously, this quarterly report on Form 10-Q, including this update to our 2020 Outlook, contains forward-looking statements 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, which includes forecast information published by third parties. See “Cautionary Statement Regarding Forward-Looking Information” within this Part I, Item 2 and “Risk Factors” 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 and presents our current views on key midstream energy supply and demand fundamentals. The third-party supply and demand forecasts cited in the following analysis, including our internal forecasts based on such information, remain subject to heightened levels of uncertainty because mitigation and reopening efforts related to COVID-19 continue to evolve.

The emergence of COVID-19 as a global pandemic in the first quarter of 2020 and the consequences of international COVID-19 containment measures (and the resulting near-term decline in end-user demand for hydrocarbons) have adversely impacted the global economy in general and the energy industry in particular. In addition, disputes between members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (collectively, the “OPEC+” group) in March and April 2020 over crude oil production levels, resulted in major disruptions to global energy markets. Although the OPEC+ group and other producers subsequently reached agreements to reduce the oversupply of crude oil in the near-term caused by demand destruction attributable to COVID-19, the downturn in the energy industry has negatively impacted us, the producers we work with and our other customers to varying degrees.  As described in 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, which in turn has a direct impact on our financial position, results of operations and cash flows.

Demand Side Observations

The COVID-19 public health emergency resulted in record, near-term decreases in hydrocarbon demand due to lockdowns, travel restrictions, quarantines, temporary business closures and other measures instituted as early as February 2020 as the virus spread across several continents.  By May 2020, several major economies across the world began to work towards reopening their economies by targeting a balance between containing and eradicating the virus and supporting their economies, versus the initial more complete shut-downs.  The U.S., China, India, much of Europe and parts of Latin America have begun to ease their COVID-19 containment measures and central banks and governments have instituted significant measures in an effort to stimulate economic activity.  As a result, energy demand began to recover, with notable improvements in China, India, Europe and to some extent in the U.S.  A continuation of this trend remains dependent on successful containment of the disease and its elimination as a widespread threat to public health.  It is encouraging to note that, according to information published by the New York Times on July 22, 2020, researchers around the world are developing more than 160 vaccines against the virus, and 27 vaccines are in human trials.  Although vaccines typically require years of research and testing before being made available to the public, scientists are racing to produce a safe and effective vaccine.  While we are encouraged by efforts to reopen the global economy, the pace and the scope of the reopening is uncertain at this time and may extend well into 2021.

In its July 2020 Oil Market Report published on July 10, 2020 (the “July 2020 OMR”), the International Energy Agency (“IEA”) estimated that global crude oil demand for calendar year 2020 would fall by 7.9 MMBPD before recovering by 5.3 MMBPD in 2021.  Overall, the July 2020 OMR forecasts that crude oil demand will approximate 92.1 MMBPD in 2020 and 97.4 MMBPD in 2021.  In addition, the IEA forecasts crude oil demand will approximate 94.5 MMBPD and 97.0 MMBPD in the third and fourth quarters of 2020, respectively.

The destruction in hydrocarbon demand attributable to COVID-19 resulted in a severe drop in crude oil prices.  Prior to the pandemic, crude oil prices for West Texas Intermediate (“WTI”) at Cushing, Oklahoma (as reported by the NYMEX) closed at $61.06 per barrel on December 31, 2019.   By March 31, 2020, WTI prices closed at $20.48 per barrel and, notwithstanding the announced production cuts, closed at a record low of a negative $37.63 per barrel on April 20, 2020.  As demand began to recover in the second quarter of 2020, WTI prices rebounded from the April lows and closed at $39.27 per barrel on June 30, 2020.  According to the July 2020 OMR, futures markets are anticipating a transformation in the oil market from substantial daily surplus in the first half of 2020 to a daily deficit in the second half of 2020.
50


Downstream demand for hydrocarbon products such as gasoline and jet fuel is expected to remain depressed until the COVID-19 containment measures are substantially lifted and the economy sufficiently improves.  Refiners have reduced their utilization rates in response to lower domestic and international demand.  According to the July 2020 OMR, global refining throughput for 2020 is forecast to fall 6.4 MMBPD to 75.1 MMBPD in 2020 due to reduced demand for transportation fuels and increase by 4.7 MMBPD in 2021.

Supply Side Observations

Production agreements within the OPEC+ group in the second quarter of 2020, along with market-driven cuts in U.S., Brazilian and Canadian supplies due to lower crude oil prices, continue to provide much-needed support for international energy markets in coping with the decline in hydrocarbon demand attributable to COVID-19.  The OPEC+ group agreed to reduce their combined oil production by 9.7 MMBPD in May and June 2020, 9.6 MMBPD in July 2020, 7.7 MMBPD from August through December 2020 and 5.8 MMBPD from January 2021 to April 2022.

Global supply and demand fundamentals are being continually evaluated by the OPEC+ Joint Ministerial Monitoring Committee and the existing OPEC+ agreement is scheduled to be reevaluated in December 2021. The duration of market-driven production cuts by non-OPEC countries such as U.S., Brazil and Canada will depend on market forces, which are based on supply and demand fundamentals. According to the July 2020 OMR, the record output cuts from OPEC+ and steep declines from other non-OPEC producers resulted in global oil production for June 2020 falling by 13.7 MMBPD when compared to April 2020.  Overall, the IEA states that global oil supply fell to a nine-year low of 86.9 MMBPD in June 2020.  According to the July 2020 OMR, global oil supply is forecast to decline by 7.1 MMBPD on average in 2020 (assuming the OPEC+ production cuts stay in place), and increase by 1.7 MMBPD in 2021.

As a result of the current business environment, most oil producers in North America have reduced their 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. Baker Hughes reports that the total number of drilling rigs working in the continental U.S. (combined crude oil and natural gas rigs) declined from 805 at December 31, 2019 to 728 at March 31, 2020 and further to 265 at June 30, 2020. The U.S. Energy Information Administration (“EIA”) in its July 2020 Short-Term Energy Outlook (“July 2020 STEO” dated July 7, 2020) expects U.S. crude oil production to average 11.6 MMBPD in 2020, which is down 0.6 MMBPD from 2019.  Furthermore, the EIA expects U.S. crude oil production to average 11.0 MMBPD in 2021.

Enterprise Outlook

Although the current business outlook remains challenging, we believe that our partnership remains in a strong financial position to endure through these circumstances. We enter the second half of 2020 with a solid balance sheet, ample liquidity and good coverage of our cash distribution.

At June 30, 2020, we had $ 7.3 billion of consolidated liquidity, which was comprised of $ 6.0 billion of available borrowing capacity under EPO’s revolving credit facilities and $ 1.3 b illion of unrestricted cash on hand. Our liquidity is supported by investment grade credit ratings on EPO’s long-term senior unsecured debt of BBB+, Baa1 and BBB+ from Standard & Poor's, Moody’s and Fitch, respectively.

EPO completed a $3.0 billion senior notes offering in January 2020 that provided funds to repay all of its $1.5 billion of senior note maturities in 2020, amounts then outstanding under its commercial paper program and for general company purposes.  In August 2020, EPO issued $1.0 billion in principal amount of 3.20% senior notes due February 2052 and $250.0 million in principal amount of reopened senior notes due January 2030.  Net proceeds from the issuance of senior notes in August 2020 will be used for general company purposes, including for growth capital investments, and to repay all or part of $750.0 million in principal amount of Senior Notes TT, which mature in February 2021. Based on current conditions, we believe that we will have sufficient liquidity and/or access to debt capital markets to fund the remaining principal amount of senior notes maturing in 2021.



51


Capital spending throughout the domestic energy industry has been significantly reduced to preserve capital during the current downturn.  We are no exception to this trend.  Based on information currently available, we now expect our total capital investments for 2020 to approximate $2.8 billion to $3.3 billion (originally forecast at $3.4 billion to $4.4 billion), which reflects growth capital investments of $2.5 billion to $3.0 billion and approximately $300 million for sustaining capital expenditures.  In addition, we currently expect our growth capital investments on sanctioned projects for 2021 and 2022 to approximate $2.3 billion and $1.0 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 during 2020.  In addition to reductions made in our capital spending program, we continue to discuss project commitments with customers and joint venture opportunities with strategic partners to optimize our use of available capital. These efforts, which have been slowed in the second quarter of 2020 due to impacts of the pandemic, could further reduce our planned growth capital investments for 2020, 2021 and 2022.

We continue to optimize our assets during this difficult period to provide incremental services to customers and to respond to market opportunities; however, as expected w e experienced a reduction in volumes on a number of our assets during the second quarter of 2020 due to reduced upstream drilling activity and lower downstream refinery activity and demand for transportation fuels. Furthermore, we may continue to 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 other facilities until the pandemic ends and economic activity is fully restored. 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. Our business is predominately fee-based (approximately 86% of gross operating margin in 2019), with a substantial portion backed by take-or-pay arrangements. The reduction in upstream production activity and international demand is negatively impacting the export of crude oil and basic petrochemicals from our marine terminals; however, LPG export demand has remained resilient.  As prices for certain NGLs, crude oil and refined products fell precipitously during the second quarter of 2020 due to collapsing demand for refined products as a result of the pandemic, our storage services provided valuable flexibility for our customers. During the second quarter of 2020, we were also able to benefit by using uncontracted storage capacity to capture contango opportunities in NGLs, crude oil and refined products and will continue to see this benefit for the remainder of 2020.

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.

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 six months 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 Recent Developments

Issuance of Senior Notes in January 2020 and August 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.

52


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.

In August 2020, EPO issued $1.0 billion in principal amount of 3.20% senior notes due February 2052 (“Senior Notes DDD”) and $250.0 million in principal amount of reopened 2.80% senior notes due January 2030 (“Senior Notes AAA”).  The reopened Senior Notes AAA and the Senior Notes DDD were issued at 107.211% and 99.233% of their principal amounts, respectively. We received aggregate net proceeds of $1.25 billion from the sale of the notes after deducting underwriting discounts and other estimated offering expenses payable by us. Net proceeds from the issuance of these senior notes will be used for general company purposes, including for growth capital investments, and to repay all or part of $750.0 million in principal amount of Senior Notes TT, which mature in February 2021.

Enterprise Co-Loads Export Vessels at Houston Ship Channel Terminals

In July 2020, we completed the simultaneous loading of propane and polymer grade propylene (“PGP”) into separate compartments on a Very Large Gas Carrier at our Enterprise Hydrocarbons Terminal (“EHT”), as well as the simultaneous loading of ethane and ethylene on a vessel at our Morgan’s Point Ethane Export Terminal facility.  Both vessels were the first export cargoes of their kind from the U.S.

Enterprise Declares Cash Distribution for Second Quarter of 2020

On July 7 , 2020, we announced that the Board declared a quarterly cash distribution to be paid to our limited partners with respect to the second quarter of 2020 of $0.4450 per common unit, or $1.78 per unit on an annualized basis.  The quarterly distribution associated with the second quarter of 2020 is payable on August 12 , 2020, to unitholders of record as of the close of business on July 31 , 2020.  This distribution represents a 1.1 % increase over the distribution declared with respect to the second quarter of 2019.  We paid our limited partners a distribution of $0.4450 per common unit with respect to the first quarter of 2020 on May 12 , 2020. 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.

Enterprise Enters Into Long-Term Sales Agreement in Support of PDH 2 Facility

In June 2020, we announced the execution of a long-term sales agreement with Marubeni Corporation to supply PGP from our second propane dehydrogenation plant (“PDH 2”), which is currently under construction at our Mont Belvieu complex. Marubeni Corporation is a major Japanese integrated trading and investment business conglomerate and the world’s largest olefins trader. PGP is a primary petrochemical that has global demand growth as a feedstock to manufacture consumer, medical and industrial products that improve the daily lives and protect the health of people around the world.

PDH 2 is expected to have the capacity to upgrade 35 MBPD of propane into 1.65 billion pounds per year (equivalent to 25 MBPD) of PGP and begin service in the second quarter of 2023.  Upon completion of PDH 2, our total capacity to produce PGP is expected to be 11 billion pounds per year, representing the largest PGP production complex in the world.

Enterprise Ramps Up Ethylene Exports at its Morgan’s Point Marine Terminal

In June 2020, we announced that the loading capacity of our jointly-owned ethylene export terminal located on the Houston Ship Channel at Morgan’s Point, Texas was exceeding our interim design expectations and that ethylene exports for June would exceed 175 million pounds.  In fact, the marine terminal loaded a record-sized ethylene cargo of 44 million pounds on the Navigator Eclipse .  We expect to complete the construction of an ethylene storage tank at the terminal site by the end of 2020, which should increase the terminal’s total loading capacity to 2.2 billion pounds per year.

The marine terminal volumes are supported by our high-capacity ethylene storage hub and pipeline system, which is connected to four ethylene pipeline systems. We expect to complete three additional connections by the end of 2020, linking the system to a majority of ethylene production capacity in Texas. Our open access ethylene storage hub and pipeline system provides domestic ethylene producers access to both domestic and global markets.
53


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 Revolving Credit Agreement ”).  The new agreement provides EPO with an incremental $1.0 billion of borrowing capacity, thereby increasing its overall borrowing capacity under its revolving credit agreements to $6.0 billion.  The April 2020 364-Day Revolving Credit Agreement enhances our financial flexibility during the economic downturn caused by the COVID-19 pandemic.  Under the terms of the April 2020 364-Day Revolving 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 Revolving Credit Agreement for working capital, capital expenditures, acquisitions and other company purposes.

Settlement of Liquidity Option

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, OTA Holdings, Inc., a Delaware corporation previously named 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 $1.30 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.  In May 2020, we filed a registration statement on behalf of Skyline for the resale of up to 54,807,352 EPD common units. This registration statement is effective and, in June 2020, we filed a prospectus supplement to this registration statement that allows Skyline to sell up to $500 million of the EPD common units it owns in connection with an “at-the-market” program that it administers.   We will not receive any proceeds from such offerings.

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 $1.30 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 , t he 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 $1.30 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 six months ended June 30, 2020, see “ Income Statement Highlights – Income Taxes ” within this Item 2.



54


Selected Energy Commodity Price Data

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

Polymer
Refinery
Indicative Gas
Natural
Normal
Natural
Grade
Grade
Processing
Gas,
Ethane,
Propane,
Butane,
Isobutane,
Gasoline,
Propylene,
Propylene,
Gross Spread
$/MMBtu
$/gallon
$/gallon
$/gallon
$/gallon
$/gallon
$/pound
$/pound
$/gallon
(1)
(2)
(2)
(2)
(2)
(2)
(3)
(3)
(4)
2019 by quarter:
1st Quarter
$3.15
$0.30
$0.67
$0.82
$0.85
$1.16
$0.38
$0.24
$0.31
2nd Quarter
$2.64
$0.21
$0.55
$0.63
$0.65
$1.21
$0.37
$0.24
$0.25
3rd Quarter
$2.23
$0.17
$0.44
$0.51
$0.66
$1.06
$0.38
$0.23
$0.21
4th Quarter
$2.50
$0.19
$0.50
$0.68
$0.82
$1.20
$0.35
$0.21
$0.25
2019 Averages
$2.63
$0.22
$0.54
$0.66
$0.75
$1.16
$0.37
$0.23
$0.26
2020 by quarter:
1st Quarter
$1.95
$0.14
$0.37
$0.57
$0.63
$0.93
$0.31
$0.18
$0.19
2nd Quarter
$1.71
$0.19
$0.41
$0.43
$0.44
$0.41
$0.26
$0.11
$0.17
2020 Averages
$1.83
$0.17
$0.39
$0.50
$0.54
$0.67
$0.29
$0.15
$0.18

(1)
Natural gas prices are based on Henry-Hub Inside FERC commercial index prices as reported by Platts, which is a division of McGraw Hill Financial, Inc.
(2)
NGL prices for ethane, propane, normal butane, isobutane and natural gasoline are based on Mont Belvieu Non-TET commercial index prices as reported by Oil Price Information Service.
(3)
Polymer grade propylene prices represent average contract pricing for such product as reported by IHS Chemical, a division of IHS Inc. (“IHS Chemical”).  Refinery grade propylene prices represent weighted-average spot prices for such product as reported by IHS Chemical.
(4)
The “Indicative Gas Processing Gross Spread” represents a generic estimate of the gross economic benefit from extracting NGLs from natural gas production based on certain pricing assumptions.  Specifically, it is the amount by which the assumed economic value of a composite gallon of NGLs at Mont Belvieu, Texas exceeds the value of the equivalent amount of energy in natural gas at Henry Hub, Louisiana (as presented in the table above). The indicative spread does not consider the operating costs incurred by a natural gas processing 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 $ 0.31 per gallon in the second quarter of 2020 versus $0.47 per gallon during the second quarter of 2019.  Likewise, the weighted-average indicative market price for NGLs was $ 0.33 per gallon during the six months ended June 30, 2020 compared to $0.52 per gallon during the same period in 2019.   The following table presents selected average index prices for crude oil for the periods indicated:

WTI
Midland
Houston
LLS
Crude Oil,
Crude Oil,
Crude Oil
Crude Oil,
$/barrel
$/barrel
$/barrel
$/barrel
(1)
(2)
(2)
(3)
2019 by quarter:
1st Quarter
$54.90
$53.70
$61.19
$62.35
2nd Quarter
$59.81
$57.62
$66.47
$67.07
3rd Quarter
$56.45
$56.12
$59.75
$60.64
4th Quarter
$56.96
$57.80
$60.04
$60.76
2019 Averages
$57.03
$56.31
$61.86
$62.71
2020 by quarter:
1st Quarter
$46.17
$45.51
$47.81
$48.15
2nd Quarter
$27.85
$28.22
$29.68
$30.12
2020 Averages
$37.01
$36.87
$38.75
$39.14

(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.
55

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 ” within this Item 2 for information regarding these events.

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

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

Income Statement Highlights

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

For the Three Months
Ended June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
Revenues
$
5,751.0
$
8,276.3
$
13,233.5
$
16,819.8
Costs and expenses:
Operating costs and expenses:
Cost of sales
3,195.2
5,609.4
8,018.2
11,445.0
Other operating costs and expenses
670.7
723.8
1,423.5
1,452.6
Depreciation, amortization and accretion expenses
494.3
462.8
977.1
913.7
Net gains attributable to asset sales
(1.6
)
(2.1
)
(1.5
)
(2.5
)
Asset impairment and related charges
11.8
7.0
13.4
11.8
Total operating costs and expenses
4,370.4
6,800.9
10,430.7
13,820.6
General and administrative costs
57.0
52.5
112.5
104.7
Total costs and expenses
4,427.4
6,853.4
10,543.2
13,925.3
Equity in income of unconsolidated affiliates
113.3
137.4
254.1
292.0
Operating income
1,436.9
1,560.3
2,944.4
3,186.5
Interest expense
(320.2
)
(290.1
)
(637.7
)
(567.3
)
Change in fair value of Liquidity Option
–
(26.6
)
(2.3
)
(84.4
)
Other, net
3.8
2.6
11.9
4.1
Benefit from (provision for) income taxes
(59.7
)
(9.7
)
119.5
(22.0
)
Net income
1,060.8
1,236.5
2,435.8
2,516.9
Net income attributable to noncontrolling interests
(26.1
)
(21.8
)
(51.0
)
(41.7
)
Net income attributable to limited partners
$
1,034.7
$
1,214.7
$
2,384.8
$
2,475.2

56


Revenues

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

For the Three Months
Ended June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
NGL Pipelines & Services:
Sales of NGLs and related products
$
1,934.1
$
2,659.4
$
4,353.3
$
5,330.6
Midstream services
542.2
625.3
1,091.1
1,268.5
Total
2,476.3
3,284.7
5,444.4
6,599.1
Crude Oil Pipelines & Services:
Sales of crude oil
1,146.7
2,531.7
2,843.6
4,860.1
Midstream services
316.5
334.9
658.5
613.8
Total
1,463.2
2,866.6
3,502.1
5,473.9
Natural Gas Pipelines & Services:
Sales of natural gas
347.7
531.4
746.9
1,187.1
Midstream services
237.5
287.9
508.9
559.7
Total
585.2
819.3
1,255.8
1,746.8
Petrochemical & Refined Products Services:
Sales of petrochemicals and refined products
1,030.0
1,087.7
2,627.5
2,568.3
Midstream services
196.3
218.0
403.7
431.7
Total
1,226.3
1,305.7
3,031.2
3,000.0
Total consolidated revenues
$
5,751.0
$
8,276.3
$
13,233.5
$
16,819.8

Second Quarter of 2020 Compared to Second Quarter of 2019 . Total revenues for the second quarter of 2020 decreased $2.53 billion when compared to the second quarter of 2019 primarily due to a net $2.35 billion decrease in marketing revenues.  Revenues from the marketing of crude oil and natural gas decreased $1.57 billion quarter-to-quarter primarily due to lower sales prices, which accounted for a $1.18 billion decrease, and lower sales volumes, which accounted for an additional $389.7 million decrease.  Revenues from the marketing of NGLs, petrochemicals and refined products decreased a net $783.0 million quarter-to-quarter primarily due to lower sales prices, which accounted for a $1.46 billion decrease, partially offset by the effects of higher sales volumes, which resulted in a $678.7 million increase.

Revenues from midstream services for the second quarter of 2020 decreased $ 173.6 million when compared to the second quarter of 2019.  Revenues from our natural gas processing facilities decreased a net $ 76.8 million quarter-to-quarter primarily due to the impact of lower NGL prices in the second quarter of 2020 compared to the second quarter of 2019 on the value of equity NGLs we receive as non-cash consideration for processing services. Revenues from our pipeline assets decreased $71.4 million quarter-to-quarter primarily due to lower demand for crude oil, natural gas and refined products transportation services. Lastly, third-party revenues from our Mont Belvieu NGL fractionation complex decreased $28.8 million quarter-to-quarter primarily due to lower fractionation fees.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019 . Total revenues for the six months ended June 30, 2020 decreased $3.59 billion when compared to the six months ended June 30, 2019 primarily due to a net $3.37 billion decrease in marketing revenues.  Revenues from the marketing of crude oil and natural gas decreased $2.46 billion period-to-period primarily due to lower sales prices, which accounted for a $1.76 billion decrease, and lower sales volumes, which accounted for an additional $700.7 million decrease.  Revenues from the marketing of NGLs decreased a net $977.3 million period-to-period primarily due to lower sales prices, which accounted for a $2.02 billion decrease, partially offset by the effects of higher sales volumes, which resulted in a $1.04 billion increase.  Revenues from the marketing of petrochemicals and refined products increased a net $59.2 million period-to-period primarily due to higher sales volumes, which accounted for a $691.1 million increase, partially offset by lower sales prices, which resulted in a $631.9 million decrease.

57


Revenues from midstream services for the six months ended June 30, 2020 decreased $ 211.5 million when compared to the six months ended June 30, 2019.  Revenues from our natural gas processing facilities decreased a net $ 122.1 million period-to-period primarily due to the impact of lower NGL prices in the six months ended June 30, 2020 compared to the six months ended June 30, 2019 on the value of equity NGLs we receive as non-cash consideration for processing services.  Revenues from our Midland-to-ECHO 2 pipeline, which commenced limited service in February 2019 and full service in April 2019, increased $ 29.6 million period-to-period. Revenues from our other pipeline assets decreased $76.5 million period-to-period primarily due to lower demand for crude oil, natural gas and refined products. Lastly, third party revenues from our Mont Belvieu NGL fractionation complex decreased $ 64.6 million period-to-period primarily due to lower fractionation fees.

Operating costs and expenses

Second Quarter of 2020 Compared to Second Quarter of 2019 . Total operating costs and expenses for the second quarter of 2020 decreased $2.43 billion when compared to the second quarter of 2019 primarily due to lower cost of sales.  The cost of sales associated with our marketing of crude oil and natural gas decreased a combined $1.51 billion quarter-to-quarter primarily due to lower purchase prices, which accounted for a $1.24 billion decrease, and lower sales volumes, which accounted for an additional $264.6 million decrease.  The cost of sales associated with our marketing of NGLs decreased a net $949.5 million quarter-to-quarter primarily due to lower purchase prices, which accounted for a $1.2 billion decrease, partially offset by higher sales volumes, which accounted for a $255.4 million increase.  The cost of sales associated with our marketing of petrochemicals and refined products increased a net $43.3 million quarter-to-quarter primarily due to higher sales volumes, which accounted for a $350.9 million increase, partially offset by lower purchase prices, which accounted for a $307.6 million decrease.

Other operating costs and expenses for the second quarter of 2020 decreased $53.1 million quarter-to-quarter primarily due to lower maintenance, chemical and power-related expenses, which accounted for a $79.7 million decrease, partially offset by higher ad valorem taxes, which accounted for a $20.3 million increase.  Depreciation, amortization and accretion expense increased $31.5 million quarter-to-quarter primarily due to assets placed into full or limited service since the second quarter of 2019 (e.g., the isobutane dehydrogenation (“iBDH”) plant, Mentone facility, Mont Belvieu Frac X and the Enterprise Navigator ethylene terminal).

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019 . Total operating costs and expenses for the six months ended June 30, 2020 decreased $3.39 billion when compared to the six months ended June 30, 2019 primarily due to lower cost of sales.  The cost of sales associated with our marketing of crude oil and natural gas decreased a combined $2.21 billion period-to-period primarily due to lower purchase prices, which accounted for a $1.69 billion decrease, and lower sales volumes, which accounted for an additional $520.8 million decrease.  The cost of sales associated with our marketing of NGLs decreased a net $1.26 billion period-to-period primarily due to lower purchase prices, which accounted for a $2.08 billion decrease, partially offset by higher sales volumes, which accounted for an $828.5 million increase. The cost of sales associated with our marketing of petrochemicals and refined products increased a net $40.6 million period-to-period primarily due to higher sales volumes, which accounted for a $628.0 million increase, partially offset by lower purchase prices, which accounted for a $587.4 million decrease.

Other operating costs and expenses for the six months ended June 30, 2020 decreased $29.1 million period-to-period primarily due to lower maintenance and power-related expenses, which accounted for an $82.3 million decrease, partially offset by higher ad valorem taxes and employee compensation costs, which accounted for a $56.9 million increase.  Depreciation, amortization and accretion expense increased $63.4 million period-to-period primarily due to assets placed into full or limited service since the first quarter of 2019 (e.g., the iBDH plant, Mentone and Orla facilities, Mont Belvieu Frac X and the Enterprise Navigator ethylene terminal).

General and administrative costs

General and administrative costs for the three and six months ended June 30, 2020 increased $ 4.5 million and $ 7.8 million, respectively, when compared to the same periods in 2019 primarily due to higher employee compensation costs and professional services expense.

58


Equity in income of unconsolidated affiliates

Equity income from our unconsolidated affiliates for the three and six months ended June 30, 2020 decreased $ 24.1 million and $ 37.9 million, respectively, when compared to the same periods in 2019 primarily due to decreased earnings from our investments in crude oil pipelines.

Operating income

Operating income for the three and six months ended June 30, 2020 decreased $ 123.4 million and $ 242.1 m illion, respectively, when compared to the same periods in 2019 due to the previously described quarter-to-quarter and period-to-period changes in revenues, operating costs and expenses, general and administrative costs and equity in income of unconsolidated affiliates.

Interest expense

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

For the Three Months
Ended June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
Interest charged on debt principal outstanding
$
334.0
$
307.4
$
665.5
$
614.9
Impact of interest rate hedging program, including related amortization (1)
9.7
8.7
19.3
7.6
Interest costs capitalized in connection with construction projects (2)
(31.9
)
(32.8
)
(62.4
)
(69.0
)
Other (3)
8.4
6.8
15.3
13.8
Total
$
320.2
$
290.1
$
637.7
$
567.3

(1)
Amount presented for the six months ended June 30, 2019 includes $ 9.8 million of swaption premium income.
(2)
We capitalize interest costs incurred on funds used to construct property, plant and equipment while the asset is in its construction phase.  Capitalized interest amounts become part of the historical cost of an asset and are charged to earnings (as a component of depreciation expense) on a straight-line basis over the estimated useful life of the asset once the asset enters its intended service.  When capitalized interest is recorded, it reduces interest expense from what it would be otherwise.  Capitalized interest amounts fluctuate based on the timing of when projects are placed into service, our capital investment levels and the interest rates charged on borrowings.
(3)
Primarily reflects facility commitment fees charged in connection with our revolving credit facilities and amortization of debt issuance costs.

Interest charged on debt principal outstanding, which is a key driver of interest expense, increased a net $26.6 million quarter-to-quarter primarily due to increased debt principal amounts outstanding during the second quarter of 2020, which accounted for a $31.0 million increase, partially offset by the effect of lower overall interest rates during the second quarter of 2020, which accounted for a $4.4 million decrease.  Our weighted-average debt principal balance for the second quarter of 2020 was $29.9 billion compared to $ 27.1 billion for the second quarter of 2019.  For the six months ended June 30, 2020, interest charged on debt principal outstanding increased a net $ 50.6 million period-to-period primarily due to increased debt principal amounts outstanding during the six months ended June 30, 2020, which accounted for a $ 62.2 million increase, partially offset by the effect of lower overall interest rates during the six months ended June 30, 2020, which accounted for an $ 11.6 million decrease.  Our weighted-average debt principal balance for the six months ended June 30, 2020 was $ 29.61 billion compared to $ 26.9 billion for the six months ended June 30, 2019.  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

For the period in which the Liquidity Option was outstanding, we recognized non-cash expense in connection with accretion and changes in management estimates that affected the valuation of the Liquidity Option liability.  As discussed in the following section, Income taxes , our obligations under the Liquidity Option Agreement were settled on March 5, 2020.


59


Expense attributable to changes in the fair value of the Liquidity Option were $26.6 million and $84.4 million during the three and six months ended June 30, 2019, respectively.  Expense of $2.3 million for the first quarter of 2020 primarily reflects accretion expense for the period in which the Liquidity Option liability was outstanding before it was settled on March 5, 2020.  The higher level of expense recognized in the three and six months ended June 30, 2019 was primarily due to a decrease in the discount factor used in determining the present value of the liability.

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 June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
Settlement of Liquidity Option at March 5, 2020
$
72.2
Deferred tax benefit (expense) attributable to OTA
$
(50.5
)
64.5
Texas Margin Tax
(7.0
)
$
(10.1
)
(14.7
)
$
(21.0
)
Other
(2.2
)
0.4
(2.5
)
(1.0
)
Benefit from (provision for) income taxes
$
(59.7
)
$
(9.7
)
$
119.5
$
(22.0
)

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 reflects the outside basis difference of OTA in the 54,807,352 EPD common units it owns. Upon settlement of the Liquidity Option, the Liquidity Option liability 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 taxes” line on our Unaudited Condensed Statement of Consolidated Operations for the six months ended June 30, 2020.

The deferred tax liability of OTA is subject to fluctuation due to changes in the market value of the EPD common units it owns relative to its underlying tax basis in the units. With respect to the second quarter of 2020, OTA recognized deferred income tax expense of $50.5 million primarily due to an increase in the market value of its investment in EPD common units since March 31, 2020.  At June 30, 2020, the deferred tax liability of OTA was $375.2 million. OTA recognized a deferred income tax benefit of $64.5 million through June 30, 2020 primarily due to a decrease in the market value of its investment in EPD common units since March 5, 2020. In total, earnings for the six months ended June 30, 2020 reflect a net $136.7 million of deferred income tax benefit attributable to OTA.

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.

Business Segment Highlights

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.

60


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


For the Three Months
Ended June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
Gross operating margin by segment:
NGL Pipelines & Services
$
968.1
$
966.3
$
2,010.1
$
1,925.5
Crude Oil Pipelines & Services
634.4
513.2
1,087.3
1,175.5
Natural Gas Pipelines & Services
208.9
301.8
492.7
566.1
Petrochemical & Refined Products Services
191.5
304.9
470.0
547.5
Total segment gross operating margin (1)
2,002.9
2,086.2
4,060.1
4,214.6
Net adjustment for shipper make-up rights
(4.5
)
(5.7
)
(14.2
)
(0.4
)
Total gross operating margin (non-GAAP)
$
1,998.4
$
2,080.5
$
4,045.9
$
4,214.2

(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.

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

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

For the Three Months
Ended June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
Operating income
$
1,436.9
$
1,560.3
$
2,944.4
$
3,186.5
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
494.3
462.8
977.1
913.7
Asset impairment and related charges in operating costs and expenses
11.8
7.0
13.4
11.8
Net gains attributable to asset sales in operating costs and expenses
(1.6
)
(2.1
)
(1.5
)
(2.5
)
General and administrative costs
57.0
52.5
112.5
104.7
Total gross operating margin (non-GAAP)
$
1,998.4
$
2,080.5
$
4,045.9
$
4,214.2

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

Our segment results for the second quarter of 2020 reflect the challenging business environment we are currently experiencing due to the COVID-19 pandemic.  A number of our assets were impacted by lower volumes due to reduced drilling activity and downstream refinery activity and demand for transportation fuels.  For a general discussion of the impact of COVID-19 on our partnership and industry, see “ Update on 2020 Outlook” within this Item 2.
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NGL Pipelines & Service s

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

For the Three Months
Ended June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
Segment gross operating margin:
Natural gas processing and related NGL marketing activities
$
199.2
$
248.6
$
451.5
$
541.3
NGL pipelines, storage and terminals
606.3
588.7
1,259.6
1,146.0
NGL fractionation
162.6
129.0
299.0
238.2
Total
$
968.1
$
966.3
$
2,010.1
$
1,925.5
Selected volumetric data:
NGL pipeline transportation volumes (MBPD)
3,482
3,587
3,622
3,523
NGL marine terminal volumes (MBPD)
701
625
721
584
NGL fractionation volumes (MBPD)
1,154
1,000
1,186
984
Equity NGL production volumes (MBPD) (1)
188
144
164
150
Fee-based natural gas processing volumes (MMcf/d) (2, 3)
4,136
4,705
4,398
4,733

(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 plants.
(3)
Fee-based natural gas processing volumes are measured at either the wellhead or plant inlet in MMcf/d.  For the third and fourth quarters of 2019, fee-based natural gas processing volumes measured in this manner were 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.

Natural gas processing and related NGL marketing activities
Second Quarter of 2020 Compared to Second Quarter of 2019 .  Gross operating margin from natural gas processing and related NGL marketing activities for the second quarter of 2020 decreased $49.4 million when compared to the second quarter of 2019.

Gross operating margin from our Rocky Mountain natural gas processing facilities (Meeker, Pioneer and Chaco plants) decreased a combined $39.8 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities).  Lower composite NGL prices impacted processing margins, which declined 34% in the second quarter of 2020 when compared to the second quarter of 2019. On a combined basis, fee-based natural gas processing volumes decreased 337 MMcf/d and equity NGL production volumes increased 7 MBPD quarter-to-quarter.  Gross operating margin from our South Texas natural gas processing facilities decreased $17.8 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 lower average processing fees, which accounted for an additional $3.3 million decrease.  Fee-based natural gas processing volumes decreased 138 MMcf/d and equity NGL production volumes increased 12 MBPD quarter-to-quarter.

Gross operating margin from our Permian Basin natural gas processing facilities decreased $4.7 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $5.0 million decrease, lower average processing fees, which accounted for a $4.9 million decrease, and higher operating costs, which accounted for an additional $4.2 million decrease, partially offset by higher processing volumes, which accounted for a $9.7 million increase. Fee-based natural gas processing and equity NGL production volumes at our Permian Basin natural gas processing facilities increased 243 MMcf/d and 21 MBPD, respectively, quarter-to-quarter primarily due to additional processing capacity at our Orla facility completed in July 2019 and the start-up of our Mentone facility in December 2019.

Gross operating margin from our Louisiana and Mississippi natural gas processing facilities decreased $7.3 million quarter-to-quarter primarily due to lower average processing margins, which accounted for an $11.0 million decrease, partially offset by lower operating costs, which accounted for a $4.1 million increase.  Net to our interest, fee-based natural gas processing volumes decreased 373 MMcf/d quarter-to-quarter.

62


Gross operating margin from our NGL marketing activities increased a net $23.0 million quarter-to-quarter primarily due to higher sales volumes, which accounted for a $79.0 million increase, partially offset by lower average sales margins, which accounted for a $56.2 million decrease.  Results from marketing strategies that optimize our transportation and storage assets increased a combined $21.3 million quarter-to-quarter, partially offset by lower earnings from the optimization of our export and plant assets, which accounted for a $30.1 million decrease.  In addition, results from NGL marketing increased $31.8 million quarter-to-quarter due to non-cash, mark-to-market gains of $35.4 million in the second quarter of 2020.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019 .  Gross operating margin from natural gas processing and related NGL marketing activities for the six months ended June 30, 2020 decreased $89.8 million when compared to the six months ended June 30, 2019.  Gross operating margin from our Rocky Mountain natural gas processing facilities decreased a combined $57.6 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities).  On a combined basis, fee-based natural gas processing and equity NGL volumes decreased 258 MMcf/d and 5 MBPD, respectively, period-to-period.  Gross operating margin from our South Texas natural gas processing facilities decreased $42.6 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $32.4 million decrease, lower processing volumes, which accounted for a $5.4 million decrease, and lower average processing fees, which accounted for an additional $4.5 million decrease.  Fee-based natural gas processing volumes decreased 92 MMcf/d and equity NGL production volumes increased 7 MBPD period-to-period.

Gross operating margin from our Permian Basin natural gas processing facilities decreased $19.2 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $17.3 million decrease, higher operating costs, which accounted for an $11.8 million decrease, and lower average processing fees, which accounted for an additional decrease of $9.6 million, partially offset by higher processing volumes, which accounted for a $19.6 million increase.  Fee-based natural gas processing and equity NGL production volumes at our Permian Basin natural gas processing facilities increased 258 MMcf/d and 11 MBPD, respectively, period-to-period, primarily due to additional processing capacity at our Orla facility completed in July 2019 and the start-up of our Mentone facility in December 2019.

Gross operating margin from our Louisiana and Mississippi natural gas processing facilities decreased $12.8 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $19.8 million decrease, partially offset by lower operating costs, which accounted for a $5.2 million increase.  Net to our interest, fee-based natural gas processing volumes decreased 291 MMcf/d period-to-period.

Gross operating margin from our NGL marketing activities increased a net $48.5 million period-to-period primarily due to higher sales volumes, which accounted for a $159.0 million increase, partially offset by lower average sales margins, which accounted for a $110.2 million decrease.  Results from marketing strategies that optimize our storage, transportation and export assets increased a combined $39.1 million period-to-period, partially offset by lower earnings from the optimization of our plant assets, which accounted for a $9.7 million decrease.  In addition, results from NGL marketing increased $19.1 million period-to-period due to non-cash, mark-to-market gains of $23.1 million in the six months ended June 30, 2020.

NGL pipelines, storage and terminals
Second Quarter of 2020 Compared to Second Quarter of 2019 . Gross operating margin from our NGL pipelines, storage and terminal assets during the second quarter of 2020 increased $17.6 million when compared to the second quarter of 2019.

Gross operating margin from LPG-related activities at EHT increased $15.5 million quarter-to-quarter primarily due to higher export volumes of 99 MBPD.  The increase in export volumes is attributable to an LPG expansion project at EHT that was completed in the third quarter of 2019. Gross operating margin from our Houston Ship Channel Pipeline System increased $ 3.7 million quarter-to-quarter primarily due to a 29 MBPD increase in transportation volumes.

Gross operating margin from our Aegis Pipeline increased $8.9 million quarter-to-quarter primarily due to a 168 MBPD increase in transportation volumes associated with contract commitments. Gross operating margin from our Dixie Pipeline and related terminals increased a combined $ 4.9 million quarter-to-quarter primarily due to higher average transportation fees.

63


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 increased $5.3 million quarter-to-quarter primarily due to higher average fees, which accounted for a $15.7 million increase, lower operating costs, which accounted for an additional $6.7 million increase, partially offset by lower transportation volumes of 166 MBPD (net to our interest), which accounted for a $17.9 million decrease.

Gross operating margin from our South Texas NGL Pipeline System decreased $6.6 million quarter-to-quarter primarily due to lower pipeline capacity fee revenues earned from an affiliate pipeline.  Transportation volumes on our South Texas NGL Pipeline System increased 16 MBPD quarter-to-quarter.

Gross operating margin from our Lou-Tex NGL Pipeline decreased $3.8 million quarter-to-quarter primarily due to lower transportation volumes of 42 MBPD.  Gross operating margin from our South Louisiana NGL Pipeline System decreased $3.5 million quarter-to-quarter primarily due to lower transportation volumes of 78 MBPD.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019 . Gross operating margin from our NGL pipelines, storage and terminal assets during the six months ended June 30, 2020 increased $113.6 million when compared to the six months ended June 30, 2019.

Gross operating margin from LPG-related activities at EHT increased $48.6 million period-to-period primarily due to higher export volumes of 151 MBPD. Gross operating margin from our Houston Ship Channel Pipeline System increased $ 11.8 million period-to-period primarily due to a 118 MBPD increase in transportation volumes.

Gross operating margin from our Aegis Pipeline increased $27.8 million period-to-period primarily due to a 161 MBPD increase in transportation volumes associated with contract commitments.

Gross operating margin from our Dixie Pipeline and related terminals increased a combined $ 7.9 million period-to-period primarily due to higher transportation volumes of 13 MBPD, which accounted for a $3.6 million increase, and higher average transportation fees, which accounted for an additional $2.6 million increase.

On a combined basis, gross operating margin from our pipelines serving Permian Basin and/or Rocky Mountain producers increased $52.1 million period-to-period primarily due to higher average fees, which accounted for a $29.0 million increase, lower operating costs, which accounted for an additional $19.7 million increase, partially offset by lower transportation volumes of 114 MBPD (net to our interest), which accounted for a $23.8 million decrease.  The $52.1 million increase also includes gross operating margin from our Shin Oak NGL Pipeline, which increased $24.3 million period-to-period primarily due to the first six months of 2019 reflecting a ramp-up of transportation volumes following its start-up in February 2019.

Gross operating margin from our Appalachia-to-Texas Express (“ATEX”) pipeline decreased $ 8.9 million period-to-period primarily due to lower transportation volumes, which decreased 17 MBPD period-to-period.

Gross operating margin from our South Texas NGL Pipeline System decreased $8.9 million period-to-period primarily due to lower pipeline capacity fee revenues earned from an affiliate pipeline.  Transportation volumes on our South Texas NGL Pipeline System increased 25 MBPD period-to-period.

Gross operating margin from our Mont Belvieu storage facility decreased $ 7.7 million period-to-period primarily due to lower handling fee revenues, which accounted for an $18.5 million decrease, partially offset by higher storage and throughput fees, which accounted for a $10.6 million increase.

64


NGL fractionation
Second Quarter of 2020 Compared to Second Quarter of 2019 .  Gross operating margin from NGL fractionation during the second quarter of 2020 increased $33.6 million when compared to the second quarter of 2019. Gross operating margin from our Mont Belvieu NGL fractionation complex increased $27.7 million quarter-to-quarter primarily due to higher fractionation volumes, which increased 166 MBPD quarter-to-quarter (net to our interest) primarily due to the start-up of the first fractionation train (“Frac X”) at our newly constructed NGL fractionation facility located in Chambers County, Texas.  Gross operating margin from our South Texas NGL fractionators increased $5.1 million quarter-to-quarter primarily due to lower operating costs at our Shoup fractionator, which underwent major maintenance activities during the second quarter of 2019.  NGL fractionation volumes at our South Texas facilities increased 13 MBPD quarter-to-quarter.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019 .  Gross operating margin from NGL fractionation during the six months ended June 30, 2020 increased $60.8 million when compared to the six months ended June 30, 2019. Gross operating margin from our Mont Belvieu NGL fractionation complex increased $27.7 million primarily due to higher fractionation volumes, which increased 168 MBPD period-to-period (net to our interest) primarily due to the start-up of Frac X. Gross operating margin at our Hobbs NGL fractionator increased $17.8 million period-to-period primarily due to major maintenance activities during the first quarter of 2019.  NGL fractionation volumes at our Hobbs NGL fractionator increased 11 MBPD period-to-period.  Gross operating margin from our South Texas NGL fractionators increased $5.7 million period-to-period primarily due to higher NGL fractionation volumes of 22 MBPD.

Crude Oil Pipelines & Services

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

For the Three Months
Ended June 30,
For the Six Months
Ended June 30,
2020
2019
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
$
53.1
$
109.6
$
113.3
$
209.4
Non-cash mark-to-market gains
–
14.0
0.9
81.2
Total Midland-to-ECHO 1 pipeline and related business activities
53.1
123.6
114.2
290.6
Midland-to-ECHO 2 pipeline
38.9
28.1
68.2
45.5
Total Midland-to-ECHO System
92.0
151.7
182.4
336.1
Other crude oil pipelines, terminals and related marketing results
542.4
361.5
904.9
839.4
Total
$
634.4
$
513.2
$
1,087.3
$
1,175.5
Selected volumetric data:
Crude oil pipeline transportation volumes (MBPD)
1,890
2,378
2,141
2,310
Crude oil marine terminal volumes (MBPD)
726
985
854
935

Second Quarter of 2020 Compared to Second Quarter of 2019 .  Gross operating margin from our Crude Oil Pipelines & Services segment for the second quarter of 2020 increased $121.2 million when compared to the second quarter of 2019.

Gross operating margin from other crude oil marketing activities increased $ 219.3 million quarter-to-quarter primarily due to higher average sales margins, which accounted for a $ 185.2 million increase, and higher non-cash mark-to-market earnings, which accounted for an additional $36.6 million increase.  Results for the second quarter of 2020 were primarily attributable to higher margins from using uncontracted storage capacity for contango opportunities and regional price spreads.

Gross operating margin from crude oil activities at EHT increased $5.4 million quarter-to-quarter primarily due to higher average terminal fees, which accounted for an $18.0 million increase, lower operating costs, which accounted for an additional $7.7 million increase, partially offset by a $20.7 million decrease due to lower volumes of 249 MBPD.

65


Gross operating margin from our Midland-to-ECHO System (Midland-to-ECHO 1 and 2 pipelines) and related business activities decreased $59.7 million quarter-to-quarter primarily due to lower earnings from marketing activities, which accounted for a $53.9 million decrease (including lower non-cash mark-to-market results of $14.0 million), lower transportation volumes, which accounted for an additional $22.7 million decrease, partially offset by lower chemical and other operating costs of $21.5 million.  Gross operating margin from our equity investment in the Eagle Ford Crude Oil Pipeline decreased $12.1 million quarter-to-quarter primarily due to lower transportation volumes.  Gross operating margin from our South Texas Crude Oil Pipeline System decreased $7.8 million quarter-to-quarter primarily due to lower transportation and other fees in the second quarter of 2020.  On an aggregate basis, transportation volumes on these three pipeline systems decreased 225 MBPD quarter-to-quarter (net to our interest).

Gross operating margin from our ECHO terminal decreased $16.3 million quarter-to-quarter primarily due to a benefit recognized during the second quarter of 2019 in connection with a settlement.

Gross operating margin from our equity investment in the Seaway Pipeline decreased $10.7 million quarter-to-quarter primarily due to lower average transportation volumes, which accounted for a $17.1 million decrease, and lower transportation fees, which accounted for an additional $10.0 million decrease, partially offset by lower operating costs of $12.3 million.  Net to our interest, transportation volumes on the Seaway Pipeline decreased 193 MBPD quarter-to-quarter.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019 .  Gross operating margin from our Crude Oil Pipelines & Services segment for the six months ended June 30, 2020 decreased $88.2 million when compared to the six months ended June 30, 2019.

Gross operating margin from our Midland-to-ECHO System and related business activities decreased $153.7 million period-to-period primarily due to lower earnings from marketing activities of $165.2 million, which includes lower non-cash mark-to-market results of $80.3 million period-to-period, partially offset by lower chemical and other operating costs of $15.9 million. Gross operating margin from our South Texas Crude Oil Pipeline System decreased $17.3 million period-to-period primarily due to lower deficiency and other fees during the six months ended June 30, 2020.  Gross operating margin from our equity investment in the Eagle Ford Crude Oil Pipeline decreased $12.5 million period-to-period primarily due to lower transportation volumes of 32 MBPD (net to our interest).

Gross operating margin from our ECHO terminal decreased $18.0 million period-to-period primarily due to a benefit recognized during the second quarter of 2019 in connection with a settlement.

Gross operating margin from our equity investment in the Seaway Pipeline decreased $27.2 million period-to-period primarily due to lower average transportation volumes, which accounted for a $25.1 million decrease, and lower transportation fees, which accounted for an additional $18.0 million decrease, partially offset by lower operating costs of $14.4 million.  Net to our interest, transportation volumes on the Seaway Pipeline decreased 122 MBPD period-to-period.

Gross operating margin from other crude oil marketing activities increased $ 101.3 million period-to-period primarily due to higher average sales margins, which accounted for a $ 90.3 million increase, and higher non-cash mark-to-market earnings, which accounted for an additional $ 13.8 million increase.

Gross operating margin from crude oil activities at EHT increased $20.8 million period-to-period primarily due to higher storage revenues and average terminal fees, which accounted for a combined $22.8 million increase, lower operating costs, which accounted for an additional $6.6 million increase, partially offset by a $12.1 million decrease due to lower volumes of 93 MBPD. Lastly, gross operating margin from our West Texas System increased $11.3 million period-to-period primarily due to higher transportation volumes of 22 MBPD.

66


Natural Gas Pipelines & Services

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

For the Three Months
Ended June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
Segment gross operating margin
$
208.9
$
301.8
$
492.7
$
566.1
Selected volumetric data:
Natural gas pipeline transportation volumes (BBtus/d)
12,975
14,349
13,419
14,274

Second Quarter of 2020 Compared to Second Quarter of 2019 .  Gross operating margin from our Natural Gas Pipelines & Services segment for the second quarter of 2020 decreased $92.9 million when compared to the second quarter of 2019.

Gross operating margin from our natural gas marketing activities decreased $35.5 million quarter-to-quarter primarily due to lower average sales margins from regional natural gas price spreads across Texas.

Gross operating margin from our Texas Intrastate System decreased $34.8 million quarter-to-quarter primarily due to lower capacity reservation revenues. Transportation volumes on our Texas Intrastate System decreased 593 BBtus/d quarter-to-quarter.  Gross operating margin from our Acadian Gas System decreased $24.0 million quarter-to-quarter primarily due to lower capacity reservation revenues on the Haynesville Extension pipeline, which accounted for a $12.1 million decrease, and a benefit recognized during the second quarter of 2019 in connection with a settlement, which accounted for an additional decrease of $11.3 million.  Transportation volumes on our Acadian Gas System decreased 163 BBtus/d quarter-to-quarter.

On a combined basis, gross operating margin from our Jonah Gathering System, Piceance Basin Gathering System, San Juan Gathering System and equity investment in the White River Hub decreased $4.4 million quarter-to-quarter primarily due to aggregate lower volumes of 586 BBtus/d.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019 .  Gross operating margin from our Natural Gas Pipelines & Services segment for the six months ended June 30, 2020 decreased $73.4 million when compared to the six months ended June 30, 2019.

Gross operating margin from our Texas Intrastate System decreased $43.5 million period-to-period primarily due to lower capacity reservation revenues.  Transportation volumes on our Texas Intrastate System decreased 281 BBtus/d period-to-period.  Gross operating margin from our Acadian Gas System decreased $23.3 million period-to-period primarily due to lower  capacity reservation revenues on the Haynesville Extension pipeline.  Transportation volumes on our Acadian Gas System decreased 94 BBtus/d period-to-period.  Gross operating margin from our Haynesville Gathering System decreased $12.5 million period-to-period primarily due to lower gathering, compression and other fee revenues, which accounted for a $9.6 million decrease, and lower gathering volumes of 175 BBtus/d, which accounted for an additional $5.5 million decrease.

Gross operating margin from our Permian Basin Gathering System increased $13.7 million period-to-period primarily due to a 290 BBtus/d increase in natural gas gathering volumes.

On a combined basis, gross operating margin from our Jonah Gathering System, Piceance Basin Gathering System, San Juan Gathering System and equity investment in the White River Hub decreased $11.3 million period-to-period primarily due to aggregate lower volumes of 497 BBtus/d.

Gross operating margin from our natural gas marketing activities decreased $3.9 million period-to-period primarily due to lower average sales margins, which accounted for a $27.5 million decrease, lower sales volumes, which accounted for an additional $8.2 million decrease, partially offset by higher mark-to-market results.   The first six months of 2020 includes $32.7 million of mark-to-market gains compared to $0.9 million of such gains for the same period in 2019.

67


Petrochemical & Refined Products Services

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

For the Three Months
Ended June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
Segment gross operating margin:
Propylene production and related activities
$
60.5
$
133.7
$
169.1
$
236.0
Butane isomerization and related operations
10.1
21.2
26.2
45.2
Octane enhancement and related plant operations
36.7
52.5
105.7
76.8
Refined products pipelines and related activities
66.3
85.3
141.4
167.2
Marine transportation and other services
17.9
12.2
27.6
22.3
Total
$
191.5
$
304.9
$
470.0
$
547.5
Selected volumetric data:
Propylene production volumes (MBPD)
72
104
85
97
Butane isomerization volumes (MBPD)
68
109
86
110
Standalone DIB processing volumes (MBPD)
130
96
118
94
Octane enhancement and related plant sales volumes (MBPD) (1)
32
39
33
31
Pipeline transportation volumes, primarily refined products &
petrochemicals (MBPD)
786
672
748
740
Marine terminal volumes, primarily refined products and
petrochemicals (MBPD)
250
396
261
367

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

Propylene production and related activities
Second Quarter of 2020 Compared to Second Quarter of 2019 . Gross operating margin from propylene production and related activities for the second quarter of 2020 decreased $73.2 million when compared to the second quarter of 2019 primarily due to lower average sales margins, which accounted for a $51.9 million decrease, and lower propylene and associated by-product sales volumes, which accounted for an additional $20.1 million decrease.  Propylene production volumes decreased 32 MBPD quarter-to-quarter (net to our interest).  Our propane dehydrogenation facility experienced 46 days of unplanned downtime in the second quarter of 2020 primarily for major maintenance activities.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019 . Gross operating margin from propylene production and related activities for the six months ended June 30, 2020 decreased $66.9 million when compared to the six months ended June 30, 2019 primarily due to lower average sales margins, which accounted for a $50.4 million decrease, and lower propylene and associated by-product sales volumes, which accounted for an additional $12.6 million decrease.  Propylene production volumes decreased 12 MBPD period-to-period (net to our interest).

Isomerization and related operations
Second Quarter of 2020 Compared to Second Quarter of 2019 . Gross operating margin from isomerization and related operations decreased $11.1 million quarter-to-quarter primarily due to lower average by-product sales prices, which accounted for a $7.7 million decrease, and lower volumes of 41 MBPD, which accounted for an additional $7.3 million decrease, partially offset by lower operating costs, which accounted for a $6.3 million increase.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019 . Gross operating margin from isomerization and related operations decreased $19.0 million period-to-period primarily due to lower average by-product sales prices, which accounted for a $15.9 million decrease, and lower volumes of 24 MBPD, which accounted for an additional $8.3 million decrease, partially offset by lower operating costs, which accounted for a $10.6 million increase.

Octane enhancement and related plant operations
Second Quarter of 2020 Compared to Second Quarter of 2019 . Gross operating margin from our octane enhancement and related plant operations decreased $15.8 million quarter-to-quarter primarily due to lower sales volumes, which accounted for a $10.9 million decrease, and higher operating expenses, which accounted for an additional $4.0 million decrease.  The decrease in sales volumes for the second quarter of 2020 was primarily due to lower international demand for motor gasoline resulting from shelter-in-place mandates caused by the pandemic.
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Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019 . Gross operating margin from our octane enhancement and related plant operations increased $28.9 million period-to-period primarily due to higher average sales margins, which accounted for a $30.0 million increase, and higher sales volumes, which accounted for an additional $7.5 million increase, partially offset by higher operating expenses, which accounted for a $10.4 million decrease.

Refined products pipelines and related activities
Second Quarter of 2020 Compared to Second Quarter of 2019 . Gross operating margin from refined products pipelines and related activities during the second quarter of 2020 decreased $19.0 million when compared to the second quarter of 2019 primarily due to lower interstate refined product transportation volumes of 55 MBPD on our TE Products Pipeline System, which accounted for a $9.5 million decrease, and higher operating expenses, which accounted for an additional $5.6 million decrease.   Overall transportation volumes on our TE Products Pipeline System increased a net 82 MBPD quarter-to-quarter, which was primarily due to higher petrochemical transport volumes in southeast Texas.

Gross operating margin at our refined products terminal in Beaumont, Texas decreased $4.9 million quarter-to-quarter primarily due to lower storage revenues.  Terminaling volumes at Beaumont decreased a net 127 MBPD quarter-to-quarter.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019 . Gross operating margin from refined products pipelines and related activities during the six months ended June 30, 2020 decreased $25.8 million when compared to the six months ended June 30, 2019.  Gross operating margin at our TE Products Pipeline System decreased $18.2 million when compared to the six months ended June 30, 2019 primarily due to higher operating costs, which accounted for a $9.6 million decrease, and lower interstate refined product transportation volumes of 31 MBPD, which accounted for an additional $8.3 million decrease.  Overall transportation volumes on our TE Products Pipeline System decreased a net 2 MBPD period-to-period.

Gross operating margin at our refined products terminal in Beaumont, Texas decreased $10.2 million period-to-period primarily due to lower storage revenues.  Terminaling volumes at Beaumont decreased a net 82 MBPD period-to-period.

Marine transportation and other services
Second Quarter of 2020 Compared to Second Quarter of 2019 .  Gross operating margin from marine transportation and other services during the second quarter of 2020 increased $5.7 million when compared to the second quarter of 2019.  Gross operating margin from our ethylene export terminal and related operations was $5.0 million for the second quarter of 2020.  Loading volumes at our ethylene export terminal, which was placed into limited service in December 2019, were 9 MBPD during the second quarter of 2020.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019 .  Gross operating margin from marine transportation and other services during the six months ended June 30, 2020 increased $5.3 million when compared to the six months ended June 30, 2019.   Gross operating margin from our ethylene export terminal and related operations was $2.3 million for the six months ended June 30, 2020.  Loading volumes at our ethylene export terminal were 6 MBPD during the six months ended June 30, 2020.

Liquidity and Capital Resources

Based on current market conditions (as of the filing date of this quarterly report), we believe we will have sufficient liquidity, cash flow from operations and access to capital markets to fund our capital investments and working capital needs for the reasonably foreseeable future.  At June 30, 2020, we had $ 7.3 billion of consolidated liquidity, which was comprised of $ 6.0 billion of available borrowing capacity under EPO’s revolving credit facilities and $ 1.3 b illion of unrestricted cash on hand.

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

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Consolidated Debt

At June 30, 2020, the average maturity of our consolidated debt obligations was approximately 19.9 years. The following table presents scheduled maturities of our consolidated debt obligations outstanding at June 30, 2020 for the years indicated (dollars in millions):

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

As discussed under “ Other Recent Developments ” within this Item 2, EPO issued $3.0 billion aggregate principal amount of senior notes in January 2020 and $1.25 billion aggregate principal amount of senior notes in August 2020.  In addition, EPO entered into its April 2020 364-Day Revolving Credit Agreement, which provides EPO with an incremental $1.0 billion of borrowing capacity.  At June 30, 2020, there were no principal amounts outstanding under the April 2020 364-Day Revolving Credit Agreement.

EPO’s September 2019 364-Day Revolving Credit Agreement is scheduled to mature in September 2020.  As a result, EPO expects to renew this credit agreement during the third quarter of 2020.  At June 30, 2020, there were no principal amounts outstanding under the September 2019 364-Day Revolving Credit Agreement.

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

Common Unit Buyback Program

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”).  EPD repurchased 6,357,739 common units under its 2019 Buyback Program through open market purchases in the six months ended June 30, 2020.  The total purchase price of these repurchases (including commissions and fees) was $ 140.1 million, and represented 2.1 % of our consolidated CFFO for the twelve months ended June 30, 2020 . The repurchased units were cancelled immediately upon acquisition. As of June 30, 2020 , the remaining available capacity under the 2019 Buyback Program was $ 1.78 billion.

In addition to the 2019 Buyback Program, privately held affiliates of EPCO acquired 1,459,000 of EPD’s common units on the open market during the six months ended June 30, 2020.  In the aggregate, 7,816,739 common units were purchased on the open market during the six months ended June 30, 2020 under the 2019 Buyback Program and by privately held affiliates of EPCO.

Credit Ratings

As of August 10, 2020, the investment-grade credit ratings of EPO’s long-term senior unsecured debt securities were BBB+ from Standard and Poor’s, Baa1 from Moody’s and BBB+ from Fitch Ratings.  In addition, the credit ratings of EPO’s short-term senior unsecured debt securities were A-2 from Standard and Poor’s, P-2 from Moody’s and F-2 from Fitch Ratings.  EPO’s credit ratings reflect only the view of a rating agency and should not be interpreted as a recommendation to buy, sell or hold any of our securities.  A credit rating can be revised upward or downward or withdrawn at any time by a rating agency, if it determines that circumstances warrant such a change.  A credit rating from one rating agency should be evaluated independently of credit ratings from other rating agencies.

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Issuance of Common Units

On March 5, 2020, 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 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 need for equity capital. During the six months ended June 30, 2020, a total of 3,379,971 common units were purchased on the open market and delivered to participants in connection with the DRIP and EUPP.  Apart from $1.3 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 August 12, 2020.

EPD issued and delivered a combined 2,897,990 common units in the six months ended June 30, 2019 in connection with the DRIP and EUPP, which generated net cash proceeds totaling $ 82.2 million.

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 Six Months
Ended June 30,
2020
2019
Net cash flows provided by operating activities
$
3,193.8
$
3,183.7
Cash used in investing activities
1,930.5
2,286.5
Cash used in financing activities
236.7
1,200.0

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

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

Operating activities
Net cash flows provided by operating activities for the six months ended June 30, 2020 increased a net $ 10.1 million when compared to the six months ended June 30, 2019 primarily due to:

•
a $ 243.0 million period-to-period increase primarily due to the timing of cash receipts and payments related to operations; partially offset by

•
a $ 199.4 m illion period-to-period decrease resulting from lower partnership earnings in the six months ended June 30, 2020 when compared to the six months ended June 30, 2019 (determined by adjusting our $ 81.1 million period-to-period decrease in net income for changes in the non-cash items identified on our Unaudited Condensed Statements of Consolidated Cash Flows); and
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•
a $ 33.5 million period-to-period decrease in cash distributions received on earnings from unconsolidated affiliates primarily attributable to our investments in crude oil pipelines.

For information regarding significant period-to-period 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 the six months ended June 30, 2020 decreased a net $ 356.0 m illion when compared to the six months ended June 30, 2019 primarily due to:

•
a $ 284.9 million period-to-period decrease in expenditures for consolidated property, plant and equipment (see “ Capital Investments ” within this Part I, Item 2 for additional information); and

•
a $ 52.6 million period-to-period decrease in investments in unconsolidated affiliates primarily related to NGL and crude oil pipeline projects.

Financing activities
Cash used in financing activities for the six months ended June 30, 2020 decreased a net $ 963.3 million when compared to the six months ended June 30, 2019 primarily due to:

•
a net $1.24 billion period-to-period increase in net cash inflows attributable to debt.  During the six months ended June 30, 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 six months ended June 30, 2019, we repaid or repurchased $724.2 million principal amount of senior and junior notes. In addition, net repayments of short term notes under EPO’s commercial paper program were $ 481.7 million during the six months ended June 30, 2020 compared to net issuances of $1.42 billion during the six months ended June 30, 2019 ; partially offset by

•
an $ 82.2 million period-to-period decrease in net cash proceeds from the issuance of common units in connection with our 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 $ 79.9 million period-to-period decrease in cash contributions from noncontrolling interests. C ash contributions from noncontrolling interests in connection with the construction of our ethylene export facility decreased $ 42.0 million period-to-period. In addition, in June 2019, an affiliate of Third Coast Midstream, LLC acquired a noncontrolling 25% equity interest in our consolidated subsidiary that owns the Pascagoula natural gas processing plant for $36.0 million in cash ;

•
a $ 59.0 million period-to-period increase in cash used to acquire common units under our 2019 Buyback Program; and

•
a $ 39.0 million period-to-period increase in cash distributions paid to limited partners primarily due to an increase in the quarterly cash distribution rate per unit.

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Non-GAAP Cash Flow Measures

Distributable Cash Flow
Our partnership agreement requires us to make quarterly distributions to our unitholders of all available cash, after any cash reserves established by Enterprise GP in its sole discretion.  Cash reserves include those for the proper conduct of our business, including those for capital 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.  Using this metric, management computes our distribution coverage ratio.   Our calculation of DCF may or may not be comparable to similarly titled measures used by other companies.

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

Our use of DCF for the limited purposes described above and in this report is not a substitute for net cash flows provided by operating activities, which is the most comparable GAAP measure. For a discussion of net cash flows provided by operating activities, see “ 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 June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
Net income attributable to limited partners (GAAP) (1)
$
1,034.7
$
1,214.7
$
2,384.8
$
2,475.2
Adjustments to net income attributable to limited partners to derive DCF
(addition or subtraction indicated by sign):
Depreciation, amortization and accretion expenses
522.7
488.6
1,031.7
963.1
Cash distributions received from unconsolidated affiliates (2)
178.4
171.0
315.6
314.5
Equity in income of unconsolidated affiliates
(113.3
)
(137.4
)
(254.1
)
(292.0
)
Change in fair market value of derivative instruments
(61.9
)
12.5
(91.4
)
(83.8
)
Change in fair value of Liquidity Option
–
26.6
2.3
84.4
Deferred income tax expense (benefit)
53.4
2.4
(130.7
)
4.2
Sustaining capital expenditures (3)
(74.0
)
(80.1
)
(142.9
)
(141.7
)
Other, net
33.8
9.7
44.8
10.8
Subtotal DCF, before proceeds from asset sales and monetization of interest rate derivative instruments accounted for as cash flow hedges
$
1,573.8
$
1,708.0
$
3,160.1
$
3,334.7
Proceeds from asset sales
3.5
14.4
4.1
16.1
Monetization of interest rate derivative instruments accounted for as cash flow hedges
–
–
(33.3
)
–
DCF (non-GAAP)
$
1,577.3
$
1,722.4
$
3,130.9
$
3,350.8
Cash distributions paid to limited partners with respect to period
$
979.9
$
969.1
$
1,959.7
$
1,932.6
Cash distribution per unit declared by Enterprise GP with respect to period (4)
$
0.4450
$
0.4400
$
0.8900
$
0.8775
Total DCF retained by partnership with respect to period (5)
$
597.4
$
753.3
$
1,171.2
$
1,418.2
Distribution coverage ratio (6)
1.6
x
1.8
x
1.6
x
1.7
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 distributions received from unconsolidated affiliates attributable to earnings and the return of capital.
(3)
Sustaining capital expenditures include cash payments and accruals applicable to the period.
(4)
See Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report for additional information regarding our quarterly cash distributions declared with respect to the years indicated.
(5)
At the sole discretion of Enterprise GP, cash retained by the partnership with respect to each of these periods was primarily reinvested in growth capital projects. This retainage of cash substantially reduced our reliance on the equity capital markets to fund such expenditures.
(6)
Distribution coverage ratio is determined by dividing DCF by total cash distributions paid to limited partners and in connection with distribution equivalent rights with respect to the period.

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 June 30,
For the Six Months
Ended June 30,
2020
2019
2020
2019
Net cash flows provided by operating activities (GAAP)
$
1,181.6
$
2,023.3
$
3,193.8
$
3,183.7
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
430.7
(227.8
)
89.0
332.0
Sustaining capital expenditures
(74.0
)
(80.1
)
(142.9
)
(141.7
)
Distributions received from unconsolidated affiliates attributable to the return of capital
47.7
18.9
58.0
23.4
Proceeds from asset sales
3.5
14.4
4.1
16.1
Net income attributable to noncontrolling interest
(26.1
)
(21.8
)
(51.0
)
(41.7
)
Monetization of interest rate derivative instruments accounted for as cash flow hedges
–
–
(33.3
)
–
Other, net
13.9
(4.5
)
13.2
(21.0
)
DCF (non-GAAP)
$
1,577.3
$
1,722.4
$
3,130.9
$
3,350.8
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Free Cash Flow
Free Cash Flow (“FCF”), a non-GAAP financial measure, is a traditional cash flow metric that is widely used by a variety of investors and other participants in the financial community, as opposed to DCF, which is a cash flow measure primarily used by investors and others in evaluating master limited partnerships. In general, FCF is a measure of how much cash flow a business generates during a specified time period after accounting for all capital investments, including expenditures for growth and sustaining capital projects. By comparison, only sustaining capital expenditures are reflected in DCF.

We believe that FCF is important to traditional investors since it reflects the amount of cash available for reducing debt, investing in additional capital projects, paying distributions, common unit repurchases and similar matters.  Since business partners fund certain capital projects of our consolidated subsidiaries, our determination of FCF reflects the amount of cash 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.

FCF fluctuates based on our earnings, the level of investing activities we undertake each period, and the timing of operating cash receipts and payments.  In addition to providing the quarterly amounts presented below, we also provide a calculation of aggregate FCF over the twelve months ended June 30, 2020 in order to measure FCF over a longer term. The following table summarizes our calculation of FCF for the periods indicated (dollars in millions):

For the Three Months
Ended June 30,
For the Six Months
Ended June 30,
For the Twelve Months Ended
June 30,
2020
2019
2020
2019
2020
Net cash flows provided by operating activities (GAAP)
$
1,181.6
$
2,023.3
$
3,193.8
$
3,183.7
$
6,530.6
Adjustments to net cash flows provided by operating activities to derive FCF (addition or subtraction indicated by sign):
Cash used in investing activities
(858.8
)
(1,112.0
)
(1,930.5
)
(2,286.5
)
(4,219.5
)
Cash contributions from noncontrolling interests
14.5
64.8
19.7
99.6
552.9
Cash distributions paid to noncontrolling interests
(31.9
)
(28.9
)
(61.8
)
(46.9
)
(121.1
)
FCF (non-GAAP)
$
305.4
$
947.2
$
1,221.2
$
949.9
$
2,742.9

For a discussion of primary drivers of our quarterly net cash flows provided by operating activities and cash used in investing activities, see “ Cash Flow Statement Highlights ” within this Part I, Item 2.

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 reviewed our planned capital investments in light of these adverse macroeconomic events.

As previously noted and based on information currently available, we now expect our total capital investments for 2020 to approximate $2.8 billion to $3.3 billion, which reflects growth capital investments of $2.5 billion to $3.0 billion and approximately $300 million for sustaining capital expenditures. Based on sanctioned projects, we currently expect our growth capital investments for 2021 and 2022 to approximate $2.3 billion and $1.0 billion, respectively.

Our revised forecast of capital investments for 2020 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 March 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 $6.6 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 into 2021);

•
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 our Acadian Gas System (Gillis Lateral and related projects) (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 Six Months
Ended June 30,
2020
2019
Capital investments for property, plant and equipment: (1)
Growth capital projects (2)
$
1,830.0
$
2,116.4
Sustaining capital projects (3)
145.9
144.4
Total
$
1,975.9
$
2,260.8
Investments in unconsolidated affiliates
$
7.3
$
59.9

(1)
Growth and sustaining capital amounts presented in the table above are presented on a cash basis.
(2)
Growth capital projects either (a) result in new sources of cash flow due to enhancements of or additions to existing assets (e.g., additional revenue streams, cost savings resulting from debottlenecking of a facility, etc.) or (b) expand our asset base through construction of new facilities that will generate additional revenue streams and cash flows.
(3)
Sustaining capital expenditures are capital expenditures (as defined by GAAP) resulting from improvements to existing assets.  Such expenditures serve to maintain existing operations but do not generate additional revenues or result in significant cost savings.

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Comparison of Six Months Ended June 30, 2020 with Six Months Ended June 30, 2019

In total, investments in growth capital projects decreased $286.4 million period-to-period primarily due to the following:

•
completion of projects at our Mont Belvieu complex, which accounted for a $262.9 million decrease.  We placed our iBDH facility and Frac X into service in December 2019 and March 2020, respectively;

•
completion of the Shin Oak NGL Pipeline (which was completed in stages extending through the fourth quarter of 2019), which accounted for a $253.3 million decrease;

•
lower investments in natural gas processing facilities and related infrastructure that support Permian Basin production, which accounted for an additional $223.6 million decrease. We completed the final phase of our Orla plant in July 2019 and placed our Mentone plant into service in December 2019;

•
lower investments in projects attributable to our ethylene business, which accounted for an $83.8 million decrease; partially offset by,

•
higher investments in propylene production, NGL fractionation and related plant assets and infrastructure at our Mont Belvieu complex, which accounted for a combined $251.3 million increase;

•
higher investments in crude oil pipelines, including those comprising our Midland-to-ECHO System, and related infrastructure that support Permian Basin production, which accounted for an overall $188.9 million increase; and

•
higher investments in natural gas pipelines and related infrastructure in support of East Texas and Louisiana production, which accounted for a $71.4 million increase.

Investments in unconsolidated affiliates decreased $52.6 million period-to-period primarily due to lower spending on joint venture dock infrastructure at Corpus Christi and other crude oil-related projects, which accounted for a $27.3 million decrease, and NGL pipeline expansion projects, which accounted for an additional $25.8 million decrease.

Fluctuations in investments for sustaining capital projects are primarily due to 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 Form 10-K.  The following types of estimates, in our opinion, are subjective in nature, require the exercise of professional judgment and involve complex analysis:

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

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

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

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

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

When used to prepare our Unaudited Condensed Consolidated Financial Statements, the foregoing types of estimates are based on our current knowledge and understanding of the underlying facts and circumstances.  Such estimates may be revised as a result of changes in the underlying facts and circumstances.  Subsequent changes in these estimates may have a significant impact on our consolidated financial position, results of operations and cash flows.
77


Other Items

Contractual Obligations

We have contractual future product purchase commitments for natural gas, NGLs, crude oil, petrochemicals and refined products.  These commitments represent enforceable and legally binding agreements as of the reporting date.  Our product purchase commitments at June 30, 2020 declined by an estimated $ 8.63 billion when compared to those reported in our 2019 Form 10-K primarily due to lower NGL and crude oil prices since December 31, 2019.

The principal amount of our consolidated debt obligations were $29.9 billion at June 30, 2020 compared to $27.88 billion at December 31, 2019.  See “ Other Recent Developments ” within this Item 2 for information regarding EPO’s senior notes offering in January 2020 and the related use of proceeds.

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


ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK.

General

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

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

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

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

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

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

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

78


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.

The following table summarizes our portfolio of commodity derivative instruments outstanding at June 30, 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 (billion cubic feet (“Bcf”))
12.7
n/a
Cash flow hedge
Forecasted sales of NGLs (MMBbls)
0.1
n/a
Cash flow hedge
Octane enhancement:
Forecasted purchase of NGLs (MMBbls)
0.6
n/a
Cash flow hedge
Forecasted sales of octane enhancement products (MMBbls)
8.9
n/a
Cash flow hedge
Natural gas marketing:
Forecasted purchase of natural gas (Bcf)
1.8
n/a
Cash flow hedge
Natural gas storage inventory management activities (Bcf)
5.9
n/a
Fair value hedge
NGL marketing:
Forecasted purchases of NGLs and related hydrocarbon products (MMBbls)
157.9
4.6
Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products (MMBbls)
162.4
15.6
Cash flow hedge
NGLs inventory management activities (MMBbls)
1.8
n/a
Fair value hedge
Refined products marketing:
Forecasted purchases of refined products (MMBbls)
46.8
15.4
Cash flow hedge
Forecasted sales of refined products (MMBbls)
52.5
18.7
Cash flow hedge
Refined products inventory management activities (MMBbls)
3.9
n/a
Fair value hedge
Crude oil marketing:
Forecasted purchases of crude oil (MMBbls)
78.2
n/a
Cash flow hedge
Forecasted sales of crude oil (MMBbls)
88.7
n/a
Cash flow hedge
Petrochemical marketing:
Forecasted sales of petrochemical products (MMBbls)
1.2
n/a
Cash flow hedge
Commercial energy:
Forecasted purchases of power related to asset operations (terawatt hours (“TWh”))
0.3
n/a
Cash flow hedge
Derivatives not designated as hedging instruments:
Natural gas risk management activities (Bcf) (3,4)
44.2
2.1
Mark-to-market
NGL risk management activities (MMBbls) (4)
21.4
8.4
Mark-to-market
Refined products risk management activities (MMBbls) (4)
4.0
n/a
Mark-to-market
Crude oil risk management activities (MMBbls) (4)
28.8
7.7
Mark-to-market
Commercial energy risk management activities (TWh) (4)
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, March 2021 and December 2022, respectively.
(3)
Current volumes include approximately 0.7 Bcf of physical derivatives instruments that are predominantly priced as index plus a premium or minus a discount.
(4)
Reflects the use of derivative instruments to manage risks associated with our transportation, processing, storage assets and end use power requirements.

At June 30, 2020, 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.

79


Sensitivity Analysis

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

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

Natural gas marketing portfolio
Portfolio Fair Value at
Scenario
Resulting
Classification
December 31,
2019
June 30,
2020
July 15,
2020
Fair value assuming no change in underlying commodity prices
Asset (Liability)
$
1.1
$
22.0
$
23.0
Fair value assuming 10% increase in underlying commodity prices
Asset (Liability)
(4.3
)
19.6
20.7
Fair value assuming 10% decrease in underlying commodity prices
Asset (Liability)
6.6
24.4
25.2

NGL and refined products marketing, natural gas processing and octane enhancement portfolio
Portfolio Fair Value at
Scenario
Resulting
Classification
December 31,
2019
June 30,
2020
July 15,
2020
Fair value assuming no change in underlying commodity prices
Asset (Liability)
$
43.7
$
(138.3
)
$
(166.6
)
Fair value assuming 10% increase in underlying commodity prices
Asset (Liability)
(19.0
)
(237.3
)
(260.4
)
Fair value assuming 10% decrease in underlying commodity prices
Asset (Liability)
106.4
(39.3
)
(72.8
)

Crude oil marketing portfolio
Portfolio Fair Value at
Scenario
Resulting
Classification
December 31,
2019
June 30,
2020
July 15,
2020
Fair value assuming no change in underlying commodity prices
Asset (Liability)
$
(9.6
)
$
(77.7
)
$
(109.8
)
Fair value assuming 10% increase in underlying commodity prices
Asset (Liability)
(50.6
)
(136.0
)
(176.6
)
Fair value assuming 10% decrease in underlying commodity prices
Asset (Liability)
31.5
(19.4
)
(43.0
)

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.

Sensitivity Analysis

At June 30, 2020, 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.



80


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 our portfolio of forward-starting swaps at June 30, 2020 (dollars 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 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
June 30,
2020
July 15,
2020
Fair value assuming no change in underlying interest rates
Asset (Liability)
$
(13.5
)
$
(250.5
)
$
(267.6
)
Fair value assuming 10% increase in underlying interest rates
Asset (Liability)
38.2
(221.4
)
(239.7
)
Fair value assuming 10% decrease in underlying interest rates
Asset (Liability)
(68.3
)
(280.5
)
(296.3
)

The $ 254.1 million decrease in the fair value of this portfolio from December 31, 2019 to July 15, 2020 was primarily due to declining interest rates relative to the fixed rates specified in the swap agreements.  Upon settlement, we would expect that any loss on these swaps would be offset by lower interest rates on future debt issuances.


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 second quarter of 2020, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.


81


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 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.














82


ITEM 1A.  RISK FACTORS.

An investment in our securities involves certain risks. Security holders and potential investors in our securities should carefully consider the risks described under “Risk Factors” set forth in Part I, Item 1A of our 2019 Form 10-K, in addition to other information in such annual report and this quarterly report (including the additional risk factor set forth below).  The risk factors set forth in our 2019 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 emergence of COVID-19 as a global pandemic in the first quarter of 2020 and the consequences of international COVID-19 containment measures (and the resulting near-term decline in end-user demand for hydrocarbons) have adversely impacted the global economy in general and the energy industry in particular. In addition, disputes between members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (collectively, the “OPEC+” group) in March and April 2020 over crude oil production levels, resulted in major disruptions to global energy markets. Although the OPEC+ group and other producers subsequently reached agreements to reduce the oversupply of crude oil in the near-term caused by demand destruction attributable to COVID-19, the downturn in the energy industry has negatively impacted us, the producers we work with and our other customers to varying degrees.

The COVID-19 public health emergency resulted in record, near-term decreases in hydrocarbon demand due to lockdowns, travel restrictions, quarantines, temporary business closures and other measures instituted as early as February 2020 as the virus spread across several continents.  By May 2020, several major economies across the world began to work towards reopening their economies by targeting a balance between containing and eradicating the virus and supporting their economies, versus the initial more complete shut-downs.  The U.S., China, India, much of Europe and parts of Latin America have begun to ease their COVID-19 containment measures and central banks and governments have instituted significant measures in an effort to stimulate economic activity.  As a result, crude oil demand has begun to recover in certain regions. A continuation of this trend remains dependent on successful containment of the disease and its elimination as a widespread threat to public health through vaccines or otherwise.  While we are encouraged by efforts to reopen the global economy, the pace and the scope of the reopening is uncertain at this time and may extend well into 2021.

Responses to the pandemic have affected business operations across the world and led to diminished near-term business and consumer confidence and increasing unemployment. 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.  As noted in this quarterly report, we experienced a reduction in volumes on a number of our assets during the second quarter of 2020 due to reduced upstream drilling activity and lower downstream refinery activity and demand for transportation fuels, and we may continue to 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 other facilities until the pandemic ends and economic activity is fully restored.

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.


83


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

Issuer Purchases of Equity Securities

The following table summarizes our equity repurchase activity during the second quarter of 2020:

Period
Total Number
of Units
Purchased
Average
Price Paid
per Unit
Total
Number
Of Units
Purchased
as Part of
2019 Buyback
Program
Remaining
Dollar Amount
of Units
That May
Be Purchased
Under the 2019 Buyback
Program
($ thousands)
2019 Buyback Program: (1)
April 2020
–
$
–
$
1,778,911
May 2020
–
$
–
$
1,778,911
June 2020
–
$
–
$
1,778,911
Vesting of phantom unit awards:
April 2020
–
$
–
n/a
n/a
May 2020 (2)
30,233
$
17.12
n/a
n/a
June 2020 (3)
2,555
$
19.12
n/a
n/a

(1)
In January 2019, we announced the 2019 Buyback Program, which authorized the repurchase of up to $2 billion of EPD’s common units.  Units repurchased under this program during 2020 were cancelled immediately upon acquisition.
(2)
Of the 117,023 phantom unit awards that vested in May 2020 and converted to common units, 30,233 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 11,955 phantom unit awards that vested in June 2020 and converted to common units, 2,555 units were sold back to us by employees to cover related withholding tax requirements. These repurchases are not part of any announced program.  We cancelled these units immediately upon acquisition.


ITEM 3.  DEFAULTS UPON SENIOR SECURITIES.

None.


ITEM 4.  MINE SAFETY DISCLOSURES.

Not applicable.


ITEM 5.  OTHER INFORMATION.


None.
84


ITEM 6.  EXHIBITS.


Exhibit Number
Exhibit*
2.1
2.2
2.3
2.4
2.5
2.6
2.7
2.8
2.9
2.10
2.11
2.12

85


2.13
2.14
3.1
3.2
3.3
3.4
3.5
3.6
3.7
3.8
3.9
3.10
3.11
3.12
3.13
3.14
3.15
3.16

86


4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
4.10
4.11
4.12
4.13
4.14

87


4.15
4.16
4.17
4.18
4.19
4.20
4.21
4.22
4.23
4.24
4.25
4.26
4.27

88


4.28
4.29
4.30
4.31
4.32
4.33
4.34
4.35
4.36
4.37
4.38
4.39
4.40
4.41
4.42
4.43

89


4.44
4.45
4.46
4.47
4.48
4.49
4.50
4.51
4.52
4.53
4.54
4.55
4.56
4.57
4.58
4.59
4.60

90


4.61
4.62
4.63
4.64
4.65
4.66
4.67
4.68
4.69
4.70
4.71
4.72
4.73
4.74
4.75
4.76

91


4.77
4.78
4.79
4.80
4.81
4.82
4.83
4.84
4.85
4.86
4.87

92


4.88
10.1
10.2
31.1#
31.2#
32.1#
32.2#
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: (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 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.

93



SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on August 10, 2020.

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
















94

TABLE OF CONTENTS
Part I. Financial InformationItem 1. Financial StatementsNote 1. Partnership Organization and Basis Of PresentationNote 2. Summary Of Significant Accounting PoliciesNote 3. InventoriesNote 4. Property, Plant and EquipmentNote 5. Investments in Unconsolidated AffiliatesNote 6. Intangible Assets and GoodwillNote 7. Debt ObligationsNote 8. Equity and DistributionsNote 9. RevenuesNote 10. Business Segments and Related InformationNote 11. Income TaxesNote 12. Earnings Per UnitNote 13. Equity-based AwardsNote 14. Derivative Instruments, Hedging Activities and Fair Value MeasurementsNote 15. Related Party TransactionsNote 16. Commitments and ContingenciesNote 17. Supplemental Cash Flow InformationNote 18. Condensed Consolidating Financial InformationNote 19. Subsequent EventsItem 2. Management S Discussion and Analysis Of Financial Condition andItem 3. Quantitative and Qualitative DisclosuresItem 4. Controls and ProceduresPart II. Other InformationItem 1. Legal ProceedingsItem 1A. Risk FactorsItem 2. Unregistered Sales Of Equity Securities and Use Of ProceedsItem 3. Defaults Upon Senior SecuritiesItem 4. Mine Safety DisclosuresItem 5. Other InformationItem 6. Exhibits

Exhibits

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). 2.4 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). 2.6 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 September3, 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 September3, 2010, by and among Enterprise Products GP, LLC, Enterprise GP Holdings L.P. and EPE Holdings, LLC (incorporated by reference to Exhibit 2.2 to Form 8-K filed September 7, 2010). 2.10 Contribution Agreement, dated as of September 30, 2010, by and between Enterprise Products Company and Enterprise Products Partners L.P. (incorporated by reference to Exhibit 2.1 to Form 8-K filed October 1, 2010). 2.11 Agreement and Plan of Merger, dated as of April 28, 2011, by and among Enterprise Products Partners L.P., Enterprise Products Holdings LLC, EPD MergerCo LLC, Duncan Energy Partners L.P. and DEP Holdings, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed April 29, 2011). 2.12 Contribution and Purchase Agreement, dated as of October 1, 2014, by and among Enterprise Products Partners L.P., Oiltanking Holding Americas, Inc. and OTB Holdco, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed October 1, 2014). 2.13 Agreement and Plan of Merger, dated as of November 11, 2014, by and among Enterprise Products Partners L.P., Enterprise Products Holdings LLC, EPOT MergerCo LLC, Oiltanking Partners, L.P. and OTLP GP, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed November 12, 2014). 2.14 Amendment No. 1 dated as of June 6, 2018 to Contribution and Purchase Agreement, by and among Enterprise Products Partners L.P., Oiltanking Holding Americas, Inc., Enterprise Products Holdings LLC and Marquard & Bahls, AG (incorporated by reference to Exhibit 2.2 to Form 8-K filed June 12, 2018). 3.1 Certificate of Limited Partnership of Enterprise Products Partners L.P. (incorporated by reference to Exhibit 3.6 to Form 10-Q filed November 9, 2007). 3.2 Certificate of Amendment to Certificate of Limited Partnership of Enterprise Products Partners L.P., filed on November 22, 2010 with the Delaware Secretary of State (incorporated by reference to Exhibit 3.6 to Form 8-K filed November 23, 2010). 3.3 Sixth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated November 22, 2010 (incorporated by reference to Exhibit 3.2 to Form 8-K filed November 23, 2010). 3.4 Amendment No. 1 to Sixth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated effective as of August 11, 2011 (incorporated by reference to Exhibit 3.1 to Form 8-K filed August 16, 2011). 3.5 Amendment No. 2 to Sixth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated effective as of August 21, 2014 (incorporated by reference to Exhibit 3.1 to Form 8-K filed August 26, 2014). 3.6 Amendment No.3 to the Sixth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated as of November28, 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, 2020 (incorporated by reference to Exhibit 3.1 to Form 8-K filed March 5, 2020). 3.9 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 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 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 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 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 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 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 Bylaws of Enterprise Products OLPGP, Inc., dated December 8, 2003 (incorporated by reference to Exhibit 3.6 to Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004). 4.1 Form of Common Unit certificate (incorporated by reference to Exhibit A to Exhibit 3.1 to Form 8-K filed August 16, 2011). 4.2 Description of the Registrants 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). 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 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 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 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 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 Twenty-First Supplemental Indenture, dated as of August 24, 2011, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed August 24, 2011). 4.17 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 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 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 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 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 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 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 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 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 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 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 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 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). 4.30 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). 4.32 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). 4.33 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). 4.34 Form of Global Note representing $700.0 million principal amount of 6.50% Senior Notes due 2019 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit4.4 to Form8-K filed April 3, 2008). 4.35 Form of Global Note representing $500.0 million principal amount of 5.25% Senior Notes due 2020 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed October 5, 2009). 4.36 Form of Global Note representing $600.0 million principal amount of 6.125% Senior Notes due 2039 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed October 5, 2009). 4.37 Form of Global Note representing $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). 4.38 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). 4.39 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). 4.40 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). 4.41 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). 4.42 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). 4.43 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). 4.44 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). 4.45 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). 4.46 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). 4.47 Form of Global Note representing $1.0 billion principal amount of 4.85% Senior Notes due 2044 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed March 18, 2013). 4.48 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). 4.49 Form of Global Note representing $1.15 billion principal amount of 5.10% Senior Notes due 2045 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed February 12, 2014). 4.50 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). 4.51 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). 4.52 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). 4.53 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). 4.54 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). 4.55 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). 4.56 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). 4.57 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). 4.58 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). 4.59 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). 4.60 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). 4.61 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). 4.62 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). 4.63 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). 4.64 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). 4.65 Form of Global Note representing $1,000.0 million principal amount of 4.15% Senior Notes due 2028 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed October 11, 2018). 4.66 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). 4.67 Form of Global Note representing $1,250.0 million principal amount of 3.125% Senior Notes due 2029 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed July 8, 2019). 4.68 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). 4.69 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). 4.70 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). 4.71 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). 4.72 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). 4.73 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). 4.74 Replacement Capital Covenant, dated October 27, 2009, executed by Enterprise Products Operating LLC and Enterprise Products Partners L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 4.9 to Form 8-K filed October 28, 2009). 4.75 Amendment to Replacement Capital Covenants, dated May 6, 2015, executed by Enterprise Products Operating LLC and Enterprise Products Partners L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit4.59 to Form10-Q filed May8, 2015). 4.77 Supplemental Indenture, dated June 27, 2002, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as Initial Subsidiary Guarantors, Val Verde Gas Gathering Company, L.P., as New Subsidiary Guarantor, and Wachovia Bank, National Association, formerly known as First Union National Bank, as Trustee (incorporated by reference to Exhibit 4.6 to the Form 10-Q filed by TEPPCO Partners, L.P. on August 14, 2002). 4.78 Full Release of Guarantee, dated July 31, 2006, by Wachovia Bank, National Association, as Trustee, in favor of Jonah Gas Gathering Company (incorporated by reference to Exhibit 4.8 to the Form 10-Q filed by TEPPCO Partners, L.P. on November 7, 2006). 4.79 Seventh Supplemental Indenture, dated March 27, 2008, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.13 to the Form 10-Q filed by TEPPCO Partners, L.P. on May 8, 2008). 4.80 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). 4.81 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). 4.82 Indenture, dated May14, 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). 4.83 First Supplemental Indenture, dated May18, 2007, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and The Bank of New York Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.2 to the Form 8-K filed by TEPPCO Partners, L.P. on May 18, 2007). 4.84 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). 4.85 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). 4.86 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). 4.87 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). 4.88 Equity Distribution Agreement, dated June 24, 2020, by and among Enterprise Products Partners L.P., Enterprise Products OLPGP, Inc., Enterprise Products Operating LLC, Skyline North Americas, Inc. and Morgan Stanley & Co. LLC. (incorporated by reference to Exhibit 1.1 to Form 8-K filed June 25, 2020). 10.1 April 2020 364-Day Revolving Credit Agreement, dated as of April 3, 2020 among Enterprise Products Operating LLC, the Lenders party thereto, and Citibank, N.A. as Administrative Agent (incorporated by reference to Exhibit 10.1 to Form 8-K filed April 6, 2020). 10.2 Guaranty Agreement, dated as of April 3, 2020, 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). 31.1# Sarbanes-Oxley Section 302 certification of A. James Teague for Enterprise Products Partners L.P.s quarterly report on Form 10-Q for the six months ended June 30, 2020. 31.2# Sarbanes-Oxley Section 302 certification of W. Randall Fowler for Enterprise Products Partners L.P.s quarterly report on Form 10-Q for the six months ended June 30, 2020. 32.1# Sarbanes-Oxley Section 906 certification of A. James Teague for Enterprise Products Partners L.P.s quarterly report on Form 10-Q for the six months ended June 30, 2020. 32.2# Sarbanes-Oxley Section 906 certification of W. Randall Fowler for Enterprise Products Partners L.P.s quarterly report on Form 10-Q for the six months ended June 30, 2020.