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 September 30, 2019March 31, 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:  001-143231-14323

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 ClassTrading Symbol(s)Name of Each Exchange On Which Registered
Common UnitsEPDNew York Stock Exchange

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

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

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

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

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

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

There were 2,189,169,5282,185,800,243 common units of Enterprise Products Partners L.P. outstanding at the close of business on October 31, 2019.April 30, 2020. 

Table of Contents

ENTERPRISE PRODUCTS PARTNERS L.P.
TABLE OF CONTENTS

  Page No.
PART I.  FINANCIAL INFORMATION.
Item 1.
Financial Statements.
 
 
Unaudited Condensed Consolidated Balance Sheets
2
 
Unaudited Condensed Statements of Consolidated Operations
3
 
Unaudited Condensed Statements of Consolidated Comprehensive Income
4
 
Unaudited Condensed Statements of Consolidated Cash Flows
5
 
Unaudited Condensed Statements of Consolidated Equity
6
 
Notes to Unaudited Condensed Consolidated Financial Statements:
 
 
1.  Partnership Organization and Basis of Presentation
87
 
2.  Summary of Significant Accounting Policies
98
 
3.  Inventories
109
 
4.  Property, Plant and Equipment
1110
 
5.  Investments in Unconsolidated Affiliates
1211
 
6.  Intangible Assets and Goodwill
1312
 
7.  Debt Obligations
1413
 
8.  Equity and Distributions
1715
 
9.  Revenues
2018
 
10.  Business Segments and Related Information
2201
 
11.  Income Taxes
23
12.  Earnings Per Unit
25
12.  Equity-Based Awards
25
 
13.  Equity-Based Awards
26
14.  Derivative Instruments, Hedging Activities and Fair Value Measurements
27
 
14.15.  Related Party Transactions
33
16.  Commitments and Contingencies
34
 
15.  Commitments and Contingencies
35
16.17.  Supplemental Cash Flow Information
3937
 
17.18.  Condensed Consolidating Financial Information
4380
19.  Subsequent Events
43
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations.
4744
Item 3.
Quantitative and Qualitative Disclosures About Market Risk.
7717
Item 4.
Controls and Procedures.
8175
   
PART II.  OTHER INFORMATION.
Item 1.
Legal Proceedings.
8175
Item 1A.
Risk Factors.
8276
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds.
8277
Item 3.
Defaults Upon Senior Securities.
8277
Item 4.
Mine Safety Disclosures.
8277
Item 5.
Other Information.
8277
Item 6.
Exhibits.
8378
   
Signatures
9286

1

Table of Contents

PART I.  FINANCIAL INFORMATION.

ITEM 1.  FINANCIAL STATEMENTS.

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

 
September 30,
2019
  
December 31,
2018
  
March 31,
2020
  
December 31,
2019
 
ASSETS            
Current assets:            
Cash and cash equivalents $1,207.8  $344.8  $2,025.7  $334.7 
Restricted cash  –   65.3   89.9   75.3 
Accounts receivable – trade, net of allowance for doubtful accounts
of $11.3 at September 30, 2019 and $11.5 at December 31, 2018
  4,261.7   3,659.1 
Accounts receivable – trade, net of allowance for doubtful accounts
of $16.7 at March 31, 2020 and $12.4 at December 31, 2019
  3,293.8   4,873.6 
Accounts receivable – related parties  2.0   3.5   1.9   2.5 
Inventories  1,644.7   1,522.1   1,538.8   2,091.4 
Derivative assets  166.0   154.4   365.8   127.2 
Prepaid and other current assets  631.6   311.5   403.2   358.2 
Total current assets  7,913.8   6,060.7   7,719.1   7,862.9 
Property, plant and equipment, net  40,763.3   38,737.6   42,159.1   41,603.4 
Investments in unconsolidated affiliates  2,660.9   2,615.1   2,608.5   2,600.2 
Intangible assets, net of accumulated amortization of $1,647.1 at
September 30, 2019 and $1,735.1 at December 31, 2018 (see Note 6)
  3,489.4   3,608.4 
Intangible assets, net of accumulated amortization of $1,727.1 at
March 31, 2020 and $1,687.5 at December 31, 2019 (see Note 6)
  3,409.4   3,449.0 
Goodwill (see Note 6)
  5,745.2   5,745.2   5,745.2   5,745.2 
Other assets  442.7   202.8   624.0   472.5 
Total assets $61,015.3  $56,969.8  $62,265.3  $61,733.2 
                
LIABILITIES AND EQUITY                
Current liabilities:                
Current maturities of debt (see Note 7) $2,300.0  $1,500.1  $1,750.0  $1,981.9 
Accounts payable – trade  1,057.8   1,102.8   915.8   1,004.5 
Accounts payable – related parties  125.5   140.2   69.4   162.3 
Accrued product payables  4,198.8   3,475.8   3,166.3   4,915.7 
Accrued interest  237.2   395.6   238.3   431.7 
Derivative liabilities  202.4   148.2   269.2   122.4 
Other current liabilities  547.8   404.8   506.4   511.2 
Total current liabilities  8,669.5   7,167.5   6,915.4   9,129.7 
Long-term debt (see Note 7)
  25,639.2   24,678.1   27,855.9   25,643.2 
Deferred tax liabilities  91.4   80.4 
Deferred tax liabilities (see Note 11)
  428.2   100.4 
Other long-term liabilities  1,089.7   751.6   951.6   1,032.4 
Commitments and contingencies (see Note 15)
        
Commitments and contingencies (see Note 16)
      
Equity: (see Note 8)
                
Partners’ equity:                
Limited partners:                
Common units (2,189,169,528 units outstanding at September 30, 2019
and 2,184,869,029 units outstanding at December 31, 2018)
  24,535.1   23,802.6 
Accumulated other comprehensive income (loss)  (39.1)  50.9 
Common units (2,240,607,595 units issued and 2,185,800,243 units outstanding at
March 31, 2020, 2,189,226,130 units issued and outstanding at December 31, 2019)
  26,225.4   24,692.6 
Treasury units, at cost (54,807,352 units at March 31, 2020) (see Note 8)  (1,297.3)  – 
Accumulated other comprehensive income  122.3   71.4 
Total partners’ equity  24,496.0   23,853.5   25,050.4   24,764.0 
Noncontrolling interests  1,029.5   438.7   1,063.8   1,063.5 
Total equity  25,525.5   24,292.2   26,114.2   25,827.5 
Total liabilities and equity $61,015.3  $56,969.8  $62,265.3  $61,733.2 


See Notes to Unaudited Condensed Consolidated Financial Statements.
2

Table of Contents



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

 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended March 31,
 
 2019  2018  2019  2018  2020  2019 
Revenues:                  
Third parties $7,948.5  $9,571.7  $24,730.2  $27,257.4  $7,466.5  $8,531.2 
Related parties  15.6   14.2   53.7   94.5   16.0   12.3 
Total revenues (see Note 9)  7,964.1   9,585.9   24,783.9   27,351.9   7,482.5   8,543.5 
Costs and expenses:                        
Operating costs and expenses:                        
Third parties  6,217.6   7,643.4   19,342.4   22,722.0   5,735.3   6,655.3 
Related parties  356.1   358.5   1,051.9   1,054.6   325.0   364.4 
Total operating costs and expenses  6,573.7   8,001.9   20,394.3   23,776.6   6,060.3   7,019.7 
General and administrative costs:                        
Third parties  19.1   15.3   60.9   57.5   23.0   20.4 
Related parties  36.4   37.4   99.3   99.6   32.5   31.8 
Total general and administrative costs  55.5   52.7   160.2   157.1   55.5   52.2 
Total costs and expenses (see Note 10)  6,629.2   8,054.6   20,554.5   23,933.7   6,115.8   7,071.9 
Equity in income of unconsolidated affiliates  139.3   112.0   431.3   350.0   140.8   154.6 
Operating income  1,474.2   1,643.3   4,660.7   3,768.2   1,507.5   1,626.2 
Other income (expense):                        
Interest expense (see Note 13)  (382.9)  (279.5)  (950.2)  (806.2)
Change in fair market value of Liquidity Option
Agreement (see Note 15)
  (38.7)  (18.5)  (123.1)  (34.9)
Gain on step acquisition of unconsolidated affiliate (see Note 16)  –   –   –   39.4 
Interest expense  (317.5)  (277.2)
Change in fair market value of Liquidity Option  (2.3)  (57.8)
Interest income  7.2   1.3 
Other, net  7.6   0.3   11.7   1.3   0.9   0.2 
Total other expense, net  (414.0)  (297.7)  (1,061.6)  (800.4)  (311.7)  (333.5)
Income before income taxes  1,060.2   1,345.6   3,599.1   2,967.8   1,195.8   1,292.7 
Provision for income taxes  (15.4)  (11.0)  (37.4)  (34.5)
Benefit from (provision for) income taxes (see Note 11)  179.2   (12.3)
Net income  1,044.8   1,334.6   3,561.7   2,933.3   1,375.0   1,280.4 
Net income attributable to noncontrolling interests (see Note 8)  (25.6)  (21.4)  (67.3)  (45.6)
Net income attributable to noncontrolling interests  (24.9)  (19.9)
Net income attributable to limited partners $1,019.2  $1,313.2  $3,494.4  $2,887.7  $1,350.1  $1,260.5 
                        
Earnings per unit: (see Note 11)
                
Basic and diluted earnings per unit $0.46  $0.60  $1.59  $1.32 
Earnings per unit: (see Note 12)
        
Basic earnings per unit $0.61  $0.57 
Diluted earnings per unit $0.61  $0.57 















See Notes to Unaudited Condensed Consolidated Financial Statements.
3

Table of Contents


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

  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2019  2018  2019  2018 
             
Net income $1,044.8  $1,334.6  $3,561.7  $2,933.3 
Other comprehensive income (loss):                
Cash flow hedges: (see Note 13)                
Commodity hedging derivative instruments:                
Changes in fair value of cash flow hedges  72.3   (145.8)  58.6   (156.0)
Reclassification of gains to net income
  (91.5)  (53.5)  (152.0)  (28.8)
Interest rate hedging derivative instruments:                
Changes in fair value of cash flow hedges  (18.6)  6.1   (23.8)  20.7 
Reclassification of losses to net income
  9.4   9.1   27.8   29.0 
Total cash flow hedges  (28.4)  (184.1)  (89.4)  (135.1)
Other  –   –   (0.6)  (0.5)
Total other comprehensive loss
  (28.4)  (184.1)  (90.0)  (135.6)
Comprehensive income  1,016.4   1,150.5   3,471.7   2,797.7 
Comprehensive income attributable to noncontrolling interests  (25.6)  (21.4)  (67.3)  (45.6)
Comprehensive income attributable to limited partners $990.8  $1,129.1  $3,404.4  $2,752.1 
  
For the Three Months
Ended March 31,
 
  2020  2019 
       
Net income $1,375.0  $1,280.4 
Other comprehensive income (loss):        
Cash flow hedges: (see Note 14)        
Commodity hedging derivative instruments:        
Changes in fair value of cash flow hedges  475.1   (95.2)
Reclassification of gains to net income
  (155.6)  (58.3)
Interest rate hedging derivative instruments:        
Changes in fair value of cash flow hedges  (292.0)  – 
Reclassification of losses to net income
  23.5   9.2 
Total cash flow hedges  51.0   (144.3)
Other  (0.1)  (0.6)
Total other comprehensive income (loss)
  50.9   (144.9)
Comprehensive income  1,425.9   1,135.5 
Comprehensive income attributable to noncontrolling interests  (24.9)  (19.9)
Comprehensive income attributable to limited partners $1,401.0  $1,115.6 





























See Notes to Unaudited Condensed Consolidated Financial Statements.
4

Table of Contents


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

  
For the Nine Months
Ended September 30,
 
  2019  2018 
Operating activities:      
Net income $3,561.7  $2,933.3 
Reconciliation of net income to net cash flows provided by operating activities:        
Depreciation, amortization and accretion  1,456.7   1,330.8 
Asset impairment and related charges  51.3   21.4 
Equity in income of unconsolidated affiliates  (431.3)  (350.0)
Distributions received on earnings from unconsolidated affiliates  431.2   345.7 
Net gains attributable to asset sales  (2.6)  (8.1)
Deferred income tax expense  10.9   9.3 
Change in fair market value of derivative instruments  2.0   254.9 
Change in fair market value of Liquidity Option Agreement  123.1   34.9 
Gain on step acquisition of unconsolidated affiliate (see Note 16)  –   (39.4)
Net effect of changes in operating accounts (see Note 16)  (409.0)  (261.9)
Other operating activities  32.2   4.4 
Net cash flows provided by operating activities  4,826.2   4,275.3 
Investing activities:        
Capital expenditures  (3,302.1)  (3,004.2)
Cash used for business combination (see Note 16)  –   (150.6)
Investments in unconsolidated affiliates  (100.1)  (95.1)
Distributions received for return of capital from unconsolidated affiliates  53.9   47.0 
Proceeds from asset sales  16.8   24.1 
Other investing activities  (41.3)  (4.0)
Cash used in investing activities  (3,372.8)  (3,182.8)
Financing activities:        
Borrowings under debt agreements  44,629.6   67,086.3 
Repayments of debt  (42,855.3)  (65,742.1)
Debt issuance costs  (26.3)  (25.2)
Cash distributions paid to limited partners (see Note 8)  (2,871.1)  (2,782.9)
Cash payments made in connection with distribution equivalent rights  (16.4)  (13.2)
Cash distributions paid to noncontrolling interests  (69.7)  (50.9)
Cash contributions from noncontrolling interests  590.8   222.0 
Net cash proceeds from the issuance of common units  82.2   449.4 
Repurchase of common units under 2019 Buyback Program (see Note 8)  (81.1)  – 
Other financing activities  (38.4)  (27.1)
Cash used in financing activities
  (655.7)  (883.7)
Net change in cash and cash equivalents, including restricted cash  797.7   208.8 
Cash and cash equivalents, including restricted cash, at beginning of period  410.1   70.3 
Cash and cash equivalents, including restricted cash, at end of period $1,207.8  $279.1 


  
For the Three Months
Ended March 31,
 
  2020  2019 
Operating activities:      
Net income $1,375.0  $1,280.4 
Reconciliation of net income to net cash flows provided by operating activities:        
Depreciation, amortization and accretion  509.0   474.5 
Asset impairment and related charges  1.6   4.8 
Equity in income of unconsolidated affiliates  (140.8)  (154.6)
Distributions received from unconsolidated affiliates attributable to earnings
  126.9   139.0 
Net losses (gains) attributable to asset sales  0.1   (0.4)
Deferred income tax expense (benefit)  (184.1)  1.8 
Change in fair market value of derivative instruments  (29.5)  (96.3)
Change in fair market value of Liquidity Option  2.3   57.8 
Non-cash expense related to long-term operating leases (see Note 16)  10.0   11.0 
Net effect of changes in operating accounts (see Note 17)  341.7   (559.8)
Other operating activities  –   2.2 
Net cash flows provided by operating activities  2,012.2   1,160.4 
Investing activities:        
Capital expenditures  (1,079.5)  (1,148.9)
Investments in unconsolidated affiliates  (3.3)  (29.1)
Distributions received from unconsolidated affiliates attributable to the return of capital
  10.3   4.5 
Proceeds from asset sales  0.6   1.7 
Other investing activities  0.2   (2.7)
Cash used in investing activities  (1,071.7)  (1,174.5)
Financing activities:        
Borrowings under debt agreements  5,411.8   15,692.4 
Repayments of debt  (3,406.6)  (14,999.2)
Debt issuance costs  (28.4)  – 
Monetization of interest rate derivative instruments  (33.3)  – 
Cash distributions paid to limited partners (see Note 8)  (974.2)  (950.4)
Cash payments made in connection with distribution equivalent rights  (5.8)  (4.5)
Cash distributions paid to noncontrolling interests  (29.9)  (18.0)
Cash contributions from noncontrolling interests  5.2   34.8 
Net cash proceeds from the issuance of common units  –   42.7 
Repurchase of common units under 2019 Buyback Program (see Note 8)  (140.1)  (51.6)
Other financing activities  (33.6)  (34.7)
Cash provided by (used in) financing activities
  765.1   (288.5)
Net change in cash and cash equivalents, including restricted cash  1,705.6   (302.6)
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 $2,115.6  $107.5 








See Notes to Unaudited Condensed Consolidated Financial Statements.
5

Table of Contents



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

  Partners’ Equity       
For the Three Months Ended September 30, 2019: 
Limited
Partners
  
Accumulated
Other
Comprehensive
Income (Loss)
  
Noncontrolling
Interests
  Total 
    Balance, June 30, 2019 $24,450.5  $(10.7) $535.6  $24,975.4 
   Net income  1,019.2   –   25.6   1,044.8 
   Cash distributions paid to limited partners  (963.2)  –   –   (963.2)
   Cash payments made in connection with distribution equivalent rights  (5.9)  –   –   (5.9)
   Cash distributions paid to noncontrolling interests  –   –   (22.8)  (22.8)
   Cash contributions from noncontrolling interests  –   –   491.2   491.2 
   Net cash proceeds from the issuance of common units  –   –   –   – 
   Repurchase of common units under 2019 Buyback Program (see Note 8)  –   –   –   – 
   Amortization of fair value of equity-based awards  36.7   –   –   36.7 
   Cash flow hedges  –   (28.4)  –   (28.4)
   Other  (2.2)  –   (0.1)  (2.3)
    Balance, September 30, 2019 $24,535.1  $(39.1) $1,029.5  $25,525.5 
  Partners’ Equity       
  
Limited
Partners
  
Treasury
Units
  
Accumulated
Other
Comprehensive
Income (Loss)
  
Noncontrolling
Interests
  Total 
     Balance, December 31, 2019 $24,692.6  $–  $71.4  $1,063.5  $25,827.5 
   Net income  1,350.1   –   –   24.9   1,375.0 
   Cash distributions paid to limited partners  (974.2)  –   –   –   (974.2)
   Cash payments made in connection with
      distribution equivalent rights
  (5.8)  –   –   –   (5.8)
   Cash distributions paid to noncontrolling interests  –   –   –   (29.9)  (29.9)
   Cash contributions from noncontrolling interests  –   –   –   5.2   5.2 
   Amortization of fair value of equity-based awards  39.1   –   –   –   39.1 
   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  –   –   51.0   –   51.0 
   Other, net  (33.6)  –   (0.1)  0.1   (33.6)
     Balance, March 31, 2020 $26,225.4  $(1,297.3) $122.3  $1,063.8  $26,114.2 


  Partners’ Equity       
For the Nine Months Ended September 30, 2019: 
Limited
Partners
  
Accumulated
Other
Comprehensive
Income (Loss)
  
Noncontrolling
Interests
  Total 
     Balance, December 31, 2018 $23,802.6  $50.9  $438.7  $24,292.2 
   Net income  3,494.4   –   67.3   3,561.7 
   Cash distributions paid to limited partners  (2,871.1)  –   –   (2,871.1)
   Cash payments made in connection with distribution equivalent rights  (16.4)  –   –   (16.4)
   Cash distributions paid to noncontrolling interests  –   –   (69.7)  (69.7)
   Cash contributions from noncontrolling interests  –   –   590.8   590.8 
   Net cash proceeds from the issuance of common units  82.2   –   –   82.2 
   Common units issued in connection with employee compensation  45.6   –   –   45.6 
   Repurchase of common units under 2019 Buyback Program  (81.1)  –   –   (81.1)
   Amortization of fair value of equity-based awards  107.2   –   –   107.2 
   Cash flow hedges  –   (89.4)  –   (89.4)
   Other  (28.3)  (0.6)  2.4   (26.5)
     Balance, September 30, 2019 $24,535.1  $(39.1) $1,029.5  $25,525.5 







  Partners’ Equity       
  
Limited
Partners
  
Accumulated
Other
Comprehensive
Income (Loss)
  
Noncontrolling
Interests
  Total 
     Balance, December 31, 2018 $23,802.6  $50.9  $438.7  $24,292.2 
   Net income  1,260.5   –   19.9   1,280.4 
   Cash distributions paid to limited partners  (950.4)  –   –   (950.4)
   Cash payments made in connection with
      distribution equivalent rights
  (4.5)  –   –   (4.5)
   Cash distributions paid to noncontrolling interests  –   –   (18.0)  (18.0)
   Cash contributions from noncontrolling interests  –   –   34.8   34.8 
   Net cash proceeds from the issuance of common units  42.7   –   –   42.7 
   Common units issued in connection with
      employee compensation
  45.6   –   –   45.6 
   Amortization of fair value of equity-based awards  32.0   –   –   32.0 
   Repurchase and cancellation of common units under
      2019 Buyback Program
  (51.6)  –   –   (51.6)
   Cash flow hedges  –   (144.3)  –   (144.3)
   Other, net  (25.0)  (0.6)  (12.0)  (37.6)
    Balance, March 31, 2019 $24,151.9  $(94.0) $463.4  $24,521.3 









See Notes to Unaudited Condensed Consolidated Financial Statements.  For information regarding Unit History,
Accumulated Other Comprehensive Income (Loss) and Noncontrolling Interests,, see Note 8.
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ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2018
(Dollars in millions)

  Partners’ Equity       
For the Three Months Ended September 30, 2018: 
Limited
Partners
  
Accumulated
Other
Comprehensive
Income (Loss)
  
Noncontrolling
Interests
  Total 
     Balance, June 30, 2018 $22,794.8  $(123.2) $418.9  $23,090.5 
   Net income  1,313.2   –   21.4   1,334.6 
   Cash distributions paid to limited partners  (935.6)  –   –   (935.6)
   Cash payments made in connection with distribution equivalent rights  (4.6)  –   –   (4.6)
   Cash distributions paid to noncontrolling interests  –   –   (22.6)  (22.6)
   Cash contributions from noncontrolling interests  –   –   15.1   15.1 
   Net cash proceeds from the issuance of common units  188.4   –   –   188.4 
   Amortization of fair value of equity-based awards  24.9   –   –   24.9 
   Cash flow hedges  –   (184.1)  –   (184.1)
   Other  (0.7)  –   (0.1)  (0.8)
    Balance, September 30, 2018 $23,380.4  $(307.3) $432.7  $23,505.8 


  Partners’ Equity       
For the Nine Months Ended September 30, 2018: 
Limited
Partners
  
Accumulated
Other
Comprehensive
Income (Loss)
  
Noncontrolling
Interests
  Total 
     Balance, December 31, 2017 $22,718.9  $(171.7) $225.2  $22,772.4 
   Net income  2,887.7   –   45.6   2,933.3 
   Cash distributions paid to limited partners  (2,782.9)  –   –   (2,782.9)
   Cash payments made in connection with distribution equivalent rights  (13.2)  –   –   (13.2)
   Cash distributions paid to noncontrolling interests  –   –   (50.9)  (50.9)
   Cash contributions from noncontrolling interests  –   –   222.0   222.0 
   Net cash proceeds from the issuance of common units  449.4   –   –   449.4 
   Common units issued in connection with employee compensation  39.1   –   –   39.1 
   Common units issued in connection with land acquisition  30.0   –   –   30.0 
   Amortization of fair value of equity-based awards  77.5   –   –   77.5 
   Cash flow hedges  –   (135.1)  –   (135.1)
   Other  (26.1)  (0.5)  (9.2)  (35.8)
    Balance, September 30, 2018 $23,380.4  $(307.3) $432.7  $23,505.8 

















See Notes to Unaudited Condensed Consolidated Financial Statements. For information regarding Unit History,
Accumulated Other Comprehensive Income (Loss) and Noncontrolling Interests, see Note 8.
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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


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

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

Unless the context requires otherwise, references to “we,” “us,” “our” or “Enterprise” are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries.  References to “EPD” 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 PresidentCo-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 31.9%32.1% of EPD’s limited partner common units at September 30, 2019.

March 31, 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 1415 for information regarding related party matters.

Our results of operations for the ninethree months ended September 30, 2019March 31, 2020 are not necessarily indicative of results expected for the full year of 2019.2020.  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”).

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

These Unaudited Condensed Consolidated Financial Statements and Notes thereto should be read in conjunction with the Audited Consolidated Financial Statements and Notes thereto included in our annual report on Form 10-K for the year ended December 31, 20182019  (the “2018“2019 Form 10-K”) filed with the SEC on March 1, 2019.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 20182019 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.

 
September 30,
2019
  
December 31,
2018
  
March 31,
2020
  
December 31,
2019
 
Cash and cash equivalents $1,207.8  $344.8  $2,025.7  $334.7 
Restricted cash  –   65.3   89.9   75.3 
Total cash, cash equivalents and restricted cash shown in the
Unaudited Condensed Statements of Consolidated Cash Flows
 $1,207.8  $410.1  $2,115.6  $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 refined products.power.  Additional cash may be restricted to maintain our commodity derivative instruments portfolio as prices fluctuate or margin requirements change.  See Note 1314 for information regarding our derivative instruments and hedging activities.

Recent Accounting Developments

Lease accounting standardCredit Losses
In FebruaryJune 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards CodificationUpdate (“ASC”ASU”) 842,2016-13, LeasesFinancial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.  The new guidance, referred to as the current expected credit loss (“CECL”) 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 requires substantially all leasesamended 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 recorded ondecision-useful for users of the balance sheet. 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.

We adopted the new standardrequirements of this ASU on January 1, 2019 and2020.  The amendments that resulted in additional disclosures have been applied it to (i) all new leases entered into after January 1, 2019 and (ii) all existing lease contracts as of January 1, 2019. ASC 842 supersedes existing lease accounting guidance found under ASC 840, Leases.

The new standard introduces two lessee accounting models, which result in a lease being classified as either a “finance”prospectively for only the most recent interim or “operating” lease based on whether the lessee effectively obtains control of the underlying asset during the lease term.  A lease would be classified as a finance lease if it meets one of five classification criteria, four of which are generally consistent with ASC 840 lease accounting guidance.  By default, a lease that does not meet the criteria to be classified as a finance lease will be deemed an operating lease.  Regardless of classification, the initial measurement of both lease types will resultannual period presented in the balance sheet recognitionyear of a right-of-use (“ROU”) asset (representing a company’s right to use the underlying assetadoption.  All other amendments were applied retrospectively. See Note 14 for a specified period of time) and a corresponding lease liability.  The lease liability will be recognized at the presentinformation regarding our fair value of the future lease payments, and the ROU asset will equal the lease liability adjusted for any prepaid rent, lease incentives provided by the lessor, and any indirect costs.

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


ASC 842 resulted in changesGoodwill
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 way our operating leases are recorded, presented and disclosed in our consolidated financial statements. Upon adoptioncarrying amount of ASC 842goodwill.  We adopted this guidance on January 1, 2019, we recognized a ROU asset and a corresponding lease liability based on the present value of then existing long-term operating lease obligations. In addition, we elected to apply several practical expedients and made accounting policy elections upon adoption of ASC 842 including:2020 for future goodwill impairment testing.

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


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


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


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

See Note 15 for our disclosures regarding operating lease obligations.


Note 3.  Inventories

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

 
September 30,
2019
  
December 31,
2018
  
March 31,
2020
  
December 31,
2019
 
NGLs $928.2  $647.7  $893.9  $1,094.9 
Petrochemicals and refined products  183.2   264.7   199.8   311.5 
Crude oil  520.1   593.4   432.9   674.2 
Natural gas  13.2   16.3   12.2   10.8 
Total $1,644.7  $1,522.1  $1,538.8  $2,091.4 

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

For the Three Months
Ended September 30,
 
For the Nine Months
Ended September 30,
 
For the Three Months
Ended March 31,
 
2019 2018 2019 2018 2020 2019 
Cost of sales (1) $5,276.5  $6,838.9  $16,721.5  $20,371.2  $4,823.0  $5,835.6 
Lower of cost or net realizable value adjustments
recognized within cost of sales
  6.8   1.7   17.1   4.3 
Lower of cost or net realizable value adjustments recognized in cost of sales  38.0   5.4 

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


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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
  
September 30,
2019
  
December 31,
2018
  
Estimated
Useful Life
in Years
  
March 31,
2020
  
December 31,
2019
 
Plants, pipelines and facilities (1)  3-45(5) $45,117.5  $42,371.0   3-45(5) $47,954.0  $47,201.2 
Underground and other storage facilities (2)  5-40(6)  3,888.8   3,624.2   5-40(6)  3,991.9   3,965.5 
Transportation equipment (3)  3-10   197.6   187.1   3-10   203.5   198.9 
Marine vessels (4)  15-30   893.8   828.6   15-30   904.0   905.9 
Land      366.1   359.5       375.9   372.3 
Construction in progress      3,558.1   3,526.8       2,817.4   2,641.2 
Total      54,021.9   50,897.2       56,246.7   55,285.0 
Less accumulated depreciation      13,258.6   12,159.6       14,087.6   13,681.6 
Property, plant and equipment, net     $40,763.3  $38,737.6      $42,159.1  $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 September 30,
 
For the Nine Months
Ended September 30,
 
For the Three Months
Ended March 31,
 
2019 2018 2019 2018 2020 2019 
Depreciation expense (1) $394.7  $368.3  $1,164.6  $1,061.1  $412.2  $380.6 
Capitalized interest (2)  33.9   28.1   102.9   113.4   30.5   36.2 

(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 September 30, 2019March 31, 2020 and December 31, 20182019 includes $66.4$70.0 million and $72.5$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, 2018:2019:

ARO liability balance, December 31, 2018 $126.3 
ARO liability balance, December 31, 2019 $132.1 
Liabilities incurred  0.8   1.2 
Liabilities settled  (0.8)
Revisions in estimated cash flows  (4.9)  (0.2)
Accretion expense  5.9   2.0 
ARO liability balance, September 30, 2019 $127.3 
ARO liability balance, March 31, 2020 $135.1 

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Note 5.  Investments in Unconsolidated Affiliates

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



 
September 30,
2019
  
December 31,
2018
  
March 31,
2020
  
December 31,
2019
 
NGL Pipelines & Services $690.9  $662.0  $699.1  $703.8 
Crude Oil Pipelines & Services  1,877.2   1,867.5   1,877.5   1,866.5 
Natural Gas Pipelines & Services  31.4   22.8   27.9   27.3 
Petrochemical & Refined Products Services  61.4   62.8   4.0   2.6 
Total $2,660.9  $2,615.1  $2,608.5  $2,600.2 

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

  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2019  2018  2019  2018 
NGL Pipelines & Services $25.9  $28.3  $82.7  $87.1 
Crude Oil Pipelines & Services  113.2   83.7   348.8   265.1 
Natural Gas Pipelines & Services  1.6   2.1   4.9   4.7 
Petrochemical & Refined Products Services  (1.4)  (2.1)  (5.1)  (6.9)
Total $139.3  $112.0  $431.3  $350.0 

Combined results of operations data for the periods indicated for our unconsolidated affiliates are summarized in the following table (all data presented on a 100% basis):
  
For the Three Months
Ended March 31,
 
  2020  2019 
NGL Pipelines & Services $32.7  $30.1 
Crude Oil Pipelines & Services  107.3   124.6 
Natural Gas Pipelines & Services  1.6   1.7 
Petrochemical & Refined Products Services  (0.8)  (1.8)
Total $140.8  $154.6 

  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2019  2018  2019  2018 
Income Statement Data:            
Revenues $470.2  $439.1  $1,484.6  $1,296.4 
Operating income  300.3   258.0   938.1   789.8 
Net income  299.5   256.9   935.9   785.6 

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Note 6.  Intangible Assets and Goodwill

Identifiable Intangible Assets

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

 September 30, 2019  December 31, 2018  March 31, 2020  December 31, 2019 
 
Gross
Value
  
Accumulated
Amortization
  
Carrying
Value
  
Gross
Value
  
Accumulated
Amortization
  
Carrying
Value
  
Gross
Value
  
Accumulated
Amortization
  
Carrying
Value
  
Gross
Value
  
Accumulated
Amortization
  
Carrying
Value
 
NGL Pipelines & Services:                                    
Customer relationship intangibles $447.8  $(202.8) $245.0  $457.3  $(201.9) $255.4  $447.8  $(210.0) $237.8  $447.8  $(206.3) $241.5 
Contract-based intangibles  162.6   (40.9)  121.7   363.4   (238.7)  124.7   162.6   (46.7)  115.9   162.6   (43.9)  118.7 
Segment total  610.4   (243.7)  366.7   820.7   (440.6)  380.1   610.4   (256.7)  353.7   610.4   (250.2)  360.2 
Crude Oil Pipelines & Services:                                                
Customer relationship intangibles  2,203.5   (226.9)  1,976.6   2,203.5   (174.1)  2,029.4   2,203.5   (260.1)  1,943.4   2,203.5   (243.5)  1,960.0 
Contract-based intangibles  276.9   (230.1)  46.8   276.9   (211.7)  65.2   276.9   (239.3)  37.6   276.9   (235.0)  41.9 
Segment total  2,480.4   (457.0)  2,023.4   2,480.4   (385.8)  2,094.6   2,480.4   (499.4)  1,981.0   2,480.4   (478.5)  2,001.9 
Natural Gas Pipelines & Services:                                                
Customer relationship intangibles  1,350.3   (473.3)  877.0   1,350.3   (447.8)  902.5   1,350.3   (489.6)  860.7   1,350.3   (481.6)  868.7 
Contract-based intangibles  468.0   (393.6)  74.4   464.7   (387.9)  76.8   468.0   (397.7)  70.3   468.0   (395.5)  72.5 
Segment total  1,818.3   (866.9)  951.4   1,815.0   (835.7)  979.3   1,818.3   (887.3)  931.0   1,818.3   (877.1)  941.2 
Petrochemical & Refined Products Services:                                                
Customer relationship intangibles  181.4   (56.2)  125.2   181.4   (51.8)  129.6   181.4   (59.1)  122.3   181.4   (57.5)  123.9 
Contract-based intangibles  46.0   (23.3)  22.7   46.0   (21.2)  24.8   46.0   (24.6)  21.4   46.0   (24.2)  21.8 
Segment total  227.4   (79.5)  147.9   227.4   (73.0)  154.4   227.4   (83.7)  143.7   227.4   (81.7)  145.7 
Total intangible assets $5,136.5  $(1,647.1) $3,489.4  $5,343.5  $(1,735.1) $3,608.4  $5,136.5  $(1,727.1) $3,409.4  $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 September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended March 31,
 
 2019  2018  2019  2018  2020  2019 
NGL Pipelines & Services $7.3  $9.2  $25.4  $25.6  $6.5  $9.1 
Crude Oil Pipelines & Services  25.1   20.7   71.2   67.3   20.9   22.0 
Natural Gas Pipelines & Services  10.3   9.8   31.2   29.1   10.2   10.9 
Petrochemical & Refined Products Services  2.1   2.2   6.5   6.6   2.0   2.2 
Total $44.8  $41.9  $134.3  $128.6  $39.6  $44.2 

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

Remainder
of 2019
  2020  2021  2022  2023 
Remainder
of 2020
Remainder
of 2020
  2021  2022  2023  2024 
$40.5  $161.8  $162.8  $168.4  $168.5 125.1  $167.1  $164.1  $162.4  $158.9 

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 20182019 Form 10-K.

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Note 7.  Debt Obligations

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

 
September 30,
2019
  
December 31,
2018
  
March 31,
2020
  
December 31,
2019
 
EPO senior debt obligations:            
Commercial Paper Notes, variable-rates $–  $–  $–  $482.0 
Senior Notes N, 6.50% fixed-rate, repaid January 2019  –   700.0 
Senior Notes LL, 2.55% fixed-rate, repaid October 2019  800.0   800.0 
Senior Notes Q, 5.25% fixed-rate, due January 2020  500.0   500.0   –   500.0 
Senior Notes Y, 5.20% fixed-rate, due September 2020  1,000.0   1,000.0   1,000.0   1,000.0 
364-Day Revolving Credit Agreement, variable-rate, due September 2020  –   – 
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   750.0   750.0 
Senior Notes RR, 2.85% fixed-rate, due April 2021  575.0   575.0   575.0   575.0 
Senior Notes VV, 3.50% fixed-rate, due February 2022  750.0   750.0   750.0   750.0 
Senior Notes CC, 4.05% fixed-rate, due February 2022  650.0   650.0   650.0   650.0 
Senior Notes HH, 3.35% fixed-rate, due March 2023  1,250.0   1,250.0   1,250.0   1,250.0 
Senior Notes JJ, 3.90% fixed-rate, due February 2024  850.0   850.0   850.0   850.0 
Multi-Year Revolving Credit Agreement, variable-rate, due September 2024  –   –   –   – 
Senior Notes MM, 3.75% fixed-rate, due February 2025  1,150.0   1,150.0   1,150.0   1,150.0 
Senior Notes PP, 3.70% fixed-rate, due February 2026  875.0   875.0   875.0   875.0 
Senior Notes SS, 3.95% fixed-rate, due February 2027  575.0   575.0   575.0   575.0 
Senior Notes WW, 4.15% fixed-rate, due October 2028  1,000.0   1,000.0   1,000.0   1,000.0 
Senior Notes YY, 3.125% fixed-rate, due July 2029  1,250.0   –   1,250.0   1,250.0 
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   500.0   500.0 
Senior Notes H, 6.65% fixed-rate, due October 2034  350.0   350.0   350.0   350.0 
Senior Notes J, 5.75% fixed-rate, due March 2035  250.0   250.0   250.0   250.0 
Senior Notes W, 7.55% fixed-rate, due April 2038  399.6   399.6   399.6   399.6 
Senior Notes R, 6.125% fixed-rate, due October 2039  600.0   600.0   600.0   600.0 
Senior Notes Z, 6.45% fixed-rate, due September 2040  600.0   600.0   600.0   600.0 
Senior Notes BB, 5.95% fixed-rate, due February 2041  750.0   750.0   750.0   750.0 
Senior Notes DD, 5.70% fixed-rate, due February 2042  600.0   600.0   600.0   600.0 
Senior Notes EE, 4.85% fixed-rate, due August 2042  750.0   750.0   750.0   750.0 
Senior Notes GG, 4.45% fixed-rate, due February 2043  1,100.0   1,100.0   1,100.0   1,100.0 
Senior Notes II, 4.85% fixed-rate, due March 2044  1,400.0   1,400.0   1,400.0   1,400.0 
Senior Notes KK, 5.10% fixed-rate, due February 2045  1,150.0   1,150.0   1,150.0   1,150.0 
Senior Notes QQ, 4.90% fixed-rate, due May 2046  975.0   975.0   975.0   975.0 
Senior Notes UU, 4.25% fixed-rate, due February 2048  1,250.0   1,250.0   1,250.0   1,250.0 
Senior Notes XX, 4.80% fixed-rate, due February 2049  1,250.0   1,250.0   1,250.0   1,250.0 
Senior Notes ZZ, 4.20% fixed-rate, due January 2050  1,250.0   –   1,250.0   1,250.0 
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   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   0.4   0.4 
Total principal amount of senior debt obligations  25,550.0   23,750.0   27,250.0   25,232.0 
EPO Junior Subordinated Notes C, variable-rate, due June 2067 (1)
  232.2   256.4   232.2   232.2 
EPO Junior Subordinated Notes D, fixed/variable-rate, due August 2077 (2)
  700.0   700.0   700.0   700.0 
EPO Junior Subordinated Notes E, fixed/variable-rate, due August 2077 (3)
  1,000.0   1,000.0   1,000.0   1,000.0 
EPO Junior Subordinated Notes F, fixed/variable-rate, due February 2078 (4)
  700.0   700.0   700.0   700.0 
TEPPCO Junior Subordinated Notes, variable-rate, due June 2067 (1)
  14.2   14.2   14.2   14.2 
Total principal amount of senior and junior debt obligations  28,196.4   26,420.6   29,896.4   27,878.4 
Other, non-principal amounts  (257.2)  (242.4)  (290.5)  (253.3)
Less current maturities of debt  (2,300.0)  (1,500.1)  (1,750.0)  (1,981.9)
Total long-term debt $25,639.2  $24,678.1  $27,855.9  $25,643.2 

(1)Variable rate is reset quarterly and based on 3-month LIBOR, or London Inter-BankInterbank Offered Rate ("LIBOR"), plus 2.778%.  During 2019, EPO repurchased and retired $24.2 million in principal amount of these junior subordinated notes.
(2)Fixed rate of 4.875% through August 15, 2022; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 2.986%.
(3)Fixed rate of 5.250% through August 15, 2027; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 3.033%.
(4)Fixed rate of 5.375% through February 14, 2028; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 2.57%.

References to “TEPPCO” mean TEPPCO Partners, L.P. prior to its merger with one of our wholly owned subsidiaries in October 2009.
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The following table presents the range of interest rates and weighted-average interest rates paid on our consolidated variable-rate debt during the ninethree months ended September 30, 2019:March 31, 2020:

 
Range of Interest
Rates Paid
Weighted-Average
Interest Rate Paid
Commercial Paper Notes2.58%1.78% to 2.80%2.08%2.72%1.86%
EPO Junior Subordinated Notes C and TEPPCO Junior Subordinated Notes4.91%4.36% to 5.52%4.68%5.34%4.57%

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

The following table presents the scheduled contractual maturities of principal amounts of our consolidated debt obligations at September 30, 2019March 31, 2020 for the next five years and in total thereafter:

     Scheduled Maturities of Debt 
  Total  
Remainder
of 2019
  2020  2021  2022  2023  Thereafter 
Principal amount of senior and junior debt obligations at
    September 30, 2019
 $28,196.4  $800.0  $1,500.0  $1,325.0  $1,400.0  $1,250.0  $21,921.4 
     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 

In October 2019, we repaid $800.0 million principal amount of EPO’s Senior Notes LL at their maturity using unrestricted cash on hand.April 2020, EPO entered into an additional 364-Day revolving credit agreement.   See Note 19 regarding this subsequent event.

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.

Amendment to Multi-Year Revolving Credit Agreement

In September 2019, EPO entered into an amendment (the “First Amendment”) to its revolving credit agreement dated September 13, 2017 (the “Multi-Year Revolving Credit Agreement”).  The First Amendment reduces the borrowing capacity under the Multi-Year Revolving Credit Agreement from $4.0 billion to $3.5 billion (which may be increased by up to $500 million to $4.0 billion at EPO’s election provided certain conditions are met) and extends the maturity date to September 10, 2024, although the maturity date may be extended further at EPO’s request by up to two years, with the consent of required lenders as set forth under the credit agreement.  Borrowings under this revolving credit agreement may be used for working capital, capital expenditures, acquisitions and general company purposes.

The Multi-Year Revolving Credit Agreement contains customary representations, warranties, covenants (affirmative and negative) and events of default, the occurrence of which would permit the lenders to accelerate the maturity date of any amounts borrowed under this credit agreement.  The Multi-Year Revolving Credit Agreement also restricts EPO’s ability to pay cash distributions to its parent, Enterprise Products Partners L.P., if an event of default (as defined in the credit agreement) has occurred and is continuing at the time such distribution is scheduled to be paid or would result therefrom.

EPO’s obligations under the Multi-Year Revolving Credit Agreement are not secured by any collateral; however, they are guaranteed by Enterprise Products Partners L.P.
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Renewal of 364-Day Revolving Credit Agreement

In September 2019, EPO entered into a new 364-Day Revolving Credit Agreement that replaced its prior 364-day credit facility.  The new 364-Day Revolving Credit Agreement matures in September 2020. There are currently no principal amounts outstanding under this revolving credit agreement.

Under the terms of the new 364-Day Revolving Credit Agreement, EPO may borrow up to $1.5 billion (which may be increased by up to $200 million to $1.7 billion at EPO’s election, provided certain conditions are met) at a variable interest rate for a term of up to 364 days, subject to the terms and conditions set forth therein.  To the extent that principal amounts are outstanding at the maturity date, EPO may elect to have the entire principal balance then outstanding continued as non-revolving term loans for a period of one additional year, payable in September 2021. Borrowings under this revolving credit agreement may be used for working capital, capital expenditures, acquisitions and general company purposes.

The new 364-Day Revolving Credit Agreement contains customary representations, warranties, covenants (affirmative and negative) and events of default, the occurrence of which would permit the lenders to accelerate the maturity date of any amounts borrowed under this credit agreement.  The credit agreement also restricts EPO’s ability to pay cash distributions to its parent, Enterprise Products Partners L.P., if an event of default (as defined in the credit agreement) has occurred and is continuing at the time such distribution is scheduled to be paid or would result therefrom.

EPO’s obligations under the new 364-Day Revolving Credit Agreement are not secured by any collateral; however, they are guaranteed by Enterprise Products Partners L.P.

Issuance of $2.5$3.0 Billion of Senior Notes in July 2019January 2020

In July 2019,January 2020, EPO issued $2.5$3.0 billion aggregate principal amount of senior notes comprised of $1.25 billion principal amount of senior notes due July 2029 (“Senior Notes YY”) and $1.25(i) $1.0 billion principal amount of senior notes due January 20502030 (“Senior Notes ZZ”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 debt$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, includingpurposes.  In addition, net proceeds from this offering will be used by EPO for growth capital expenditures.the repayment of $1.0 billion principal amount of its Senior Notes Y upon their maturity in September 2020.

Senior Notes YYAAA were issued at 99.955%99.921% of their principal amount and have a fixedfixed-rate interest rate of 3.125%2.80% per year.  Senior Notes ZZBBB were issued at 99.792%99.413% of their principal amount and have a fixedfixed-rate interest rate of 4.20%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 has guaranteed thethese senior notes through an unconditional guarantee on an unsecured and unsubordinated basis.

Partial Retirement of Junior Subordinated Notes During Second Quarter of 2019

During the second quarter of 2019, EPO repurchased and retired $24.2 million in principal amount of its Junior Subordinated Notes C.  A $1.5 million gain on the extinguishment of these debt obligations is included in “Other, net” on our Unaudited Condensed Statements of Consolidated Operations with respect to the nine months ended September 30, 2019.

Lender Financial Covenants

We were in compliance with the financial covenants of our consolidated debt agreements at September 30, 2019.March 31, 2020.

Letters of Credit

At September 30, 2019,March 31, 2020, EPO had $101.4 million of letters of credit outstanding primarily related to our commodity hedging activities.

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Note 8.  Equity and Distributions

Limited Partner Common Units OutstandingPartners’ Equity

The following table summarizes changes in the number of EPDour limited partner common units outstanding and treasury units since December 31, 2018:2019:

Common units outstanding at December 31, 20182,184,869,029
Common unit repurchases under 2019 Buyback Program(1,852,392)
Common units issued in connection with DRIP and EUPP1,516,779
Common units issued in connection with the vesting of phantom unit awards, net2,379,620
Common units issued in connection with employee compensation1,626,041
Other21,595
Common units outstanding at March 31, 20192,188,560,672
Common unit repurchases under 2019 Buyback Program(1,056,736)
Common units issued in connection with DRIP and EUPP1,381,211
Common units issued in connection with the vesting of phantom unit awards, net120,831
Common units outstanding at June 30, 20192,189,005,978
Common units issued in connection with the vesting of phantom unit awards, net163,550
Common units outstanding at September 30, 20192,189,169,528
 
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 

We have a universal shelf registration statement (the “2019 Shelf”) on file with the SEC which allows EPD and EPO (each on a standalone basis) to issue an unlimited amount of equity and debt securities, respectively. The 2019 Shelf replaced our prior universal shelf registration statement, which expired in May 2019.  EPO issued $2.5$3.0 billion of senior notes in July 2019January 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 ninethree months ended September 30, 2019March 31, 2020 and 20182019, 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 September 30, 2019,March 31, 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.

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

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

The 54,807,352 new EPD common units issued to Skyline upon settlement of the Liquidity Option constitute “restricted securities” in the meaning of Rule 144 under the Securities Act of 1933, as amended (the “Securities Act”) and may not be resold except pursuant to an effective registration statement or an available exemption under the Securities Act.  In connection with the settlement of the Liquidity Option, Enterprise entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with Skyline. Pursuant to the Registration Rights Agreement, Skyline has the right to request that we prepare and file a registration statement to permit and otherwise facilitate the public resale of all or a portion of such EPD common units that Skyline and its affiliates then own.  Our obligation to Skyline to effect such transactions is limited to 5 registration statements and underwritten offerings.
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As a result of the Liquidity Option settlement, the partners’ equity balance for common units (as presented on our Unaudited Condensed Consolidated Balance Sheet) increased by the $1.3 billion market value of the new EPD common units issued to Skyline.  Since OTA does not meet the definition of a business as described in ASC 805, Business Combinations, the acquisition of OTA was accounted for as the purchase of treasury units and assumption of the related deferred tax liability.  In consolidation, we present the 54,807,352 EPD common units owned by OTA as treasury units, with their historical cost based on the $1.3 billion market value of the 54,807,352 new EPD common units issued to Skyline.

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

Common unit repurchases underUnit 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.

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 2,909,1286,357,739 common units under the 2019 Buyback Program through open market purchases during the ninethree months ended September 30, 2019March 31, 2020 (no repurchases were made during the third quarter of 2019).  The total purchase price of these repurchases (including commissions and fees) was $81.1 million, excluding commissions140.1 million. During the three months ended March 31, 2019, EPD repurchased 1,852,392 common units under the 2019 Buyback Program for a total purchase price of $51.6 million.  The units repurchased during the three months ended March 31, 2020 and fees. The repurchased units2019 were immediately cancelled immediately upon acquisition.  At September 30, 2019,March 31, 2020, the remaining available capacity under the 2019 Buyback Program was $1.921.78 billion.
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Common Units Issued in Connection With the Vesting of Phantom Unit Awards
During the three months ended March 31, 2020, after taking into account tax withholding requirements, EPD issued a net 2,912,214 new common units issuedto 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”). EPD issued and delivered a total of 2,601,727 new common units under the DRIP during the nine months ended September 30, 2019, which generated net cash proceeds of $73.7 million.  During the nine months ended September 30, 2018, EPD issued and delivered 16,073,974 new common units under the DRIP, which generated net cash proceeds of $438.1 million.  After taking into account the number of common units delivered under the DRIP through September 30, 2019, EPD has the capacity to deliver an additional 57,544,841 common units under this plan.  The period-to-period decrease in net cash proceeds from the DRIP is primarily due to (i) lower reinvestments by privately held affiliates of EPCO in 2019, (ii) a reduction in the discount applicable to common unit purchases made under the DRIP from 2.5% to 0% beginning with the distribution paid in February 2019 and (iii) the election to satisfy delivery obligations under the DRIP using common units purchased on the open market, rather than issuing new common units, beginning with the distribution paid in August 2019.

EPD issued and delivered 296,263 new common units under the EUPP during the nine months ended September 30, 2019, which generated net cash proceeds of $8.5 million.  During the nine months ended September 30, 2018, EPD issued and delivered 403,602 new common units under its EUPP, which generated net cash proceeds of $11.3 million.  After taking into account the number of common units delivered under the EUPP through September 30, 2019, EPD may deliver an additional 4,763,149 common units under this plan.

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

In July 2019, EPD announced that, beginning with the quarterly distribution payment 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.  In August 2019,February 2020, a total of 1,410,0201,422,063 common units were purchased on the open market and delivered to participants in connection with the DRIP and EUPP.  Apart from $0.5million 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 NovemberMay 12, 2019.

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

Common Units Issued in Connection With the Vesting of Phantom Unit Awards
During the nine months ended September 30, 2019, after taking into account tax withholding requirements, EPD issued a net 2,664,001 new common units to employees in connection with the vesting of phantom unit awards.  See Note 12 for information regarding our phantom unit awards.2020.
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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Accumulated Other Comprehensive Income (Loss)

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

 Cash Flow Hedges        Cash Flow Hedges       
 
Commodity
Derivative
Instruments
  
Interest Rate
Derivative
Instruments
  Other  
Total
  
Commodity
Derivative
Instruments
  
Interest Rate
Derivative
Instruments
  Other  
Total
 
Accumulated Other Comprehensive Income (Loss), December 31, 2018 $152.7  $(104.8) $3.0  $50.9 
Accumulated Other Comprehensive Income, December 31, 2019 $55.1  $13.9  $2.4  $71.4 
Other comprehensive income (loss) for period, before reclassifications  58.6   (23.8)  (0.6)  34.2   475.1   (292.0)  (0.1)  183.0 
Reclassification of losses (gains) to net income during period  (152.0)  27.8   –   (124.2)  (155.6)  23.5   –   (132.1)
Total other comprehensive income (loss) for period  (93.4)  4.0   (0.6)  (90.0)  319.5   (268.5)  (0.1)  50.9 
Accumulated Other Comprehensive Income (Loss), September 30, 2019 $59.3  $(100.8) $2.4  $(39.1)
Accumulated Other Comprehensive Income (Loss), March 31, 2020 $374.6  $(254.6) $2.3  $122.3 

 Cash Flow Hedges        Cash Flow Hedges       
 
Commodity
Derivative
Instruments
  
Interest Rate
Derivative
Instruments
  Other  
Total
  
Commodity
Derivative
Instruments
  
Interest Rate
Derivative
Instruments
  Other  
Total
 
Accumulated Other Comprehensive Income (Loss), December 31, 2017 $(10.1) $(165.1) $3.5  $(171.7)
Accumulated Other Comprehensive Income (Loss), December 31, 2018 $152.7  $(104.8) $3.0  $50.9 
Other comprehensive income (loss) for period, before reclassifications  (156.0)  20.7   (0.5)  (135.8)  (95.2)  –   (0.6)  (95.8)
Reclassification of losses (gains) to net income during period  (28.8)  29.0   –   0.2   (58.3)  9.2   –   (49.1)
Total other comprehensive income (loss) for period  (184.8)  49.7   (0.5)  (135.6)  (153.5)  9.2   (0.6)  (144.9)
Accumulated Other Comprehensive Income (Loss), September 30, 2018 $(194.9) $(115.4) $3.0  $(307.3)
Accumulated Other Comprehensive Income (Loss), March 31, 2019 $(0.8) $(95.6) $2.4  $(94.0)

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

 
For the Three Months
Ended March 31,
   
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 Location2020 2019
Losses (gains) on cash flow hedges:Location 2019  2018  2019  2018      
Interest rate derivativesInterest expense $9.4  $9.1  $27.8  $29.0 Interest expense$23.5 $9.2
Commodity derivativesRevenue  (93.6)  (53.9)  (161.4)  (28.5)Revenue (154.4)  (65.3)
Commodity derivativesOperating costs and expenses  2.1   0.4   9.4   (0.3)Operating costs and expenses (1.2)  7.0
Total  $(82.1) $(44.4) $(124.2) $0.2  $(132.1) $(49.1)

For information regarding our interest rate and commodity derivative instruments, see Note 13.14.

Noncontrolling Interests

In June 2019, an affiliate of American Midstream, LP acquired a noncontrolling 25% equity interest in our consolidated subsidiary that owns the Pascagoula natural gas processing plant for $36.0 million in cash.  In July 2019, Altus Midstream Processing LP acquired a noncontrolling 33% equity interest in our consolidated subsidiary that owns the Shin Oak NGL Pipeline for $440.7 million in cash.  The following table presents information regarding our noncontrolling interests since December 31, 2018:

Noncontrolling interest balance in Equity, December 31, 2018 $438.7 
Net income attributable to noncontrolling interests  67.3 
Cash distributions paid to noncontrolling interests  (69.7)
Cash contributions from noncontrolling interests  590.8 
Other  2.4 
Noncontrolling interest balance in Equity, September 30, 2019 $1,029.5 
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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Cash Distributions

In January 2019, management announced its plans to recommend toOn March 18, 2020, the Board an increase of $0.0025 per unit per quarter in EPD’sdeclared a quarterly cash distribution rateto be paid to our limited partners with respect to 2019. The anticipated ratethe first quarter of increase would result in distributions for 20192020 of $1.7650$0.4450 per common unit, or $1.78 per unit which would be 2.3% higher than those paid by EPD for 2018on an annualized basis.  The quarterly distribution associated with the first quarter of $1.7250 per unit.2020 is payable on May 12, 2020, to unitholders of record as of the close of business on April 30, 2020.  This distribution represents a 1.7% increase over the distribution declared with respect to the first quarter of 2019.

In light of current economic conditions, management will evaluate future cash distributions in 2020 on a quarterly basis.  The payment of any quarterly cash distribution is subject to Board approval and management’s evaluation of our financial condition, results of operations and cash flows in connection with such payment.payments.


On October 9, 2019, EPD announced that the Board declared a cash distribution



17

Table of $0.4425 per common unit with respect to the third quarter of 2019, which represents a 2.3% increase over the $0.4325 per common unit EPD declared and paid with respect to the third quarter of 2018.  The distribution with respect to the third quarter of 2019 will be paid on November 12, 2019 to unitholders of record as of the close of business on October 31, 2019.Contents
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 September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended March 31,
 
 2019  2018  2019  2018  2020  2019 
NGL Pipelines & Services:                  
Sales of NGLs and related products $2,624.9  $3,898.2  $7,955.5  $9,324.5  $2,419.2  $2,671.2 
Segment midstream services:                        
Natural gas processing and fractionation  279.6   397.2   837.3   982.2   188.5   269.5 
Transportation  248.2   241.8   767.4   725.5   265.0   275.3 
Storage and terminals  99.4   85.7   291.0   277.7   95.4   98.4 
Total segment midstream services  627.2   724.7   1,895.7   1,985.4   548.9   643.2 
Total NGL Pipelines & Services  3,252.1   4,622.9   9,851.2   11,309.9   2,968.1   3,314.4 
Crude Oil Pipelines & Services:                        
Sales of crude oil  2,130.0   2,209.0   6,990.1   8,082.9   1,696.9   2,328.4 
Segment midstream services:                        
Transportation  209.1   187.9   598.1   490.7   218.4   183.7 
Storage and terminals  139.2   98.0   364.0   273.4   123.6   95.2 
Total segment midstream services  348.3   285.9   962.1   764.1   342.0   278.9 
Total Crude Oil Pipelines & Services  2,478.3   2,494.9   7,952.2   8,847.0   2,038.9   2,607.3 
Natural Gas Pipelines & Services:                        
Sales of natural gas  440.0   589.0   1,627.1   1,681.5   399.2   655.7 
Segment midstream services:                        
Transportation  275.5   261.2   835.2   766.3   271.4   271.8 
Total segment midstream services  275.5   261.2   835.2   766.3   271.4   271.8 
Total Natural Gas Pipelines & Services  715.5   850.2   2,462.3   2,447.8   670.6   927.5 
Petrochemical & Refined Products Services:                        
Sales of petrochemicals and refined products  1,299.0   1,408.9   3,867.3   4,111.6   1,597.5   1,480.6 
Segment midstream services:                        
Fractionation and isomerization  43.2   45.9   125.5   146.8   35.8   40.8 
Transportation, including marine logistics  134.4   119.2   393.2   353.0   134.9   126.6 
Storage and terminals  41.6   43.9   132.2   135.8   36.7   46.3 
Total segment midstream services  219.2   209.0   650.9   635.6   207.4   213.7 
Total Petrochemical & Refined Products Services  1,518.2   1,617.9   4,518.2   4,747.2   1,804.9   1,694.3 
Total consolidated revenues $7,964.1  $9,585.9  $24,783.9  $27,351.9  $7,482.5  $8,543.5 

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

Unbilled Revenue and midstream services accounted for 82%Deferred Revenue

The following table provides information regarding our contract assets and 18%, respectively, of our consolidated revenues for the three and nine months ended September 30, 2019.  During the three and nine months ended September 30, 2018, product sales and midstream services accounted for 85% and 15%, respectively, of our consolidated revenues.contract liabilities at March 31, 2020:

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

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

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


Unbilled Revenue and Deferred Revenue

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

Contract AssetLocation Balance 
Unbilled revenue (current amount)Prepaid and other current assets $223.8 
Total  $223.8 

Contract LiabilityLocation Balance 
Deferred revenue (current amount)Other current liabilities $137.4 
Deferred revenue (noncurrent)Other long-term liabilities  192.2 
Total  $329.6 

The following table presents significant changes in our unbilled revenue and deferred revenue balances during the ninethree months ended September 30, 2019:March 31, 2020:


 
Unbilled
Revenue
  
Deferred
Revenue
  
Unbilled
Revenue
  
Deferred
Revenue
 
Balance at December 31, 2018 $13.3  $291.2 
Balance at December 31, 2019 $17.6  $314.9 
Amount included in opening balance transferred to other accounts during period (1)  (13.3)  (110.9)  (4.2)  (64.8)
Amount recorded during period  270.5   430.7   65.6   170.9 
Amounts recorded during period transferred to other accounts (1)  (46.7)  (278.7)  (8.5)  (75.8)
Other changes  –   (2.7)  –   (2.5)
Balance at September 30, 2019 $223.8  $329.6 
Balance at March 31, 2020 $70.5  $342.7 

(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 with customers as of September 30, 2019 that contain minimum volume commitments, deficiency and similar fees and contract terms exceedingthe term of the contracts exceeds one year.  These amounts represent the revenues we expect to recognize in future periods from these contracts as of March 31, 2020.

Period Fixed Consideration  
Fixed
Consideration
 
Three Months Ended December 31, 2019 $945.0 
One Year Ended December 31, 2020  3,505.7 
Nine Months Ended December 31, 2020 $2,901.3 
One Year Ended December 31, 2021  3,075.3   3,594.9 
One Year Ended December 31, 2022  2,636.9   3,250.9 
One Year Ended December 31, 2023  2,203.9   2,990.0 
One Year Ended December 31, 2024  2,855.1 
Thereafter
  10,576.7   14,587.2 
Total $22,943.5  $30,179.4 



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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Note 10.  Business Segments and Related Information

Our operations are reported under 4 business segments: (i) NGL Pipelines & Services, (ii) Crude Oil Pipelines & Services, (iii) Natural Gas Pipelines & Services and (iv) Petrochemical & Refined Products Services.

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.
21

Table Our calculation of Contentsgross operating margin may or may not be comparable to similarly titled measures used by other companies.
ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


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 September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended March 31,
 
 2019  2018  2019  2018  2020  2019 
Operating income $1,474.2  $1,643.3  $4,660.7  $3,768.2  $1,507.5  $1,626.2 
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  467.1   429.4   1,380.8   1,249.0   482.8   450.9 
Asset impairment and related charges in operating costs and expenses  39.4   4.6   51.2   21.4   1.6   4.8 
Net gains attributable to asset sales in operating costs and expenses  (0.1)  (6.7)  (2.6)  (8.1)
Net losses (gains) attributable to asset sales in operating costs and expenses  0.1   (0.4)
General and administrative costs  55.5   52.7   160.2   157.1   55.5   52.2 
Non-refundable payments received from shippers attributable to make-up rights (1)
  20.8   6.5   34.3   14.8   16.8   2.2 
Subsequent recognition of revenues attributable to make-up rights (2)  (5.5)  (6.2)  (18.6)  (42.4)  (7.1)  (7.5)
Total segment gross operating margin $2,051.4  $2,123.6  $6,266.0  $5,160.0  $2,057.2  $2,128.4 

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

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

  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2019  2018  2019  2018 
Gross operating margin by segment:            
NGL Pipelines & Services $1,008.3  $1,063.1  $2,933.8  $2,861.7 
Crude Oil Pipelines & Services  496.2   594.2   1,671.7   867.0 
Natural Gas Pipelines & Services  258.5   216.9   824.6   628.2 
Petrochemical & Refined Products Services  288.4   249.4   835.9   803.1 
Total segment gross operating margin $2,051.4  $2,123.6  $6,266.0  $5,160.0 

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

  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2019  2018  2019  2018 
Mark-to-market gains (losses) in gross operating margin:            
NGL Pipelines & Services $(0.7) $0.1  $(0.1) $7.9 
Crude Oil Pipelines & Services  9.8   200.2   95.0   (267.4)
Natural Gas Pipelines & Services  1.3   4.7   1.3   5.9 
Petrochemical & Refined Products Services  (1.3)  (0.9)  (3.3)  (1.2)
     Total mark-to-market impact on gross operating margin  9.1   204.1   92.9   (254.8)
Mark-to-market loss in interest expense  (94.9)  –   (94.9)  (0.1)
Total $(85.8) $204.1  $(2.0) $(254.9)

For information regarding our hedging activities, see Note 13.

  
For the Three Months
Ended March 31,
 
  2020  2019 
Gross operating margin by segment:      
NGL Pipelines & Services $1,042.0  $959.2 
Crude Oil Pipelines & Services  452.9   662.3 
Natural Gas Pipelines & Services  283.8   264.3 
Petrochemical & Refined Products Services  278.5   242.6 
Total segment gross operating margin $2,057.2  $2,128.4 
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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 March 31,
 
  2020  2019 
Mark-to-market gains (losses) in gross operating margin:      
NGL Pipelines & Services $(12.3) $1.3 
Crude Oil Pipelines & Services  10.7   99.8 
Natural Gas Pipelines & Services  28.8   (0.3)
Petrochemical & Refined Products Services  2.3   (4.5)
     Total mark-to-market impact on gross operating margin $29.5  $96.3 

For information regarding our hedging activities, see Note 14.

Summarized Segment Financial Information

Information by business segment, together with reconciliations to amounts presented on 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 September 30, 2019 $3,250.1  $2,467.9  $712.3  $1,518.2  $–  $7,948.5 
Three months ended September 30, 2018  4,616.7   2,490.7   846.4   1,617.9   –   9,571.7 
Nine months ended September 30, 2019  9,843.9   7,916.5   2,451.6   4,518.2   –   24,730.2 
Nine months ended September 30, 2018  11,295.1   8,777.2   2,437.9   4,747.2   –   27,257.4 
Revenues from related parties:                        
Three months ended September 30, 2019  2.0   10.4   3.2   –   –   15.6 
Three months ended September 30, 2018  6.2   4.2   3.8   –   –   14.2 
Nine months ended September 30, 2019  7.3   35.7   10.7   –   –   53.7 
Nine months ended September 30, 2018  14.8   69.8   9.9   –   –   94.5 
Intersegment and intrasegment revenues:                        
Three months ended September 30, 2019  4,729.3   9,479.7   141.7   558.1   (14,908.8)  – 
Three months ended September 30, 2018  6,814.9   6,278.8   186.6   844.3   (14,124.6)  – 
Nine months ended September 30, 2019  14,715.5   26,818.0   500.2   1,890.4   (43,924.1)  – 
Nine months ended September 30, 2018  19,384.4   27,683.6   522.5   2,241.6   (49,832.1)  – 
Total revenues:                        
Three months ended September 30, 2019  7,981.4   11,958.0   857.2   2,076.3   (14,908.8)  7,964.1 
Three months ended September 30, 2018  11,437.8   8,773.7   1,036.8   2,462.2   (14,124.6)  9,585.9 
Nine months ended September 30, 2019  24,566.7   34,770.2   2,962.5   6,408.6   (43,924.1)  24,783.9 
Nine months ended September 30, 2018  30,694.3   36,530.6   2,970.3   6,988.8   (49,832.1)  27,351.9 
Equity in income (loss) of unconsolidated affiliates:                        
Three months ended September 30, 2019  25.9   113.2   1.6   (1.4)  –   139.3 
Three months ended September 30, 2018  28.3   83.7   2.1   (2.1)  –   112.0 
Nine months ended September 30, 2019  82.7   348.8   4.9   (5.1)  –   431.3 
Nine months ended September 30, 2018  87.1   265.1   4.7   (6.9)  –   350.0 
  Reportable Business Segments       
  
NGL
Pipelines
& Services
  
Crude Oil
Pipelines
& Services
  
Natural Gas
Pipelines
& Services
  
Petrochemical
& Refined
Products
Services
  
Adjustments
and
Eliminations
  
Consolidated
Total
 
Revenues from third parties:                  
Three months ended March 31, 2020 $2,966.3  $2,027.7  $667.6  $1,804.9  $–  $7,466.5 
Three months ended March 31, 2019  3,311.6   2,601.6   923.7   1,694.3   –   8,531.2 
Revenues from related parties:                        
Three months ended March 31, 2020  1.8   11.2   3.0   –   –   16.0 
Three months ended March 31, 2019  2.8   5.7   3.8   –   –   12.3 
Intersegment and intrasegment revenues:                        
Three months ended March 31, 2020  5,780.7   7,840.3   115.1   808.1   (14,544.2)  – 
Three months ended March 31, 2019  5,491.4   7,885.0   195.4   714.4   (14,286.2)  – 
Total revenues:                        
Three months ended March 31, 2020  8,748.8   9,879.2   785.7   2,613.0   (14,544.2)  7,482.5 
Three months ended March 31, 2019  8,805.8   10,492.3   1,122.9   2,408.7   (14,286.2)  8,543.5 
Equity in income (loss) of unconsolidated affiliates:                        
Three months ended March 31, 2020  32.7   107.3   1.6   (0.8)  –   140.8 
Three months ended March 31, 2019  30.1   124.6   1.7   (1.8)  –   154.6 

Segment revenues include intersegment and intrasegment transactions, which are generally based on transactions made at market-based rates.  Our consolidated revenues reflect the elimination of intercompany transactions.  Substantially all of our consolidated revenues are earned in the U.S. and derived from a wide customer base.
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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 September 30, 2019 $16,212.2  $6,316.2  $8,320.5  $6,356.3  $3,558.1  $40,763.3 
At December 31, 2018  14,845.4   5,847.7   8,303.8   6,213.9   3,526.8   38,737.6 
Investments in unconsolidated affiliates:
(see Note 5)
                        
At September 30, 2019  690.9   1,877.2   31.4   61.4   –   2,660.9 
At December 31, 2018  662.0   1,867.5   22.8   62.8   –   2,615.1 
Intangible assets, net: (see Note 6)
                        
At September 30, 2019  366.7   2,023.4   951.4   147.9   –   3,489.4 
At December 31, 2018  380.1   2,094.6   979.3   154.4   –   3,608.4 
Goodwill: (see Note 6)
                        
At September 30, 2019  2,651.7   1,841.0   296.3   956.2   –   5,745.2 
At December 31, 2018  2,651.7   1,841.0   296.3   956.2   –   5,745.2 
Segment assets:                        
At September 30, 2019  19,921.5   12,057.8   9,599.6   7,521.8   3,558.1   52,658.8 
At December 31, 2018  18,539.2   11,650.8   9,602.2   7,387.3   3,526.8   50,706.3 
  Reportable Business Segments       
  
NGL
Pipelines
& Services
  
Crude Oil
Pipelines
& Services
  
Natural Gas
Pipelines
& Services
  
Petrochemical
& Refined
Products
Services
  
Adjustments
and
Eliminations
  
Consolidated
Total
 
Property, plant and equipment, net:
(see Note 4)
                  
At March 31, 2020 $16,997.8  $6,340.2  $8,433.6  $7,570.1  $2,817.4  $42,159.1 
At December 31, 2019  16,652.1   6,324.4   8,432.5   7,553.2   2,641.2   41,603.4 
Investments in unconsolidated affiliates:
(see Note 5)
                        
At March 31, 2020  699.1   1,877.5   27.9   4.0   –   2,608.5 
At December 31, 2019  703.8   1,866.5   27.3   2.6   –   2,600.2 
Intangible assets, net: (see Note 6)
                        
At March 31, 2020  353.7   1,981.0   931.0   143.7   –   3,409.4 
At December 31, 2019  360.2   2,001.9   941.2   145.7   –   3,449.0 
Goodwill: (see Note 6)
                        
At March 31, 2020  2,651.7   1,841.0   296.3   956.2   –   5,745.2 
At December 31, 2019  2,651.7   1,841.0   296.3   956.2   –   5,745.2 
Segment assets:                        
At March 31, 2020  20,702.3   12,039.7   9,688.8   8,674.0   2,817.4   53,922.2 
At December 31, 2019  20,367.8   12,033.8   9,697.3   8,657.7   2,641.2   53,397.8 

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 September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended March 31,
 
 2019  2018  2019  2018  2020  2019 
Consolidated revenues:                  
NGL Pipelines & Services $3,252.1  $4,622.9  $9,851.2  $11,309.9  $2,968.1  $3,314.4 
Crude Oil Pipelines & Services  2,478.3   2,494.9   7,952.2   8,847.0   2,038.9   2,607.3 
Natural Gas Pipelines & Services  715.5   850.2   2,462.3   2,447.8   670.6   927.5 
Petrochemical & Refined Products Services  1,518.2   1,617.9   4,518.2   4,747.2   1,804.9   1,694.3 
Total consolidated revenues $7,964.1  $9,585.9  $24,783.9  $27,351.9  $7,482.5  $8,543.5 
                        
Consolidated costs and expenses                        
Operating costs and expenses:                        
Cost of sales $5,276.5  $6,838.9  $16,721.5  $20,371.2  $4,823.0  $5,835.6 
Other operating costs and expenses (1)  790.8   735.7   2,243.4   2,143.1   752.8   728.8 
Depreciation, amortization and accretion  467.1   429.4   1,380.8   1,249.0   482.8   450.9 
Asset impairment and related charges  39.4   4.6   51.2   21.4   1.6   4.8 
Net gains attributable to asset sales
  (0.1)  (6.7)  (2.6)  (8.1)
Net losses (gains) attributable to asset sales  0.1   (0.4)
General and administrative costs  55.5   52.7   160.2   157.1   55.5   52.2 
Total consolidated costs and expenses $6,629.2  $8,054.6  $20,554.5  $23,933.7  $6,115.8  $7,071.9 

(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.

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Note 11.  Income Taxes

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

OTA Deferred Tax Liability

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

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

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

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

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Tabular Disclosures Regarding Income Taxes

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

  
For the Three Months
Ended March 31,
 
  2020  2019 
Current portion of income tax provision (benefit):      
Federal $0.1  $0.9 
State  4.6   9.0 
Foreign  0.2   0.6 
Total current portion  4.9   10.5 
Deferred portion of income tax provision (benefit):        
    Federal  (172.8)  (0.1)
    State  (11.3)  1.9 
Total deferred portion  (184.1)  1.8 
Total provision for (benefit from) income taxes $(179.2) $12.3 

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

  
For the Three Months
Ended March 31,
 
  2020  2019 
Pre-Tax Net Book Income (“NBI”) $1,195.8  $1,292.7 
         
Texas Margin Tax (1)  7.7   10.9 
State income taxes (net of federal benefit) (2)  (11.3)  0.2 
Federal income taxes computed by applying the federal 
statutory rate to NBI of corporate entities
  (107.8)  1.2 
Federal benefit attributable to settlement of Liquidity Option (2)  (67.8)  – 
Provision for (benefit from) income taxes $(179.2) $12.3 
         
         
Effective income tax rate  (15.0)%  1.0%

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

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

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


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

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


Note 11.12.  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 September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended March 31,
 
 2019  2018  2019  2018  2020  2019 
BASIC EARNINGS PER UNIT                  
Net income attributable to limited partners $1,019.2  $1,313.2  $3,494.4  $2,887.7  $1,350.1  $1,260.5 
Undistributed earnings allocated and cash payments on phantom unit awards (1)  (6.1)  (6.2)  (21.3)  (15.5)
Earnings allocated to phantom unit awards (1)  (9.9)  (7.8)
Net income available to common unitholders $1,013.1  $1,307.0  $3,473.1  $2,872.2  $1,340.2  $1,252.7 
                        
Basic weighted-average number of common units outstanding  2,189.1   2,179.9   2,188.4   2,173.8   2,188.9   2,187.1 
                        
Basic earnings per unit $0.46  $0.60  $1.59  $1.32  $0.61  $0.57 
                        
DILUTED EARNINGS PER UNIT                        
Net income attributable to limited partners $1,019.2  $1,313.2  $3,494.4  $2,887.7  $1,350.1  $1,260.5 
                        
Diluted weighted-average number of units outstanding:                        
Distribution-bearing common units  2,189.1   2,179.9   2,188.4   2,173.8   2,188.9   2,187.1 
Phantom units (1)  13.2   10.6   13.1   10.6   15.1   12.4 
Total  2,202.3   2,190.5   2,201.5   2,184.4   2,204.0   2,199.5 
                        
Diluted earnings per unit $0.46  $0.60  $1.59  $1.32  $0.61  $0.57 

(1)Each phantom unit award includes a distribution equivalent right ("DER"), which entitles the recipient to receive cash payments equal to the product of the number of phantom unit awards and the cash distribution per unit paid to EPD’s common unitholders. Cash payments made in connection with DERs are nonforfeitable. As a result, the phantomPhantom units are considered participating securities for purposes of computing basic earnings per unit. See Note 13 for information regarding our phantom units.

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Note 12.13.  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 September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended March 31,
 
 2019  2018  2019  2018  2020  2019 
Equity-classified awards:                  
Phantom unit awards $34.7  $24.2  $99.6  $74.7  $36.2  $29.4 
Profits interest awards  2.5   1.2   8.1   3.8   2.9   2.6 
Liability-classified awards  0.1   0.1   0.1   0.3 
Total $37.3  $25.5  $107.8  $78.8  $39.1  $32.0 

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

PhantomSubject 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) once a defined vesting period expires, subject to customary forfeiture provisions..  The following table presents phantom unit award activity for the period indicated:

 
Number of
Units
  
Weighted-
Average Grant
Date Fair Value
per Unit (1)
  
Number of
Units
  
Weighted-
Average Grant
Date Fair Value
per Unit (1)
 
Phantom unit awards at December 31, 2018  10,333,277  $26.97 
Phantom unit awards at December 31, 2019  12,974,684  $27.21 
Granted (2)  6,851,920  $27.75   7,397,845  $25.72 
Vested  (3,810,666) $27.54   (4,204,938) $26.32 
Forfeited  (268,621) $27.21   (22,624) $26.92 
Phantom unit awards at September 30, 2019  13,105,910  $27.21 
Phantom unit awards at March 31, 2020  16,144,967  $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 20192020 was $190.2$190.3 million based on a grant date market price of EPD common units ranging from $27.75$24.98 to $29.29$25.76 per unit.  An estimated annual forfeiture rate of 3.0%2.4% was applied to these awards.

Each phantom unit award includes a DER,distribution equivalent right (“DER”), which entitles the recipientparticipant to receivenonforfeitable 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 EPD’sits common unitholders.  Cash payments made in connection with DERs are nonforfeitable and charged to partners’ equity when the phantom unit award is expected to result in the issuance of common units; otherwise, such amounts are expensed.

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

 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended March 31,
 
 2019  2018  2019  2018  2020  2019 
Cash payments made in connection with DERs $5.9  $4.6  $16.4  $13.2  $5.8  $4.5 
Total intrinsic value of phantom unit awards that vested during period  7.2   4.5   108.9   89.6   109.2   97.0 

TheFor the EPCO group of companies, the unrecognized compensation cost associated with phantom unit awards was $172.5$278.7 million at September 30, 2019,March 31, 2020, of which our share of thesuch cost is currently estimated to be $144.2$239.8 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 2.12.3 years.

Profits Interest Awards

EPCO has established five limited partnerships (referred to as “Employee Partnerships”) that serve as long-term incentive arrangements for key employees of EPCO by providing them a profits interest in one or more of the Employee Partnerships.  At September 30, 2019, our share of the total unrecognized compensation cost related to the Employee Partnerships was $27.3 million, which we expect to recognize over a weighted-average period of 3.4 years.

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Profits Interest Awards

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


Note 13.14.  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.

Swaptions
In January and July 2019, we sold options to be put into forward-starting swaps, or swaptions, if the market rate of interest fell below the strike rate of the option upon expiration of the derivative instrument.  The premiums we realized upon sale of the swaptions are reflected as a $13.3 million and $23.1 million reduction in interest expense for the three and nine months ended September 30, 2019, respectively.

Due to declining interest rates, the counterparties to the swaptions sold in July 2019 exercised their right to put us into 10 forward-starting swaps on September 30, 2019 having an aggregate notional value of $1.0 billion on September 30, 2019.  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 debt issuance.  Under the terms of the forward-starting swaps, we will pay to the counterparties (at the expected settlement dates of the instruments) amounts based on a 30-year fixed interest rate applied to the notional amount and receive from the counterparties an amount equal to a 30-year variable interest rate on the same notional amount.  On September 30, 2019, the weighted-average fixed interest rate of the 10 forward-starting swaps was 2.12%, which was 0.41% higher than the then applicable variable interest rate.  As a result, we incurred an unrealized, mark-to-market loss at inception totaling $94.9 million that is reflected as an increase in interest expense for the three and nine months ended September 30, 2019.  Prospectively, we will account for the forward-starting swaps as cash flow hedges, with any subsequent gains or losses on these derivative instruments reflected as a component of other comprehensive income and amortized to earnings (through interest expense) over the 30-year period of the associated future debt issuance.

Although we incurred a loss upon the exercise of these derivative instruments, we believe that the fixed interest rates that we will pay in connection with these forward-starting swaps are very favorable when compared to historical 30-year rates.   Settlement of amounts accrued under the ten forward-starting swaps, including any gains or losses incurred from changes in interest rates between now and the contractual settlement dates, will occur at their respective expiration dates in September 2020 and April 2021.

Forward-Starting Swaps
The following table summarizes our portfolio of 30-year forward-starting swaps at September 30, 2019,March 31, 2020, all of which are associated with the expected future issuance of senior notes.

Hedged Transaction
Number and Type
of Derivatives
Outstanding
Notional
Amount
Expected
Settlement
Date
Weighted-Average
Fixed Rate
Locked
Accounting
Treatment
Number and Type
of Derivatives
Outstanding
Notional
Amount
Expected
Settlement
Date
Weighted-Average
Fixed Rate
Locked
Accounting
Treatment
Future long-term debt offering1 forward-starting swap (1)$75.09/20202.39%Cash flow hedge1 forward-starting swap$75.04/20212.41%Cash flow hedge
Future long-term debt offering1 forward-starting swap (1)$75.04/20212.41%Cash flow hedge5 forward-starting swaps$500.04/20212.13%Cash flow hedge
Future long-term debt offering5 forward-starting swaps (2)$500.09/20202.12%Cash flow hedge2 forward-starting swaps (1)$150.02/20221.72%Cash flow hedge
Future long-term debt offering5 forward-starting swaps (2)$500.04/20212.13%Cash flow hedge1 forward starting swap (1)$100.04/20211.46%Cash flow hedge
Future long-term debt offering2 forward starting swaps (1)$150.02/20221.48%Cash flow hedge
Future long-term debt offering2 forward starting swaps (1)$100.02/20220.95%Cash flow hedge

(1)These swaps were entered into in May 2019.
(2)These swaps were entered into in September 2019 as a result ofduring the swaption exercise.three months ended March 31, 2020.

In total, the notional amount of forward-starting swaps outstanding at September 30, 2019March 31, 2020 was $1.15$1.08 billion.  The weighted-average fixed interest rate of these derivative instruments is 2.16%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.

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Commodity Hedging Activities

The prices of natural gas, NGLs, crude oil, petrochemicals and refined products are subject to fluctuations in response to changes in supply and demand, market conditions and a variety of additional factors that are beyond our control.  In order to manage such price risks, we enter into commodity derivative instruments such as physical forward contracts, futures contracts, fixed-for-float swaps and basis swaps.

At September 30, 2019,March 31, 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 natural gas processing margins and (iii) hedging the fair value of commodity products held in inventory.inventory and (iii) hedging natural gas processing margins.  

The following table summarizes our portfolio of commodity derivative instruments outstanding at September 30, 2019March 31, 2020 (volume measures as noted):

Volume (1)AccountingVolume (1)Accounting
Derivative Purpose
Current (2)
Long-Term (2)
Treatment
Current (2)
Long-Term (2)
Treatment
Derivatives designated as hedging instruments:      
Natural gas processing:      
Forecasted natural gas purchases for plant thermal reduction (billion cubic feet (“Bcf”))15.2n/aCash flow hedge11.9n/aCash flow hedge
Forecasted sales of NGLs (million barrels (“MMBbls”))
1.8n/aCash flow hedge
Octane enhancement:      
Forecasted purchase of NGLs (MMBbls)1.0n/aCash flow hedge0.7n/aCash flow hedge
Forecasted sales of octane enhancement products (MMBbls)8.11.6Cash flow hedge13.6n/aCash flow hedge
Natural gas marketing:      
Forecasted purchase of natural gas (Bcf)4.5n/aCash flow hedge
Natural gas storage inventory management activities (Bcf)3.2n/aFair value hedge4.4n/aFair value hedge
NGL marketing:      
Forecasted purchases of NGLs and related hydrocarbon products (MMBbls)100.01.5Cash flow hedge126.30.4Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products (MMBbls)121.71.2Cash flow hedge140.02.2Cash flow hedge
NGLs inventory management activities (MMBbls)0.3n/aFair value hedge0.8n/aFair value hedge
Refined products marketing:      
Forecasted purchases of refined products (MMBbls)0.9n/aCash flow hedge5.1n/aCash flow hedge
Forecasted sales of refined products (MMBbls)0.9n/aCash flow hedge6.8n/aCash flow hedge
Refined products inventory management activities (MMBbls)0.5n/aFair value hedge
Crude oil marketing:      
Forecasted purchases of crude oil (MMBbls)10.4n/aCash flow hedge24.5n/aCash flow hedge
Forecasted sales of crude oil (MMBbls)13.8n/aCash flow hedge31.4n/aCash flow hedge
Propylene marketing:      
Forecasted sales of NGLs for propylene marketing activities (MMBbls)0.3n/aCash flow hedge0.6n/aCash flow hedge
Commercial energy:   
Forecasted purchases of power related to asset operations (terawatt hours (“TWh”))0.2n/aCash flow hedge
Derivatives not designated as hedging instruments:      
Natural gas risk management activities (Bcf) (3)38.20.6Mark-to-market54.50.3Mark-to-market
NGL risk management activities (MMBbls) (3)2.4n/aMark-to-market15.7n/aMark-to-market
Refined products risk management activities (MMBbls) (3)7.6n/aMark-to-market5.1n/aMark-to-market
Crude oil risk management activities (MMBbls) (3)22.26.1Mark-to-market33.99.0Mark-to-market
Commercial energy risk management activities (TWh) (3)0.1n/aMark-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 JanuaryDecember 2021, December 20192020 and December 2022, respectively.
(3)Reflects the use of derivative instruments to manage risks associated with transportation, processing, storage assets and storage assets.end use power requirements.

The carrying amount of our inventories subject to fair value hedges was $21.1$28.1 million and $50.2$31.7 million at September 30, 2019March 31, 2020 and December 31, 2018,2019, respectively.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Tabular Presentation of Fair Value Amounts, and Gains and Losses on
  Derivative Instruments and Related Hedged Items

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



Asset Derivatives Liability DerivativesAsset Derivatives Liability Derivatives
September 30, 2019 December 31, 2018 September 30, 2019 December 31, 2018March 31, 2020 December 31, 2019 March 31, 2020 December 31, 2019
Balance
Sheet
Location
Fair
Value
 
Balance
Sheet
Location
Fair
Value
 
Balance
Sheet
Location
Fair
Value
 
Balance
Sheet
Location
Fair
Value
Balance
Sheet
Location
Fair
Value
 
Balance
Sheet
Location
Fair
Value
 
Balance
Sheet
Location
Fair
Value
 
Balance
Sheet
Location
Fair
Value
Derivatives designated as hedging instruments                              
Interest rate derivativesCurrent assets$– Current assets$– 
Current
liabilities
$11.8 
Current
liabilities
$–Current assets$– Current assets$– 
Current
liabilities
$– 
Current
liabilities
$6.7
Interest rate derivativesOther assets – Other assets – Other liabilities 11.9 Other liabilities –Other assets – Other assets – Other liabilities 258.3 Other liabilities 6.8
Total interest rate derivatives  –   –   23.7   –  –   –   258.3   13.5
Commodity derivativesCurrent assets 149.3 Current assets 138.5 
Current
liabilities
 139.2 
Current
liabilities
 115.0Current assets 310.7 Current assets 116.5 
Current
liabilities
 244.6 
Current
liabilities
 107.1
Commodity derivativesOther assets 5.6 Other assets 5.6 Other liabilities 6.8 Other liabilities 11.1Other assets – Other assets – Other liabilities – Other liabilities –
Total commodity derivatives  154.9   144.1   146.0   126.1  310.7   116.5   244.6   107.1
Total derivatives designated as hedging instruments $154.9  $144.1  $169.7  $126.1 $310.7  $116.5  $502.9  $120.6
                              
Derivatives not designated as hedging instruments                              
Interest rate derivativesCurrent assets$– Current assets$– 
Current
liabilities
$47.2 
Current
liabilities
$–
Interest rate derivativesOther assets – Other assets – Other liabilities 47.7 Other liabilities –
Total interest rate derivatives  –   –   94.9   –
Commodity derivativesCurrent assets 16.7 Current assets 15.9 
Current
liabilities
 4.2 
Current
liabilities
 33.2Current assets$55.1 Current assets$10.7 
Current
liabilities
$24.6 
Current
liabilities
$8.6
Commodity derivativesOther assets 1.0 Other assets 1.9 Other liabilities 0.3 Other liabilities 3.1Other assets 5.1 Other assets 0.6 Other liabilities 3.0 Other liabilities 0.5
Total commodity derivatives  17.7   17.8   4.5   36.3  60.2   11.3   27.6   9.1
Total derivatives not designated as hedging instruments $17.7  $17.8  $99.4  $36.3 $60.2  $11.3  $27.6  $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 Offsetting of Financial Assets and Derivative Assets 
Gross
Amounts of
Recognized
Assets
 
Gross
Amounts
Offset in the
Balance Sheet
 
Amounts
of Assets
Presented
in the
Balance Sheet
 
Gross Amounts Not Offset
in the Balance Sheet
 
Amounts That
Would Have
Been Presented
On Net Basis
 
Gross
Amounts of
Recognized
Assets
 
Gross
Amounts
Offset in the
Balance Sheet
 
Amounts
of Assets
Presented
in the
Balance Sheet
 
Gross Amounts Not Offset
in the Balance Sheet
 
Amounts That
Would Have
Been Presented
On Net Basis
 
Financial
Instruments
 
Cash
Collateral
Received
 
Cash
Collateral
Paid
 
Financial
Instruments
 
Cash
Collateral
Received
 
Cash
Collateral
Paid
 
(i) (ii) (iii) = (i) – (ii) (iv) (v) = (iii) + (iv) (i) (ii) (iii) = (i) – (ii) (iv) (v) = (iii) + (iv) 
As of September 30, 2019:                     
As of March 31, 2020:                     
Commodity derivatives $172.6  $–  $172.6  $(149.0) $–  $(22.4) $1.2  $370.9  $–  $370.9  $(267.0) $–  $(100.6) $3.3 
As of December 31, 2018:                            
As of December 31, 2019:                            
Commodity derivatives $161.9  $–  $161.9  $(158.6) $–  $–  $3.3  $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 March 31, 2020:                     
Interest rate derivatives $258.3  $–  $258.3  $–  $–  $–  $258.3 
Commodity derivatives  272.2   –   272.2   (267.0)  –   –   5.2 
As of December 31, 2019:                            
Interest rate derivatives $13.5  $–  $13.5  $–  $–  $–  $13.5 
Commodity derivatives  116.2   –   116.2   (115.3)  –   –   0.9 
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 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 September 30, 2019:                     
Interest rate derivatives $118.6  $–  $118.6  $–  $–  $–  $118.6 
Commodity derivatives  150.5   –   150.5   (149.0)  –   0.3   1.8 
As of December 31, 2018:                            
Commodity derivatives $162.4  $–  $162.4  $(158.6) $–  $(2.3) $1.5 

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

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

Derivatives in Fair Value
Hedging Relationships
 
Location
 
Gain (Loss) Recognized in
Income on Derivative
 Location 
Gain (Loss) Recognized in
Income on Derivative
 
   
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
    
For the Three Months
Ended March 31,
 
  2019  2018  2019  2018   2020  2019 
Interest rate derivativesInterest expense $–  $–  $–  $1.3 
Commodity derivativesRevenue  (0.4)  (1.4)  (2.0)  3.2 Revenue $3.9  $(8.5)
Total  $(0.4) $(1.4) $(2.0) $4.5   $3.9  $(8.5)

Derivatives in Fair Value
Hedging Relationships
 
Location
 
Gain (Loss) Recognized in
Income on Hedged Item
 Location 
Gain (Loss) Recognized in
Income on Hedged Item
 
   
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
    
For the Three Months
Ended March 31,
 
  2019  2018  2019  2018   2020  2019 
Interest rate derivativesInterest expense $–  $–  $–  $(1.4)
Commodity derivativesRevenue  2.4   3.7   8.7   1.9 Revenue $(8.2) $9.9 
Total  $2.4  $3.7  $8.7  $0.5   $(8.2) $9.9 

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 September 30,
  
For the Nine Months
Ended September 30,
 
  2019  2018  2019  2018 
Interest rate derivatives $(18.6) $6.1  $(23.8) $20.7 
Commodity derivatives – Revenue (1)  73.5   (145.5)  71.1   (156.7)
Commodity derivatives – Operating costs and expenses (1)  (1.2)  (0.3)  (12.5)  0.7 
Total $53.7  $(139.7) $34.8  $(135.3)

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

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

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Derivatives in Cash Flow
Hedging Relationships
Location 
Gain (Loss) Reclassified from
Accumulated Other Comprehensive Income (Loss) to Income
 Location 
Gain (Loss) Reclassified from
Accumulated Other
Comprehensive Income (Loss)
to Income
 
   
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
    
For the Three Months
Ended March 31,
 
  2019  2018  2019  2018   2020  2019 
Interest rate derivativesInterest expense $(9.4) $(9.1) $(27.8) $(29.0)Interest expense $(23.5) $(9.2)
Commodity derivativesRevenue  93.6   53.9   161.4   28.5 Revenue  154.4   65.3 
Commodity derivativesOperating costs and expenses  (2.1)  (0.4)  (9.4)  0.3 Operating costs and expenses  1.2   (7.0)
Total  $82.1  $44.4  $124.2  $(0.2)  $132.1  $49.1 

Over the next twelve months, we expect to reclassify $39.1$39.8 million of losses attributable to interest rate derivative instruments from accumulated other comprehensive loss to earnings as an increase in interest expense.  Likewise, we expect to reclassify $66.3$363.1 million of gains attributable to commodity derivative instruments from accumulated other comprehensive income to earnings, $68.1$366.7 million as an increase in revenue and $1.8$3.6 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
 Location 
Gain (Loss) Recognized in
Income on Derivative
 
   
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
    
For the Three Months
Ended March 31,
 
  2019  2018  2019  2018   2020  2019 
Interest rate derivativesInterest expense $(94.9) $–  $(94.9) $– 
Commodity derivativesRevenue  21.8   21.8   96.7   (538.0)Revenue $63.5  $95.1 
Commodity derivativesOperating costs and expenses  (1.6)  (2.7)  (6.3)  (4.2)Operating costs and expenses  (0.1)  0.1 
Total  $(74.7) $19.1  $(4.5) $(542.2)  $63.4  $95.2 

The $4.5$63.4 million lossgain recognized for the ninethree months ended September 30, 2019March 31, 2020 (as noted in the preceding table) from derivatives not designated as hedging instruments consists of (i) $0.7$20.6 million of realized lossesgains and $91.1$42.8 million of net unrealized mark-to-market gains attributable to commodity derivatives and (ii) $94.9 million of unrealized mark-to-market losses attributable to interest rate derivatives.

In total and inclusive of both fair value hedges and derivatives not designated as hedging instruments, we recognized a net $2.0 million mark-to-market loss for the nine months ended September 30, 2019 consisting of (i) $92.9 million of net unrealized mark-to-market gains attributable to commodity derivatives and (ii) $94.9 million of unrealized mark-to-market losses attributable to interest rate 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.
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


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

 
At September 30, 2019
Fair Value Measurements Using
     
At March 31, 2020
Fair Value Measurements Using
    
 
Quoted Prices
in Active
Markets for
Identical Assets
and Liabilities
(Level 1)
  
Significant
Other
Observable
Inputs
(Level 2)
  
Significant
Unobservable
Inputs
(Level 3)
  Total  
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 $54.0  $365.4  $14.5  $433.9  $764.5  $938.1  $14.3  $1,716.9 
Impact of CME Rule 814  (44.8)  (206.3)  (10.2)  (261.3)  (723.9)  (609.7)  (12.4)  (1,346.0)
Total commodity derivatives  9.2   159.1   4.3   172.6   40.6   328.4   1.9   370.9 
Total $9.2  $159.1  $4.3  $172.6  $40.6  $328.4  $1.9  $370.9 
                                
Financial liabilities:                                
Liquidity Option Agreement (see Note 15) $–  $–  $513.1  $513.1 
Interest rate derivatives  –   118.6   –   118.6  $–  $258.3  $–  $258.3 
Commodity derivatives:                                
Value before application of CME Rule 814  39.8   268.3   47.9   356.0   531.1   912.9   5.3   1,449.3 
Impact of CME Rule 814  (31.0)  (138.5)  (36.0)  (205.5)  (490.9)  (685.5)  (0.7)  (1,177.1)
Total commodity derivatives  8.8   129.8   11.9   150.5   40.2   227.4   4.6   272.2 
Total $8.8  $248.4  $525.0  $782.2  $40.2  $485.7  $4.6  $530.5 

 
At December 31, 2018
Fair Value Measurements Using
     
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  
Quoted Prices
in Active
Markets for
Identical Assets
and Liabilities
(Level 1)
  
Significant
Other
Observable
Inputs
(Level 2)
  
Significant
Unobservable
Inputs
(Level 3)
  Total 
Financial assets:                        
Commodity derivatives:                        
Value before application of CME Rule 814 $172.3  $282.4  $2.2  $456.9  $53.4  $343.7  $0.1  $397.2 
Impact of CME Rule 814  (134.8)  (159.3)  (0.9)  (295.0)  (47.0)  (222.4)  –   (269.4)
Total commodity derivatives  37.5   123.1   1.3   161.9   6.4   121.3   0.1   127.8 
Total $37.5  $123.1  $1.3  $161.9  $6.4  $121.3  $0.1  $127.8 
                                
Financial liabilities:                                
Liquidity Option Agreement (see Note 15) $–  $–  $390.0  $390.0 
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  85.5   291.2   21.4   398.1   88.1   273.6   0.3   362.0 
Impact of CME Rule 814  (48.6)  (172.9)  (14.2)  (235.7)  (81.9)  (163.9)  –   (245.8)
Total commodity derivatives  36.9   118.3   7.2   162.4   6.2   109.7   0.3   116.2 
Total $36.9  $118.3  $397.2  $552.4  $6.2  $123.2  $509.9  $639.3 

In the aggregate, the fair value of our commodity hedging portfolios at September 30, 2019March 31, 2020 was a net derivative asset of $77.9267.6 million prior to the impact of CME Rule 814.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


The followingtable provides quantitative information regarding our recurring Level 3 fair value measurements for commodity derivatives
Financial assets and liabilities recorded on the balance sheet at September 30, 2019:

  Fair Value      
  
Financial
Assets
  
Financial
Liabilities
 
Valuation
Techniques
Unobservable
Input
Range
Commodity derivatives – Crude oil $0.5  $0.2 Discounted cash flowForward commodity prices$54.11-$54.78/barrel
Commodity derivatives – Propane  1.2   3.7 Discounted cash flowForward commodity prices$0.43-$0.49/gallon
Commodity derivatives – Natural gasoline  –   4.3 Discounted cash flowForward commodity prices$0.96-$1.04/gallon
Commodity derivatives – Ethane  1.5   1.3 Discounted cash flowForward commodity prices$0.18-$0.19/gallon
Commodity derivatives – Normal Butane  0.5   2.2 Discounted cash flowForward commodity prices$0.48-$0.56/gallon
Commodity derivatives – Isobutane  0.6   0.2 Discounted cash flowForward commodity prices$0.53-$0.64/gallon
   Total $4.3  $11.9      

With respect to commodity derivatives, we believe forward commodity prices are the mostMarch 31, 2020 using significant unobservable inputs in determining our Level 3 recurring fair value measurements at September 30, 2019.  In general, changes in(Level 3) are not material to the priceUnaudited Condensed Consolidated Financial Statements. Refer to Note 8 for discussion of the underlying commodity increases or decreasessettlement of the fair value of a commodity derivative depending on whetherLiquidity Option in March 2020 and Note 11 for the derivative was purchased or sold.  We generally expect changes in the fair value of our derivative instrumentsincome tax impact related to be offset by corresponding changes in the fair value of our hedged exposures.this transaction.

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

 test
  
For the Nine Months
Ended September 30,
 
  testLocation 2019  2018 
Financial asset (liability) balance, net, January 1  $(395.9) $(332.7)
Total gains (losses) included in:         
Net income (1)Revenue  3.1   (0.5)
Net incomeOther expense, net  (57.8)  (7.5)
Other comprehensive incomeCommodity derivative instruments – changes in fair value of cash flow hedges  4.0   – 
Settlements (1)Revenue  (0.1)  (1.2)
Transfers out of Level 3   (0.2)  – 
Financial asset (liability) balance, net, March 31   (446.9)  (341.9)
Total gains (losses) included in:         
Net income (1)Revenue  (0.1)  1.3 
Net incomeOther expense, net  (26.6)  (8.9)
Other comprehensive incomeCommodity derivative instruments – changes in fair value of cash flow hedges  (2.9)  – 
Settlements (1)Revenue  (3.1)  0.5 
Transfers out of Level 3   –   – 
Financial asset (liability) balance, net, June 30   (479.6)  (349.0)
Total gains (losses) included in:         
Net income (1)Revenue  0.8   (0.2)
Net incomeOther expense, net  (38.7)  (18.5)
Other comprehensive incomeCommodity derivative instruments – changes in fair value of cash flow hedges  (3.2)  2.8 
Settlements (1)Revenue  –   (1.3)
Transfers out of Level 3   –   – 
Financial asset (liability) balance, net, September 30  $(520.7) $(366.2)

(1)
There were $0.8 million and $0.6 million of unrealized gains included in these amounts for the three and nine months ended September 30, 2019, respectively.  There were unrealized losses of $1.5 million and $1.4 million, respectively, included in these amounts for the three and nine months ended September 30, 2018.

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Nonrecurring Fair Value Measurements

Non-cash asset impairment charges for the ninethree months ended September 30, 2019March 31, 2020 were $51.3$1.6 million compared to $21.4$4.8 million for the ninethree months ended September 30, 2018.March 31, 2019. Charges for 20192020 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 $31.01$28.77 billion and $25.97$30.37 billion at September 30, 2019March 31, 2020 and December 31, 2018,2019, respectively.  The aggregate carrying value of these debt obligations was $27.95$29.65 billion and $26.15$27.15 billion at September 30, 2019March 31, 2020 and December 31, 2018,2019, 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 14.15.  Related Party Transactions

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

 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended March 31,
 
 2019  2018  2019  2018  2020  2019 
Revenues – related parties:                  
Unconsolidated affiliates $15.6  $14.2  $53.7  $94.5  $16.0  $12.3 
Costs and expenses – related parties:                        
EPCO and its privately held affiliates $297.8  $285.9  $837.9  $802.8  $286.0  $272.9 
Unconsolidated affiliates  94.7   110.0   313.3   351.4   71.5   123.3 
Total $392.5  $395.9  $1,151.2  $1,154.2  $357.5  $396.2 

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

 
September 30,
2019
  
December 31,
2018
  
March 31,
2020
  
December 31,
2019
 
Accounts receivable - related parties:            
Unconsolidated affiliates $2.0  $3.5  $1.9  $2.5 
                
Accounts payable - related parties:                
EPCO and its privately held affiliates $106.6  $116.3  $59.8  $143.7 
Unconsolidated affiliates  18.9   23.9   9.6   18.6 
Total $125.5  $140.2  $69.4  $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.
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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.  

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At September 30, 2019,March 31, 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
Percentage of
Total Units
Outstanding
698,313,13731.9%
701,956,85232.1%

Of the total number of units held by EPCO and its privately held affiliates, 108,222,618 have been pledged as security under the credit facilities of EPCO and its privately held affiliates at September 30, 2019.March 31, 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 ninethree months ended September 30,March 31, 2020 and 2019, and 2018, we paid EPCO and its privately held affiliates cash distributions totaling $893.1$302.8 million and $867.4$296.0 million, respectively.

From time-to-time, EPCO and its privately held affiliates elect to purchase additional common units under EPD’s DRIP and ATM program.  During the nine months ended September 30, 2019, privately held affiliates of EPCO reinvested $21.6 million through the DRIP.  See Note 8 for additional information regarding the DRIP.

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


 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended March 31,
 
 2019  2018  2019  2018  2020  2019 
Operating costs and expenses $259.3  $246.6  $732.0  $697.6  $251.2  $239.1 
General and administrative expenses  34.2   35.0   92.9   92.6   30.5   29.3 
Total costs and expenses $293.5  $281.6  $824.9  $790.2  $281.7  $268.4 

We lease office space from privately held affiliates of EPCO.  The rental rates in these lease agreements approximate market rates.  For the three and nine months ended September 30,March 31, 2020 and 2019,, we recognized $3.83.4 million and $11.13.8 million, respectively, of related party operating lease expense in connection with these office space leases.For the three and nine months ended September 30, 2018, we recognized $3.8 million and $10.7million, respectively, of related party operating lease expense for these leases.  



Note 15.16.  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.

Our accruals for litigation contingencies were $0.5$0.2 million at September 30, 2019March 31, 2020 and December 31, 20182019, and recorded in our Unaudited Condensed Consolidated Balance Sheets as a component of “Other current liabilities.”  
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Energy Transfer Matter
In connection with a proposed pipeline project, we and ETP Energy Transfer Partners, L.P. (“ETP”) signed a non-binding letter of intent in April 2011 that disclaimed any partnership or joint venture related to such project absent executed definitive documents and board approvals of the respective companies.  Definitive agreements were never executed and board approval was never obtained for the potential pipeline project.  In August 2011, the proposed pipeline project was cancelled due to a lack of customer support.

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

We filed our Brief of the Appellant in the Court of Appeals for the Fifth District of Dallas, Texas on March 30, 2015 and ETP filed its Brief of Appellees on June 29, 2015.  We filed our Reply Brief of Appellant on September 18, 2015.  Oral argument was conducted on April 20, 2016, and the case was then submitted to the Court of Appeals for its consideration.ETP’s favor, Enterprise appealed this judgment.  On July 18, 2017, a panel of the Dallas Court of Appeals issued a unanimous opinion reversing the trial court’s judgment as to all of ETP’s claims against us,Enterprise and rendering judgment that ETP take nothing on those claims, and affirming our counterclaim against ETP of $0.8 million, plus interest.  On August 31, 2017,claims.  ETP filed a motion for rehearing before the Dallas Court of Appeals, which was denied on September 13, 2017.  On December 27, 2017, ETP filed its Petition for Review with the Supreme Court of Texas and, we filed our Response to the Petition for Review on February 26, 2018.   On June 8, 2018,January 31, 2020, the Supreme Court of Texas requested thatissued a unanimous opinion affirming the parties file briefs onjudgment of the merits, and the parties filed their respective submittals.Dallas Court of Appeals in Enterprise’s favor.  On June 28, 2019,March 6, 2020, the Supreme Court of Texas requested oral argument, which was held on October 8, 2019.

We have not recordedissued its Mandate to the Trial Court of Dallas County, bringing this lawsuit and the resulting appeal to a provision for this matter as management continues to believe that payment of damages by us in this case is not probable. We continue to monitor developments involving this matter.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”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, (“OPD”), to complete the construction and installation of the PDH facility.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.

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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 $28.20$29.90 billion and $26.42$27.88 billion at September 30, 2019March 31, 2020 and December 31, 2018,2019, respectively.  See Note 7 for additional information regarding our scheduled future maturities of debt principal.

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Lease Accounting Matters
The following table presents information regarding our operating leases where we are the lessee at September 30, 2019:March 31, 2020:

Asset Category
ROU
Asset
Carrying
Value (1)
 
Lease
Liability Carrying
    Value (2)
 
Weighted-
Average
Remaining
Term
 
Weighted-
Average
Discount
Rate (3)
ROU
Asset
Carrying
Value (1)
 
Lease
Liability Carrying
    Value (2)
 
Weighted-
Average
Remaining
Term
 
Weighted-
Average
Discount
Rate (3)
Storage and pipeline facilities$141.0 $141.6 16 years 4.3%$137.0 $137.5 16 years 4.3%
Transportation equipment 
            54.2
              56.6 4 years 3.4% 
            45.6
              46.3 3 years 3.5%
Office and warehouse space 
            24.3
              22.9 2 years 3.5% 
            176.3
              179.8 17 years 3.2%
Total$ 219.5 $221.1    $ 358.9 $363.6    

(1)ROURight-of-use (“ROU”) asset amounts are a component of “Other assets” on our consolidated balance sheet.Unaudited Condensed Consolidated Balance Sheet.
(2)At September 30, 2019,March 31, 2020, lease liabilities of $39.2$31.0 million and $181.9$332.6 million were included within “Other current liabilities” and “Other liabilities,” respectively.
(3)The discount rate for each category of assets represents the weighted average of either (i) the implicit rate applicable to the underlying leases (where determinable) or (ii) our incremental borrowing rate adjusted for collateralization (if the implicit rate is not determinable).  In general, the discount rates are based on either (i) information available at the lease commencement date or (ii) January 1, 2019 for leases existing at the adoption date for ASC 842.

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

 
For the Three Months
Ended March 31,
 
 
For the Three Months
Ended September 30, 2019
  
For the Nine Months
Ended September 30, 2019
  2020  2019 
Long-term operating leases:            
Fixed lease expense $12.8  $39.3 
Fixed lease expense:      
Non-cash lease expense (amortization of ROU assets) $10.0  $11.0 
Related accretion expense on lease liability balances  3.4   2.4 
Total fixed lease expense  13.4   13.4 
Variable lease expense  1.6   4.5   0.2   1.8 
Subtotal operating lease expense  14.4   43.8   13.6   15.2 
Short-term lease expense  12.4   35.9 
Short-term operating leases  13.2   11.8 
Total operating lease expense $26.8  $79.7  $26.8  $27.0 

In total, operating lease expense was $26.8 million and $27.6 million for the three months ended September 30, 2019 and 2018, respectively.  During the nine months ended September 30, 2019 and 2018 operating lease expense was $79.7 million and $79.0 million, respectively. Operating lease expense represents less than 1% of “Operating costs and expenses” as presented on our consolidated statements of operations.  Fixed lease expense is charged to earnings on a straight-line basis over the contractual term, with any variable lease payments expensed as incurred.  Short-term operating lease expense is expensed as incurred.  Cash paid for operating lease liabilities recorded on our balance sheet was $10.1 million and $9.9 million for the three months ended March 31, 2020 and 2019, respectively.

We recognized $246.1 million in ROU assets and lease liabilities for long-termdo not have any significant operating or direct financing leases at January 1, 2019 in connection withwhere we are the adoption of ASC 842.  These amounts represented less than 1% of our total consolidated assets and liabilities, respectively, at the adoption date. On an undiscounted basis, our long-termlessor.  Our operating lease income for the three months ended March 31, 2020 and 2019 was $3.5 million and $4.8 million, respectively.  We do not have any sales-type leases.

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

Purchase Obligations
We have contractual future product purchase commitments for natural gas, NGLs, crude oil, petrochemicals and refined products.  These commitments represent enforceable and legally binding agreements as of the reporting date.  Our product purchase commitments at March 31, 2020 declined by an estimated $10.45 billion when compared to those reported in our 2019 Form 10-K primarily due to lower NGL and crude oil prices in the first quarter of 2020.  At March 31, 2020, our estimated long-term product purchase obligations aggregated to $314.4 million at January 1, 2019.totaled $10.12 billion after reflecting the decline in commodity prices, agreements added during the first three months of 2020 and those commitments that expired during the year.  At December 31, 2019, our estimated long-term product purchase obligations totaled $20.57 billion.

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Under ASC 842, lessors classify leases as either operating, direct financing or sales-type.  We do not have any significant operating or direct financing leases.  Our operating lease income for the three and nine months ended September 30, 2019 was $3.5 million and $10.7 million, respectively, which represented less than 1%Settlement of our consolidated revenues.  We do not have any sales-type leases.Liquidity Option

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

Purchase Obligations
During the nine months ended September 30, 2019, we entered into additional long-term purchase commitmentsSee Note 8 for NGLs with third-party suppliers.  On a combined basis, these new agreements increased our estimated long-term purchase obligations by $3.6 billion, with $1.3 billion committed over the next five years and $2.3 billion thereafter.  At September 30, 2019, our estimated long-term purchase obligations totaled $12.7 billion after reflecting the agreements added during the first nine months of 2019 and those commitments that expired during the year.  At December 31, 2018, our estimated long-term purchase obligations totaled $10.8 billion.

Liquidity Option Agreement

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

The carrying value of the Liquidity Option Agreement, which is a component of “Other long-term liabilities” on our Unaudited Condensed Consolidated Balance Sheet, was $513.1 million and $390.0 million at September 30, 2019 and December 31, 2018, respectively.  The fair value of the Liquidity Option, at any measurement date, represents the present value of estimated federal and state income tax payments that we believe a market participant would incur on the future taxable income of OTA. We expect that OTA’s taxable income would, in turn, be based on an allocation of our partnership’s taxable income to the common units held by OTA and reflect certain tax planning strategies we believe could be employed.

Changes in the fair value of the Liquidity Option are recognized in earnings as a component of other income (expense) on our Unaudited Condensed Statements of Consolidated Operations. Results for the three and nine months ended September 30, 2019 include $38.7 million and $123.1 million, respectively, of non-cash expense attributable to the Liquidity Option. Expense recognized during 2019 is primarily due to a decrease in the applicable midstream industry weighted-average cost of capital, which is used as the discount factor in determining the present value of the liability, since December 31, 2018.  The remainder of the inputs to the valuation model have not materially changed since those reported under Note 17 of the 2018 Form 10-K.March 5, 2020.

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Note 16.17.  Supplemental Cash Flow Information

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

 
For the Nine Months
Ended September 30,
  
For the Three Months
Ended March 31,
 
 2019  2018  2020  2019 
Decrease (increase) in:            
Accounts receivable – trade $(578.0) $123.1  $1,702.4  $(653.0)
Accounts receivable – related parties  1.6   (0.3)  0.5   2.0 
Inventories  (44.2)  (474.2)  507.7   (84.5)
Prepaid and other current assets  (305.3)  (124.7)  1,001.7   (223.4)
Other assets  (18.3)  (9.9)  22.7   (13.2)
Increase (decrease) in:                
Accounts payable – trade  (55.4)  213.1   22.4   (35.7)
Accounts payable – related parties  31.0   47.4   (93.0)  (7.9)
Accrued product payables  666.6   356.9   (1,743.1)  673.0 
Accrued interest  (158.4)  (167.5)  (193.4)  (178.7)
Other current liabilities  133.6   (261.7)  (896.4)  (8.4)
Other liabilities  (82.2)  35.9   10.2   (30.0)
Net effect of changes in operating accounts $(409.0) $(261.9) $341.7  $(559.8)

We incurred liabilities for construction in progress that had not been paid at September 30, 2019March 31, 2020 and December 31, 20182019 of $490.5$394.0 million and $567.6$432.0 million, respectively.  Such amounts are not included under the caption “Capital expenditures” on the Unaudited Condensed Statements of Consolidated Cash Flows.

Acquisition of Delaware Processing

In March 2018, we acquired the remaining 50% member interest in our Delaware Basin Gas Processing LLC (“Delaware Processing”) joint venture for $150.6 million.  As a result, Delaware Processing became our wholly-owned consolidated subsidiary.  Upon acquisition of the remaining 50% member interest, our existing equity investment was remeasured to fair value resulting in the recognition of a non-cash $39.4 million gain during 2018.


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Note 17.18.  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
September 30, 2019March 31, 2020

 EPO and Subsidiaries           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
  
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 $1,004.2  $235.7  $(32.1) $1,207.8  $–  $–  $1,207.8  $1,897.3  $230.2  $(12.0) $2,115.5  $0.1  $–  $2,115.6 
Accounts receivable – trade, net  1,223.0   3,039.4   (0.7)  4,261.7   –   –   4,261.7   1,026.1   2,268.9   (1.2)  3,293.8   –   –   3,293.8 
Accounts receivable – related parties  190.8   905.5   (1,086.2)  10.1   –   (8.1)  2.0   235.3   871.8   (924.3)  182.8   –   (180.9)  1.9 
Inventories  1,078.5   566.5   (0.3)  1,644.7   –   –   1,644.7   1,080.8   458.5   (0.5)  1,538.8   –   –   1,538.8 
Derivative assets  138.1   27.9   –   166.0   –   –   166.0   324.0   61.8   (20.0)  365.8   –   –   365.8 
Prepaid and other current assets  275.0   402.4   (46.2)  631.2   0.3   0.1   631.6   217.3   249.7   (64.8)  402.2   0.8   0.2   403.2 
Total current assets  3,909.6   5,177.4   (1,165.5)  7,921.5   0.3   (8.0)  7,913.8   4,780.8   4,140.9   (1,022.8)  7,898.9   0.9   (180.7)  7,719.1 
Property, plant and equipment, net  6,285.6   34,522.8   (45.1)  40,763.3   –   –   40,763.3   6,537.2   35,664.4   (42.5)  42,159.1   –   –   42,159.1 
Investments in unconsolidated affiliates  44,827.7   4,174.0   (46,340.8)  2,660.9   25,016.0   (25,016.0)  2,660.9   46,002.5   4,781.6   (48,175.6)  2,608.5   25,229.5   (25,229.5)  2,608.5 
Intangible assets, net  642.0   2,860.6   (13.2)  3,489.4   –   –   3,489.4   631.9   2,794.9   (17.4)  3,409.4   –   –   3,409.4 
Goodwill  459.5   5,285.7   –   5,745.2   –   –   5,745.2   459.5   5,285.7   –   5,745.2   –   –   5,745.2 
Other assets  373.5   290.7   (222.4)  441.8   0.9   –   442.7   553.0   313.9   (243.8)  623.1   0.9   –   624.0 
Total assets $56,497.9  $52,311.2  $(47,787.0) $61,022.1  $25,017.2  $(25,024.0) $61,015.3  $58,964.9  $52,981.4  $(49,502.1) $62,444.2  $25,231.3  $(25,410.2) $62,265.3 
                                                        
LIABILITIES AND EQUITY                                                        
Current liabilities:                                                        
Current maturities of debt $2,300.0  $–  $–  $2,300.0  $–  $–  $2,300.0  $1,750.0  $–  $–  $1,750.0  $–  $–  $1,750.0 
Accounts payable – trade  297.1   792.8   (32.1)  1,057.8   –   –   1,057.8   157.7   769.9   (11.8)  915.8   –   –   915.8 
Accounts payable – related parties  1,042.3   182.7   (1,099.5)  125.5   8.1   (8.1)  125.5   895.0   111.9   (937.5)  69.4   180.9   (180.9)  69.4 
Accrued product payables  1,490.3   2,709.6   (1.1)  4,198.8   –   –   4,198.8   1,379.2   1,788.7   (1.6)  3,166.3   –   –   3,166.3 
Accrued interest  237.1   3.2   (3.1)  237.2   –   –   237.2   238.2   3.2   (3.1)  238.3   –   –   238.3 
Derivative liabilities  194.3   8.1   –   202.4   –   –   202.4   208.1   81.1   (20.0)  269.2   –   –   269.2 
Other current liabilities  121.3   469.5   (43.0)  547.8   –   –   547.8   191.5   378.3   (63.4)  506.4   –   –   506.4 
Total current liabilities  5,682.4   4,165.9   (1,178.8)  8,669.5   8.1   (8.1)  8,669.5   4,819.7   3,133.1   (1,037.4)  6,915.4   180.9   (180.9)  6,915.4 
Long-term debt  25,624.5   14.7   –   25,639.2   –   –   25,639.2   27,841.3   14.6   –   27,855.9   –   –   27,855.9 
Deferred tax liabilities  21.0   68.9   (1.2)  88.7   –   2.7   91.4   24.6   400.8   (0.6)  424.8   –   3.4   428.2 
Other long-term liabilities  195.5   603.0   (221.9)  576.6   513.1   –   1,089.7   579.4   619.0   (246.8)  951.6   –   –   951.6 
Commitments and contingencies                                                 
Equity:                                                        
Partners’ and other owners’ equity  24,974.5   47,392.8   (47,381.8)  24,985.5   24,496.0   (24,985.5)  24,496.0   25,699.9   48,749.4   (49,253.5)  25,195.8   25,050.4   (25,195.8)  25,050.4 
Noncontrolling interests  –   65.9   996.7   1,062.6   –   (33.1)  1,029.5   –   64.5   1,036.2   1,100.7   –   (36.9)  1,063.8 
Total equity  24,974.5   47,458.7   (46,385.1)  26,048.1   24,496.0   (25,018.6)  25,525.5   25,699.9   48,813.9   (48,217.3)  26,296.5   25,050.4   (25,232.7)  26,114.2 
Total liabilities and equity $56,497.9  $52,311.2  $(47,787.0) $61,022.1  $25,017.2  $(25,024.0) $61,015.3  $58,964.9  $52,981.4  $(49,502.1) $62,444.2  $25,231.3  $(25,410.2) $62,265.3 

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

Enterprise Products Partners L.P.
Unaudited Condensed Consolidating Balance Sheet
December 31, 20182019

 EPO and Subsidiaries           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
  
Subsidiary
Issuer
(EPO)
  
Other
Subsidiaries
(Non-
guarantor)
  
EPO and
Subsidiaries
Eliminations
and
Adjustments
  
Consolidated
EPO and
Subsidiaries
  
EPD
(Guarantor)
  
Eliminations
and
Adjustments
  
Consolidated
Total
 
ASSETS                                          
Current assets:                                          
Cash and cash equivalents and restricted cash $393.4  $50.3  $(33.6) $410.1  $–  $–  $410.1  $109.2  $315.8  $(15.1) $409.9  $0.1  $–  $410.0 
Accounts receivable – trade, net  1,303.1   2,356.8   (0.8)  3,659.1   –   –   3,659.1   1,471.1   3,403.8   (1.3)  4,873.6   –   –   4,873.6 
Accounts receivable – related parties  141.8   1,423.7   (1,530.1)  35.4   0.8   (32.7)  3.5   233.1   799.9   (1,023.6)  9.4   –   (6.9)  2.5 
Inventories  889.3   633.2   (0.4)  1,522.1   –   –   1,522.1   1,351.3   740.4   (0.3)  2,091.4   –   –   2,091.4 
Derivative assets  105.0   49.1   0.3   154.4   –   –   154.4   115.2   12.0   –   127.2   –   –   127.2 
Prepaid and other current assets  166.0   155.1   (10.2)  310.9   –   0.6   311.5   221.0   183.5   (46.3)  358.2   –   –   358.2 
Total current assets  2,998.6   4,668.2   (1,574.8)  6,092.0   0.8   (32.1)  6,060.7   3,500.9   5,455.4   (1,086.6)  7,869.7   0.1   (6.9)  7,862.9 
Property, plant and equipment, net  6,112.7   32,628.7   (3.8)  38,737.6   –   –   38,737.6   6,413.3   35,233.6   (43.5)  41,603.4   –   –   41,603.4 
Investments in unconsolidated affiliates  43,962.6   4,170.6   (45,518.1)  2,615.1   24,273.6   (24,273.6)  2,615.1   45,514.0   4,165.7   (47,079.5)  2,600.2   25,279.3   (25,279.3)  2,600.2 
Intangible assets, net  659.2   2,963.0   (13.8)  3,608.4   –   –   3,608.4   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   459.5   5,285.7   –   5,745.2   –   –   5,745.2 
Other assets  292.1   131.9   (222.1)  201.9   0.9   –   202.8   404.9   288.5   (221.9)  471.5   1.0   –   472.5 
Total assets $54,484.7  $49,848.1  $(47,332.6) $57,000.2  $24,275.3  $(24,305.7) $56,969.8  $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 $1,500.0  $0.1  $–  $1,500.1  $–  $–  $1,500.1  $1,981.9  $–  $–  $1,981.9  $–  $–  $1,981.9 
Accounts payable – trade  404.0   734.3   (35.5)  1,102.8   –   –   1,102.8   301.4   717.7   (14.6)  1,004.5   –   –   1,004.5 
Accounts payable – related parties  1,557.3   127.5   (1,543.9)  140.9   31.9   (32.6)  140.2   977.5   222.3   (1,037.5)  162.3   6.9   (6.9)  162.3 
Accrued product payables  1,574.7   1,902.3   (1.2)  3,475.8   –   –   3,475.8   1,895.4   3,021.9   (1.6)  4,915.7   –   –   4,915.7 
Accrued interest  395.5   0.9   (0.8)  395.6   –   –   395.6   431.6   0.9   (0.8)  431.7   –   –   431.7 
Derivative liabilities  86.2   61.7   0.3   148.2   –   –   148.2   114.2   8.2   –   122.4   –   –   122.4 
Other current liabilities  87.9   326.3   (9.4)  404.8   –   –   404.8   120.5   438.2   (47.3)  511.4   –   (0.2)  511.2 
Total current liabilities  5,605.6   3,153.1   (1,590.5)  7,168.2   31.9   (32.6)  7,167.5   5,822.5   4,409.2   (1,101.8)  9,129.9   6.9   (7.1)  9,129.7 
Long-term debt  24,663.4   14.7   –   24,678.1   –   –   24,678.1   25,628.6   14.6   –   25,643.2   –   –   25,643.2 
Deferred tax liabilities  17.0   62.0   (0.9)  78.1   –   2.3   80.4   22.2   75.6   (0.8)  97.0   –   3.4   100.4 
Other long-term liabilities  65.2   518.4   (221.9)  361.7   389.9   –   751.6   161.2   608.9   (247.2)  522.9   509.5   –   1,032.4 
Commitments and contingencies                                                 
Equity:                                                        
Partners’ and other owners’ equity  24,133.5   46,031.8   (45,917.9)  24,247.4   23,853.5   (24,247.4)  23,853.5   25,294.8   48,107.6   (48,155.3)  25,247.1   24,764.0   (25,247.1)  24,764.0 
Noncontrolling interests  –   68.1   398.6   466.7   –   (28.0)  438.7   –   65.3   1,033.6   1,098.9   –   (35.4)  1,063.5 
Total equity  24,133.5   46,099.9   (45,519.3)  24,714.1   23,853.5   (24,275.4)  24,292.2   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 $54,484.7  $49,848.1  $(47,332.6) $57,000.2  $24,275.3  $(24,305.7) $56,969.8  $56,929.3  $53,281.2  $(48,471.5) $61,739.0  $25,280.4  $(25,286.2) $61,733.2 

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


Enterprise Products Partners L.P.
Unaudited Condensed Consolidating Statement of Operations
For the Three Months Ended September 30, 2019March 31, 2020

  EPO and Subsidiaries          
  
Subsidiary
Issuer
(EPO)
  
Other
Subsidiaries
(Non-
guarantor)
  
EPO and
Subsidiaries
Eliminations
and
Adjustments
  
Consolidated
EPO and
Subsidiaries
  
EPD
(Guarantor)
  
Eliminations
and
Adjustments
  
Consolidated
Total
 
Revenues $8,268.7  $5,238.9  $(5,543.5) $7,964.1  $–  $–  $7,964.1 
Costs and expenses:                            
Operating costs and expenses  7,950.9   4,166.6   (5,543.8)  6,573.7   –   –   6,573.7 
General and administrative costs  9.4   45.4   0.4   55.2   0.3   –   55.5 
Total costs and expenses  7,960.3   4,212.0   (5,543.4)  6,628.9   0.3   –   6,629.2 
Equity in income of unconsolidated affiliates  1,131.9   167.1   (1,159.7)  139.3   1,058.2   (1,058.2)  139.3 
Operating income  1,440.3   1,194.0   (1,159.8)  1,474.5   1,057.9   (1,058.2)  1,474.2 
Other income (expense):                            
Interest expense  (383.2)  (2.6)  2.9   (382.9)  –   –   (382.9)
Other, net  8.7   1.8   (2.9)  7.6   (38.7)  –   (31.1)
Total other expense, net  (374.5)  (0.8)  –   (375.3)  (38.7)  –   (414.0)
Income before income taxes  1,065.8   1,193.2   (1,159.8)  1,099.2   1,019.2   (1,058.2)  1,060.2 
Provision for income taxes  (8.5)  (6.6)  –   (15.1)  –   (0.3)  (15.4)
Net income  1,057.3   1,186.6   (1,159.8)  1,084.1   1,019.2   (1,058.5)  1,044.8 
Net income attributable to noncontrolling interests  –   (1.5)  (25.4)  (26.9)  –   1.3   (25.6)
Net income attributable to entity $1,057.3  $1,185.1  $(1,185.2) $1,057.2  $1,019.2  $(1,057.2) $1,019.2 

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


Enterprise Products Partners L.P.
Unaudited Condensed Consolidating Statement of Operations
For the Three Months Ended September 30, 2018March 31, 2019

 EPO and Subsidiaries           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
  
Subsidiary
Issuer
(EPO)
  
Other
Subsidiaries
(Non-
guarantor)
  
EPO and
Subsidiaries
Eliminations
and
Adjustments
  
Consolidated
EPO and
Subsidiaries
  
Enterprise
Products
Partners
L.P.
(Guarantor)
  
Eliminations
and
Adjustments
  
Consolidated
Total
 
Revenues $11,395.5  $6,039.5  $(7,849.1) $9,585.9  $–  $–  $9,585.9  $9,477.8  $5,639.6  $(6,573.9) $8,543.5  $–  $–  $8,543.5 
Costs and expenses:                                                        
Operating costs and expenses  11,086.5   4,764.8   (7,849.4)  8,001.9   –   –   8,001.9   9,149.5   4,440.1   (6,569.9)  7,019.7   –   –   7,019.7 
General and administrative costs  8.0   43.6   0.8   52.4   0.3   –   52.7   3.8   46.8   0.7   51.3   0.9   –   52.2 
Total costs and expenses  11,094.5   4,808.4   (7,848.6)  8,054.3   0.3   –   8,054.6   9,153.3   4,486.9   (6,569.2)  7,071.0   0.9   –   7,071.9 
Equity in income of unconsolidated affiliates  1,313.4   146.8   (1,348.2)  112.0   1,332.0   (1,332.0)  112.0   1,276.8   172.1   (1,294.3)  154.6   1,319.2   (1,319.2)  154.6 
Operating income  1,614.4   1,377.9   (1,348.7)  1,643.6   1,331.7   (1,332.0)  1,643.3   1,601.3   1,324.8   (1,299.0)  1,627.1   1,318.3   (1,319.2)  1,626.2 
Other income (expense):                                                        
Interest expense  (279.8)  (2.5)  2.8   (279.5)  –   –   (279.5)  (277.3)  (2.7)  2.8   (277.2)  –   –   (277.2)
Other, net  2.6   0.5   (2.8)  0.3   (18.5)  –   (18.2)  3.1   1.2   (2.8)  1.5   (57.8)  –   (56.3)
Total other expense, net  (277.2)  (2.0)  –   (279.2)  (18.5)  –   (297.7)  (274.2)  (1.5)  –   (275.7)  (57.8)  –   (333.5)
Income before income taxes  1,337.2   1,375.9   (1,348.7)  1,364.4   1,313.2   (1,332.0)  1,345.6   1,327.1   1,323.3   (1,299.0)  1,351.4   1,260.5   (1,319.2)  1,292.7 
Provision for income taxes  (5.9)  (4.8)  –   (10.7)  –   (0.3)  (11.0)  (4.2)  (7.8)  –   (12.0)  –   (0.3)  (12.3)
Net income  1,331.3   1,371.1   (1,348.7)  1,353.7   1,313.2   (1,332.3)  1,334.6   1,322.9   1,315.5   (1,299.0)  1,339.4   1,260.5   (1,319.5)  1,280.4 
Net income attributable to noncontrolling interests  –   (2.4)  (20.5)  (22.9)  –   1.5   (21.4)  –   (1.8)  (19.4)  (21.2)  –   1.3   (19.9)
Net income attributable to entity $1,331.3  $1,368.7  $(1,369.2) $1,330.8  $1,313.2  $(1,330.8) $1,313.2  $1,322.9  $1,313.7  $(1,318.4) $1,318.2  $1,260.5  $(1,318.2) $1,260.5 

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


Enterprise Products Partners L.P.
Unaudited Condensed Consolidating Statement of OperationsComprehensive Income
For the NineThree Months Ended September 30, 2019March 31, 2020

  EPO and Subsidiaries          
  
Subsidiary
Issuer
(EPO)
  
Other
Subsidiaries
(Non-
guarantor)
  
EPO and
Subsidiaries
Eliminations
and
Adjustments
  
Consolidated
EPO and
Subsidiaries
  
EPD
(Guarantor)
  
Eliminations
and
Adjustments
  
Consolidated
Total
 
Revenues $25,664.8  $16,618.5  $(17,499.4) $24,783.9  $–  $–  $24,783.9 
Costs and expenses:                            
Operating costs and expenses  24,670.6   13,216.2   (17,492.5)  20,394.3   –   –   20,394.3 
General and administrative costs  22.6   133.4   2.3   158.3   1.9   –   160.2 
Total costs and expenses  24,693.2   13,349.6   (17,490.2)  20,552.6   1.9   –   20,554.5 
Equity in income of unconsolidated affiliates  3,606.9   496.8   (3,672.4)  431.3   3,619.4   (3,619.4)  431.3 
Operating income  4,578.5   3,765.7   (3,681.6)  4,662.6   3,617.5   (3,619.4)  4,660.7 
Other income (expense):                            
Interest expense  (950.9)  (7.8)  8.5   (950.2)  –   –   (950.2)
Other, net  16.0   4.2   (8.5)  11.7   (123.1)  –   (111.4)
Total other expense, net  (934.9)  (3.6)  –   (938.5)  (123.1)  –   (1,061.6)
Income before income taxes  3,643.6   3,762.1   (3,681.6)  3,724.1   3,494.4   (3,619.4)  3,599.1 
Provision for income taxes  (18.2)  (18.3)  –   (36.5)  –   (0.9)  (37.4)
Net income  3,625.4   3,743.8   (3,681.6)  3,687.6   3,494.4   (3,620.3)  3,561.7 
Net income attributable to noncontrolling interests  –   (4.9)  (66.5)  (71.4)  –   4.1   (67.3)
Net income attributable to entity $3,625.4  $3,738.9  $(3,748.1) $3,616.2  $3,494.4  $(3,616.2) $3,494.4 
  EPO and Subsidiaries          
  
Subsidiary
Issuer
(EPO)
  
Other
Subsidiaries
(Non-
guarantor)
  
EPO and
Subsidiaries
Eliminations
and
Adjustments
  
Consolidated
EPO and
Subsidiaries
  
Enterprise
Products
Partners
L.P.
(Guarantor)
  
Eliminations
and
Adjustments
  
Consolidated
Total
 
Comprehensive income $489.1  $1,044.9  $(177.2) $1,356.8  $1,401.0  $(1,331.9) $1,425.9 
Comprehensive income attributable to noncontrolling interests
  –   (1.4)  (24.9)  (26.3)  –   1.4   (24.9)
Comprehensive income attributable to entity $489.1  $1,043.5  $(202.1) $1,330.5  $1,401.0  $(1,330.5) $1,401.0 


Enterprise Products Partners L.P.
Unaudited Condensed Consolidating Statement of Operations
For the Nine Months Ended September 30, 2018

  EPO and Subsidiaries          
  
Subsidiary
Issuer
(EPO)
  
Other
Subsidiaries
(Non-
guarantor)
  
EPO and
Subsidiaries
Eliminations
and
Adjustments
  
Consolidated
EPO and
Subsidiaries
  
EPD
(Guarantor)
  
Eliminations
and
Adjustments
  
Consolidated
Total
 
Revenues $31,270.1  $18,254.8  $(22,173.0) $27,351.9  $–  $–  $27,351.9 
Costs and expenses:                            
Operating costs and expenses  30,323.2   15,626.9   (22,173.5)  23,776.6   –   –   23,776.6 
General and administrative costs  21.4   132.3   1.4   155.1   2.0   –   157.1 
Total costs and expenses  30,344.6   15,759.2   (22,172.1)  23,931.7   2.0   –   23,933.7 
Equity in income of unconsolidated affiliates  2,812.1   437.8   (2,899.9)  350.0   2,924.6   (2,924.6)  350.0 
Operating income  3,737.6   2,933.4   (2,900.8)  3,770.2   2,922.6   (2,924.6)  3,768.2 
Other income (expense):                            
Interest expense  (806.8)  (7.6)  8.2   (806.2)  –   –   (806.2)
Other, net  7.8   41.1   (8.2)  40.7   (34.9)  –   5.8 
Total other expense, net  (799.0)  33.5   –   (765.5)  (34.9)  –   (800.4)
Income before income taxes  2,938.6   2,966.9   (2,900.8)  3,004.7   2,887.7   (2,924.6)  2,967.8 
Provision for income taxes  (17.5)  (16.2)  –   (33.7)  –   (0.8)  (34.5)
Net income  2,921.1   2,950.7   (2,900.8)  2,971.0   2,887.7   (2,925.4)  2,933.3 
Net income attributable to noncontrolling interests  –   (6.1)  (43.6)  (49.7)  –   4.1   (45.6)
Net income attributable to entity $2,921.1  $2,944.6  $(2,944.4) $2,921.3  $2,887.7  $(2,921.3) $2,887.7 


43

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

Enterprise Products Partners L.P.
Unaudited Condensed Consolidating Statement of Comprehensive Income
For the Three Months Ended September 30,March 31, 2019

  EPO and Subsidiaries          
  
Subsidiary
Issuer
(EPO)
  
Other
Subsidiaries
(Non-
guarantor)
  
EPO and
Subsidiaries
Eliminations
and
Adjustments
  
Consolidated
EPO and
Subsidiaries
  
EPD
(Guarantor)
  
Eliminations
and
Adjustments
  
Consolidated
Total
 
Comprehensive income $1,038.7  $1,176.8  $(1,159.8) $1,055.7  $990.8  $(1,030.1) $1,016.4 
Comprehensive income attributable to noncontrolling interests  –   (1.5)  (25.4)  (26.9)  –   1.3   (25.6)
Comprehensive income attributable to entity $1,038.7  $1,175.3  $(1,185.2) $1,028.8  $990.8  $(1,028.8) $990.8 

Unaudited Condensed Consolidating Statement of Comprehensive Income
For the Three Months Ended September 30, 2018

  EPO and Subsidiaries          
  
Subsidiary
Issuer
(EPO)
  
Other
Subsidiaries
(Non-
guarantor)
  
EPO and
Subsidiaries
Eliminations
and
Adjustments
  
Consolidated
EPO and
Subsidiaries
  
EPD
(Guarantor)
  
Eliminations
and
Adjustments
  
Consolidated
Total
 
Comprehensive income $1,177.1  $1,340.7  $(1,348.2) $1,169.6  $1,129.1  $(1,148.2) $1,150.5 
Comprehensive income attributable to noncontrolling interests  –   (2.4)  (20.5)  (22.9)  –   1.5   (21.4)
Comprehensive income attributable to entity $1,177.1  $1,338.3  $(1,368.7) $1,146.7  $1,129.1  $(1,146.7) $1,129.1 

Unaudited Condensed Consolidating Statement of Comprehensive Income
For the Nine Months Ended September 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 $3,628.6  $3,650.6  $(3,681.6) $3,597.6  $3,404.4  $(3,530.3) $3,471.7 
Comprehensive income attributable to noncontrolling interests
  –   (4.9)  (66.5)  (71.4)  –   4.1   (67.3)
Comprehensive income attributable to entity $3,628.6  $3,645.7  $(3,748.1) $3,526.2  $3,404.4  $(3,526.2) $3,404.4 

Unaudited Condensed Consolidating Statement of Comprehensive Income
For the Nine Months Ended September 30, 2018

 EPO and Subsidiaries           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
  
Subsidiary
Issuer
(EPO)
  
Other
Subsidiaries
(Non-
guarantor)
  
EPO and
Subsidiaries
Eliminations
and
Adjustments
  
Consolidated
EPO and
Subsidiaries
  
Enterprise
Products
Partners
L.P.
(Guarantor)
  
Eliminations
and
Adjustments
  
Consolidated
Total
 
Comprehensive income $2,791.2  $2,943.9  $(2,899.7) $2,835.4  $2,752.1  $(2,789.8) $2,797.7  $1,294.2  $1,199.3  $(1,299.0) $1,194.5  $1,115.6  $(1,174.6) $1,135.5 
Comprehensive income attributable to noncontrolling interests  –   (6.1)  (43.6)  (49.7)  –   4.1   (45.6)
Comprehensive income attributable to noncontrolling interests
  –   (1.8)  (19.4)  (21.2)  –   1.3   (19.9)
Comprehensive income attributable to entity $2,791.2  $2,937.8  $(2,943.3) $2,785.7  $2,752.1  $(2,785.7) $2,752.1  $1,294.2  $1,197.5  $(1,318.4) $1,173.3  $1,115.6  $(1,173.3) $1,115.6 

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


Enterprise Products Partners L.P.
Unaudited Condensed Consolidating Statement of Cash Flows
For the NineThree Months Ended September 30, 2019March 31, 2020

 EPO and Subsidiaries           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
  
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 $3,625.4  $3,743.8  $(3,681.6) $3,687.6  $3,494.4  $(3,620.3) $3,561.7  $765.8  $717.2  $(177.1) $1,305.9  $1,350.1  $(1,281.0) $1,375.0 
Reconciliation of net income to net cash flows provided by operating activities:                                                        
Depreciation, amortization and accretion  231.5   1,226.5   (1.3)  1,456.7   –   –   1,456.7   85.6   424.2   (0.8)  509.0   –   –   509.0 
Equity in income of unconsolidated affiliates  (3,606.9)  (496.8)  3,672.4   (431.3)  (3,619.4)  3,619.4   (431.3)  (678.1)  (153.1)  690.4   (140.8)  (1,280.7)  1,280.7   (140.8)
Distributions received on earnings from unconsolidated affiliates  1,170.9   243.0   (982.7)  431.2   3,028.9   (3,028.9)  431.2 
Distributions received from unconsolidated affiliates attributable to earnings  397.9   68.0   (339.0)  126.9   981.1   (981.1)  126.9 
Net effect of changes in operating accounts and other operating activities  2,203.8   (2,549.8)  19.1   (326.9)  134.6   0.2   (192.1)  1,161.3   (612.7)  (509.7)  38.9   103.2   –   142.1 
Net cash flows provided by operating activities  3,624.7   2,166.7   (974.1)  4,817.3   3,038.5   (3,029.6)  4,826.2   1,732.5   443.6   (336.2)  1,839.9   1,153.7   (981.4)  2,012.2 
Investing activities:                                                        
Capital expenditures  (503.8)  (2,791.2)  (7.1)  (3,302.1)  –   –   (3,302.1)  (266.8)  (813.0)  0.3   (1,079.5)  –   –   (1,079.5)
Cash used for business combination, net of cash received  –   –   –   –   –   –   – 
Proceeds from asset sales  0.9   15.9   –   16.8   –   –   16.8   0.1   0.5   –   0.6   –   –   0.6 
Other investing activities  (1,349.5)  (28.8)  1,290.8   (87.5)  (119.3)  119.3   (87.5)  (640.1)  4.6   642.7   7.2   –   –   7.2 
Cash used in investing activities  (1,852.4)  (2,804.1)  1,283.7   (3,372.8)  (119.3)  119.3   (3,372.8)  (906.8)  (807.9)  643.0   (1,071.7)  –   –   (1,071.7)
Financing activities:                                                        
Borrowings under debt agreements  44,629.6   –   –   44,629.6   –   –   44,629.6   5,411.8   –   –   5,411.8   –   –   5,411.8 
Repayments of debt  (42,855.2)  (0.1)  –   (42,855.3)  –   –   (42,855.3)  (3,406.6)  –   –   (3,406.6)  –   –   (3,406.6)
Cash distributions paid to owners  (3,028.9)  (1,484.8)  1,484.8   (3,028.9)  (2,871.1)  3,028.9   (2,871.1)  (981.1)  (374.6)  374.5   (981.2)  (974.2)  981.2   (974.2)
Cash payments made in connection with DERs  –   –   –   –   (16.4)  –   (16.4)  –   –   –   –   (5.8)  –   (5.8)
Cash distributions paid to noncontrolling interests  –   (7.0)  (63.4)  (70.4)  –   0.7   (69.7)  –   (2.2)  (27.9)  (30.1)  –   0.2   (29.9)
Cash contributions from noncontrolling interests  –   –   590.8   590.8   –   –   590.8   –   –   5.2   5.2   –   –   5.2 
Net cash proceeds from issuance of common units  –   –   –   –   82.2   –   82.2 
Common units acquired in connection with buyback program  –   –   –   –   (81.1)  –   (81.1)
Common units acquired in connection with 2019 Buyback Program  –   –   –   –   (140.1)  –   (140.1)
Cash contributions from owners  119.3   2,320.3   (2,320.3)  119.3   –   (119.3)  –   –   655.5   (655.5)  –   –   –   – 
Other financing activities  (26.3)  (5.6)  –   (31.9)  (32.8)  –   (64.7)  (61.7)  –   –   (61.7)  (33.6)  –   (95.3)
Cash provided by (used in) financing activities  (1,161.5)  822.8   (308.1)  (646.8)  (2,919.2)  2,910.3   (655.7)  962.4   278.7   (303.7)  937.4   (1,153.7)  981.4   765.1 
Net change in cash and cash equivalents,
including restricted cash
  610.8   185.4   1.5   797.7   –   –   797.7   1,788.1   (85.6)  3.1   1,705.6   –   –   1,705.6 
Cash and cash equivalents, including
restricted cash, at beginning of period
  393.4   50.3   (33.6)  410.1   –   –   410.1   109.2   315.8   (15.1)  409.9   0.1   –   410.0 
Cash and cash equivalents, including
restricted cash, at end of period
 $1,004.2  $235.7  $(32.1) $1,207.8  $–  $–  $1,207.8  $1,897.3  $230.2  $(12.0) $2,115.5  $0.1  $–  $2,115.6 

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


Enterprise Products Partners L.P.
Unaudited Condensed Consolidating Statement of Cash Flows
For the NineThree Months Ended September 30, 2018March 31, 2019

 EPO and Subsidiaries           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
  
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 $2,921.1  $2,950.7  $(2,900.8) $2,971.0  $2,887.7  $(2,925.4) $2,933.3  $1,322.9  $1,315.5  $(1,299.0) $1,339.4  $1,260.5  $(1,319.5) $1,280.4 
Reconciliation of net income to net cash flows provided by operating activities:                                                        
Depreciation, amortization and accretion  207.3   1,123.8   (0.3)  1,330.8   –   –   1,330.8   74.9   399.8   (0.2)  474.5   –   –   474.5 
Equity in income of unconsolidated affiliates  (2,812.1)  (437.8)  2,899.9   (350.0)  (2,924.6)  2,924.6   (350.0)  (1,276.8)  (172.1)  1,294.3   (154.6)  (1,319.2)  1,319.2   (154.6)
Distributions received on earnings from unconsolidated affiliates  915.1   191.5   (760.9)  345.7   2,834.5   (2,834.5)  345.7 
Distributions received from unconsolidated affiliates attributable to earnings  338.4   83.0   (282.4)  139.0   981.7   (981.7)  139.0 
Net effect of changes in operating accounts and other operating activities  2,325.1   (2,344.0)  (35.0)  (53.9)  69.4   –   15.5   100.9   (861.7)  27.7   (733.1)  154.0   0.2   (578.9)
Net cash flows provided by operating activities  3,556.5   1,484.2   (797.1)  4,243.6   2,867.0   (2,835.3)  4,275.3   560.3   764.5   (259.6)  1,065.2   1,077.0   (981.8)  1,160.4 
Investing activities:                                                        
Capital expenditures  (605.8)  (2,343.2)  –   (2,949.0)  (55.2)  –   (3,004.2)  (223.8)  (921.0)  (4.1)  (1,148.9)  –   –   (1,148.9)
Cash used for business combination, net of cash received  –   (150.6)  –   (150.6)  –   –   (150.6)
Proceeds from asset sales  11.4   12.7   –   24.1   –   –   24.1   0.2   1.5   –   1.7   –   –   1.7 
Other investing activities  (1,701.1)  180.6   1,468.4   (52.1)  (438.1)  438.1   (52.1)  (492.8)  (10.1)  475.6   (27.3)  (84.1)  84.1   (27.3)
Cash used in investing activities  (2,295.5)  (2,300.5)  1,468.4   (3,127.6)  (493.3)  438.1   (3,182.8)  (716.4)  (929.6)  471.5   (1,174.5)  (84.1)  84.1   (1,174.5)
Financing activities:                                                        
Borrowings under debt agreements  67,086.3   11.5   (11.5)  67,086.3   –   –   67,086.3   15,692.4   –   –   15,692.4   –   –   15,692.4 
Repayments of debt  (65,741.7)  (0.4)  –   (65,742.1)  –   –   (65,742.1)  (14,999.1)  (0.1)  –   (14,999.2)  –   –   (14,999.2)
Cash distributions paid to owners  (2,834.5)  (1,003.6)  1,003.6   (2,834.5)  (2,782.9)  2,834.5   (2,782.9)  (981.7)  (300.5)  300.5   (981.7)  (950.4)  981.7   (950.4)
Cash payments made in connection with DERs  –   –   –   –   (13.2)  –   (13.2)  –   –   –   –   (4.5)  –   (4.5)
Cash distributions paid to noncontrolling interests  –   (6.8)  (44.9)  (51.7)  –   0.8   (50.9)  –   (2.4)  (15.7)  (18.1)  –   0.1   (18.0)
Cash contributions from noncontrolling interests  –   –   222.0   222.0   –   –   222.0   –   –   34.8   34.8   –   –   34.8 
Net cash proceeds from issuance of common units  –   –   –   –   449.4   –   449.4   –   –   –   –   42.7   –   42.7 
Common units acquired in connection with 2019 Buyback Program  –   –   –   –   (51.6)  –   (51.6)
Cash contributions from owners  438.1   1,876.6   (1,876.6)  438.1   –   (438.1)  –   84.1   512.9   (512.9)  84.1   –   (84.1)  – 
Other financing activities  (25.3)  –   –   (25.3)  (27.0)  –   (52.3)  –   (5.6)  –   (5.6)  (29.1)  –   (34.7)
Cash provided by (used in) financing activities  (1,077.1)  877.3   (707.4)  (907.2)  (2,373.7)  2,397.2   (883.7)  (204.3)  204.3   (193.3)  (193.3)  (992.9)  897.7   (288.5)
Net change in cash and cash equivalents,
including restricted cash
  183.9   61.0   (36.1)  208.8   –   –   208.8   (360.4)  39.2   18.6   (302.6)  –   –   (302.6)
Cash and cash equivalents, including
restricted cash, at beginning of period
  65.2   31.5   (26.4)  70.3   –   –   70.3   393.4   50.3   (33.6)  410.1   –   –   410.1 
Cash and cash equivalents, including
restricted cash, at end of period
 $249.1  $92.5  $(62.5) $279.1  $–  $–  $279.1  $33.0  $89.5  $(15.0) $107.5  $–  $–  $107.5 


Note 19.  Subsequent Events

Enterprise Enters Into April 2020 364-Day Revolving Credit Agreement

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


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

For the Three and Nine Months Ended September 30,March 31, 2020 and 2019 and 2018

The following information should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and accompanying Notes included in this quarterly report on Form 10-Q and the Audited Consolidated Financial Statements and related Notes, together with our discussion and analysis of financial position and results of operations, included in our annual report on Form 10-K for the year ended December 31, 20182019 (the “2018“2019 Form 10-K”), as filed on March 1, 2019February 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 PresidentCo-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 31.9%32.1% of EPD’s limited partner common units at September 30, 2019.March 31, 2020.

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

/d=per dayMMBbls=million barrels
BBtus=billion British thermal unitsMMBPD=million barrels per day
Bcf=billion cubic feetMMBtus=million British thermal units
BPD=barrels per dayMMcf=million cubic feet
MBPD=thousand barrels per dayTBtus=trillion British thermal units

As used in this quarterly report, the phrase “quarter-to-quarter” means the thirdfirst quarter of 20192020 compared to the thirdfirst quarter of 2018.  Likewise, the phrase “period-to-period” means the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018.2019.
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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This quarterly report on Form 10-Q contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us.  When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “seek,” “goal,” “estimate,” “forecast,” “intend,” “could,” “should,” “would,” “will,” “believe,” “may,” “potential” and similar expressions and statements regarding our plans and objectives for future operations are intended to identify forward-looking statements.  Although we and our general partner believe that our expectations reflected in such forward-looking statements (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 20182019 Form 10-K and within Part II, Item 1A of this quarterly report.  These risks include recent impacts of COVID-19 and decreases in certain commodity prices resulting from demand weakness and oversupply, which are discussed in Part II, Item 1A “Risk Factors” of this quarterly report, and this Part I, Item 2.  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.

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

Significant Recent DevelopmentsUpdate on 2020 Outlook – Coronavirus and Oil Price Shock

EnterpriseAs noted previously, this quarterly report on Form 10-Q, including this Update on 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 Expand Appalachia-to-Texasus, 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.

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

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

the initiation of a crude oil price war in March 2020 between members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (collectively, the “OPEC+” group) and its effect on global crude oil supplies.  OPEC+ subsequently agreed in April 2020 to reduce global supplies by 9.7 MMBPD beginning with the May 2020 production month.

The consequences of international COVID-19 containment measures (and the resulting dramatic declines in end-user demand for hydrocarbons in general), paired with threatened and actual overproduction of crude oil in April 2020 by Saudi Arabia and Russia (in their attempt to gain market share from each other and U.S. shale producers), resulted in major disruptions to global energy markets.  As a midstream energy company, these macroeconomic events have a direct impact on our financial position, results of operations and cash flows.  As noted 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.

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

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

In October 2019, we announcedApril 2020, at the urging of President Trump, OPEC and Russia met again to discuss ways to stabilize the global oil markets. After intense negotiations, OPEC and Russia agreed to reduce their combined oil production by 9.7 MMBPD in May and June 2020, 7.7 MMBPD from July through December 2020 and 5.8 MMBPD from January 2021 to April 2022.  Moreover, the U.S., Brazil and Canada contributed an expansionaggregate 3.7 MMBPD of our ATEX ethane pipelineadditional reductions on the basis that adverse market dynamics (e.g., COVID-19 demand destruction) will naturally result in lower production from their respective energy industries.  The new OPEC+ agreement will be reevaluated in December 2021.  The length of the output restrictions by U.S., Brazil and Canada will depend on market forces, which are based on supply and demand fundamentals.

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

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

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

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

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

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

Capital spending throughout the domestic energy industry is being significantly reduced to protect cash flow. For example, integrated oil majors Chevron Corporation and ExxonMobil recently announced reductions in their 2020 capital expenditure budgets of 20% (as of March 24, 2020) and 30% (as of April 7, 2020), respectively.  Many smaller and independent energy producers are not expected to have the same level of access to the capital markets as they did during a recent 30-day binding open season. The 1,192-mile ATEX pipeline transports ethane from the Marcellus/Utica Basinprevious downturn in 2015/2016.

Based on information currently available, we now expect our total capital investments for 2020 to approximate $2.8 billion to $3.3 billion (previously $3.4 billion to $4.4 billion), which reflects growth capital investments of Pennsylvania, West Virginia$2.5 billion to $3.0 billion (previously $3.0 billion to $4.0 billion) and Ohioapproximately $300 million for sustaining capital expenditures (previously $400 million).  We currently expect our growth capital investments on sanctioned projects for 2021 and 2022 to approximate $2.5 billion and $1.5 billion, respectively.  These amounts do not include capital investments associated with our NGL storage complexproposed deepwater offshore crude oil terminal (the Sea Port Oil Terminal or “SPOT”), which remains subject to governmental approvals.  We do not expect to receive governmental approvals for SPOT in Mont Belvieu, Texas.   The current capacity2020.

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Table of ATEX is approximately 145 MBPD, which would be expanded to 190 MBPD in connection with this expansion project. The incremental capacityContents

Downstream demand for hydrocarbon products such as gasoline and jet fuel is expected to be achieved through improvementsremain depressed until the COVID-19 containment measures are lifted and modificationsthe economy sufficiently improves.  Refiners have significantly reduced their utilization rates in response to existing infrastructure.  We anticipate that this expansion project will be completedthe lack of domestic and international demand.  According to the IEA’s April 2020 Report, global refining throughput for 2020 is forecast to fall 7.6 MMBPD to 74.3 MMBPD in 2022.

Enterprise to Build Midland-to-ECHO 4 Pipeline; Conversion of Crude Oil Pipeline back to NGL Service

In October 2019, we announced long-term agreements that support a further expansion of our Midland-to-ECHO crude oil pipeline network. As part of such expansion, we plan to construct a fourth pipeline (the “Midland-to-ECHO 4” pipeline) that will connect our Midland terminal in Midland, Texas with our ECHO terminal in Houston, Texas utilizing both new construction and segments of our existing crude oil pipelines in South Texas.  The Midland-to-ECHO 4 pipeline2020 on sharply reduced demand for transportation fuels.  Global refinery intake is expected to have an initial transportation capacity of 450 MBPD and can be expanded up to 540 MBPD.

When placed into service, the Midland-to-ECHO 4 pipeline will allow our shippers with crude oil and condensate production in both the Permian Basin and the Eagle Ford shale to maximize the value of their contracted pipeline capacity by allowing shippers to source barrels from the Permian Basin and/or the Eagle Ford shale.  This unmatched flexibility will allow shippers and producers to dynamically match their pipeline capacity to their allocation of capital and respective production profiles between the two basins.  Their production will be delivered into our integrated storage, pipeline, distribution and marine terminal system that has access to both domestic and international markets.

The Midland-to-ECHO 4 pipeline complements our Midland-to-ECHO 1 and 2 pipelines, which entered servicedecrease 16 MMBPD in the second quarter of 2018 and first2020 when compared to the second quarter of 2019, respectively, as well as an expansion project we announced in July 2019 (which we refer to as2019.  Although refinery runs are falling, the “Midland-to-ECHO 3” project).  The Midland-to-ECHO 3 and Midland-to-ECHO 4 projects are expected to begin service during the third quarter of 2020 and first half of 2021, respectively.  Similar to the Midland-to-ECHO 4 project, the Midland-to-ECHO 3 pipeline is expected to add an incremental 450 MBPD of transportation capacity.  Together, these four projects (Midland-to-ECHO 1, 2, 3 and 4) comprise our Midland-to-ECHO crude oil pipeline network, which supports crude oil production growth from the Permian Basin (and Eagle Ford shale, as applicable) by providing producers and other shippers with transportation solutionsIEA expects that are both cost-efficient and operationally flexible.  The Midland-to-ECHO network is expected to include 6 MMBbls of storage at our Midland terminal and access to more than 45 MMBbls of storage and approximately 4 MMBPD of export capacity at partnership assets along the Texas Gulf Coast.  The network connects to every refinery in the Houston, Texas City and Beaumont/Port Arthur area, representing approximately 4.5 MMBPD of refining capacity.

In January 2019, we converted the Midland-to-Sealy segment of one of our two Seminole NGL pipelines from NGL service to crude oil service, thus creating the major segment of the Midland-to-ECHO 2 pipeline.  In April 2019, our Midland-to-ECHO 2 pipeline, which provides us with approximately 200 MBPD of incremental crude oil transportation capacity, was placed into full service after being in limited service since February 2019.  Following the in-service date of the Midland-to-ECHO 4 pipeline, we plan to convert the Midland-to-Sealy segment of the Midland-to-ECHO 2 pipeline back to NGL service (as part of our Seminole NGL Pipeline) based upon our expectation that NGL production from the Permian Basinrefined product inventories will increase by over 50 percent by 2025.6 MMBPD due to drastically lower demand.  The reconversion project is expected to take less than sixty days and be completed duringIEA expects that refining activity will slowly recover in the second half of 2020.

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

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

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

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

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

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

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

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

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

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

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


Other Recent Developments

Enterprise Enters Into April 2020 364-Day Revolving Credit Agreement

In September 2019, we announced the execution of long-term contracts with affiliates of LyondellBasell Industries N.V. (“LyondellBasell”) that support construction of our second propane dehydrogenation plant (referred to as “PDH 2”April 2020, EPO entered into an additional 364-day revolving credit agreement (the “April 2020 364-Day Credit Agreement”).  The new plant is expectedagreement provides EPO with an incremental $1.0 billion of borrowing capacity, thereby increasing its overall borrowing capacity under its credit agreements to have$6.0 billion.  The April 2020 364-Day Credit Agreement enhances our financial flexibility during the capacity to consumecurrent economic downturn caused by the COVID-19 pandemic and oil price shock.

Under the terms of the April 2020 364-Day Credit Agreement, EPO may borrow up to 35 MBPD of propane and produce up to 1.65$1.0 billion pounds per year of polymer grade propylene (“PGP”).  PDH 2 will be located at our complex in the Mont Belvieu, Texas area.  PDH 2 is scheduled to begin service in the first half of 2023.

The anchor contracts with LyondellBasell provide for us to process LyondellBasell-provided propane into PGPa variable interest rate for a fixed fee.  This fee-based model leverages our integrated value chain by providing sourcingterm of 364 days, subject to the terms and storageconditions set forth therein.  EPO may use proceeds from our NGL storage facilities in Mont Belvieu,borrowings under the April 2020 364-Day Credit Agreement for working capital, capital expenditures, acquisitions and delivers PGP into our storage hub and network of PGP pipeline infrastructure.  Our network of PGP assets includes more than 300 miles of delivery pipelines, 5 MMBbls of storage capacity, and an export facility at our Enterprise Hydrocarbons Terminal (“EHT”) located on the Houston Ship Channel.  We are currently expanding our PGP refrigeration facilities at EHT, which will enable us to load more than 5,000 barrels per hour of PGP, as well as co-load PGP and LPG on very large gas carriers.

Our Mont Belvieu NGL fractionation and storage system supporting PDH 2 currently has 760 MBPD of NGL fractionation capacity, with another 300 MBPD under construction.  In addition, our Mont Belvieu complex has more than 100 million barrels of NGL and petrochemical storage, which provides our customers with unparalleled reliability and flexibility.  The integration of our PDH 1 and PDH 2 plants with our legacy propylene fractionation facilities provides us with significant operational flexibility, and a combined PGP supply of more than nine billion pounds per year.other company purposes.

Enterprise to ExpandProvides Distribution and Extend Acadian Gas SystemBuyback Guidance for 2020

In September 2019, we announced plansOn March 18, 2020, the Board declared a quarterly cash distribution to expand and extend our Acadian Gas System in order to deliver growing natural gas production from the Haynesville Shale to the liquefied natural gas (“LNG”) market in South Louisiana. The Haynesville region currently produces approximately 11 Bcf/d of natural gas, which is expected to grow to approximately 14 Bcf/d by 2025.

The expansion project will include construction of an approximately 80-mile natural gas pipeline (the “Gillis Lateral”) extending from near Cheneyville, Louisiana to third-party pipeline interconnects near Gillis, Louisiana, including multiple pipelines serving regional LNG export facilities.  The LNG market in South Louisiana and Southeast Texas includes facilities, including those under construction, featuring an aggregate 15 Bcf/d of export capacity. The Gillis Lateral will have a transportation capacity of approximately 1 Bcf/d.  In addition to construction of the Gillis Lateral, we plan to increase the transportation capacity of the Haynesville Extension from 1.8 Bcf/d to 2.1 Bcf/d by adding horsepower at our compressor station in Mansfield, Louisiana.

The Mansfield project and construction of the Gillis Lateral are supported by long-term customer contracts and are expected to begin service in mid-2021. Once the expansion project is completed, we expect that our Acadian Gas System will be able to deliver up to 2.1 Bcf/d of Haynesville production into the LNG market, South Louisiana industrial complex and other pipeline interconnects that serve attractive southeastern U.S. markets.

Enterprise Announces Final Investment Decision Regarding Sea Port Oil Terminal

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

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

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

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

In May 2018, in conjunction with a long-term NGL supply agreement, we granted Apache Midstream LLC (“Apache”) an option to acquire up to a 33% equity interest in our consolidated subsidiary that owns the Shin Oak NGL Pipeline (“Shin Oak”).  In November 2018, Apache contributed this option to Altus Midstream Processing LP (“Altus”), which is a consolidated subsidiary of Apache.  In July 2019, Altus exercised the option and acquired a 33% equity interest (effective July 31, 2019).  As a result, we received a $440.7 million cash payment from Altus, which is included in contributions from noncontrolling interests as presented on our Unaudited Condensed Statements of Consolidated Cash Flows for the nine months ended September 30, 2019.

Shin Oak is a 658-mile pipeline that transports NGLs from the Permian Basinpaid to our Mont Belvieu NGL fractionation and storage complex.  In February 2019, the 24-inch diameter mainline segment of Shin Oak from Orla, Texaslimited partners with respect to Mont Belvieu was placed into limited commercial service with an initial transportation capacity of 250 MBPD.  In June 2019, an additional pipeline segment, the 20-inch diameter Waha lateral, was placed into service. Shin Oak’s transportation capacity by the end of the third quarter of 2019 was 350 MBPD. When fully complete in the fourth quarter of 2019, Shin Oak is expected to have up to 550 MBPD of transportation capacity.
Enterprise Begins Service at Orla III; Update on Mentone Plant

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

In October 2018, we announced that construction of our Mentone cryogenic natural gas processing plant had commenced.  The Mentone plant, which is located in Loving County, Texas, is expected to have the capacity to process 300 MMcf/d of natural gas and extract more than 40 MBPD of NGLs.  The project is on schedule for completion in the first quarter of 2020 and is supported by a long-term acreage dedication agreement.  In addition, we are actively negotiating contractsof $0.4450 per common unit, or $1.78 per unit on an annualized basis.  The quarterly distribution associated with producers to underwrite additional capacity at Mentone. When the Mentone plant is completed and placed into service, we expect to have an aggregate 1.6 Bcf/d of natural gas processing capacity and approximately 250 MBPD of NGL production from our processing plants in the Delaware Basin.

Expansion Projects at EHT

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

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

Our current nameplate loading capacity for LPG at EHT2020 is approximately 835 MBPD, with 175 MBPDpayable on May 12, 2020, to unitholders of this loading capacity placed into service during the third quarter of 2019. The expansion project announced in July 2019 is expected to increase our LPG loading capacity at EHT by an additional 260 MBPD and be placed into service during the fourth quarter of 2020.  When this latest expansion project is completed, EHT will have a nameplate LPG loading capacity of approximately 1.1 MMBPD, or 33 MMBbls per month.

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

Enterprise to Extend Ethylene Pipeline Network

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

The Baymark pipeline will feature accessclose of business on April 30, 2020.  This distribution represents a 1.7% increase over the distribution declared with respect to a high-capacity ethylene storage well that is under development at our Mont Belvieu complex, along with connectivity to our ethylene export terminal currently under construction at Morgan’s Point. The storage well is expected to be completed in the fourth quarter of 2019 and have a capacity of 600 million pounds of ethylene. Our ethylene export terminal at Morgan’s Point will have the capacity to export approximately 2.2 billion pounds of ethylene per year and is expected to begin service in the fourthfirst quarter of 2019.

Enterprise Announces $2 Billion Unit Buyback Program

In January 2019, we announced that the Boardlight of Enterprise GP had approvedcurrent economic conditions, management will evaluate future cash distributions in 2020 on 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.

EPD repurchased 2,909,128 common units under the 2019 Buyback Program through open market purchases during the nine months ended September 30, 2019 (no repurchases were made during the third quarter of 2019).  The total purchase price of these repurchases was $81.1 million, excluding commissions and fees. The repurchased units were cancelled immediately upon acquisition.  At September 30, 2019, the remaining available capacity under the 2019 Buyback Program was $1.92 billion.

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Enterprise Provides 2019 Distribution Guidance

In January 2019, management announced plans to recommend to the Board an increase of $0.0025 per unit per quarter in our cash distribution rate with respect to 2019. The anticipated rate of increase would result in distributions for 2019 of $1.7650 per unit, which would be 2.3% higher than those paid for 2018 of $1.7250 per unit.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 payment.payments.

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

Settlement of Liquidity Option

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

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

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

On October 9As a result of the Liquidity Option settlement, the partners’ capital balance for common units (as presented on our Unaudited Condensed Consolidated Balance Sheet) increased by the $1.30 billion market value of the new EPD common units issued to Skyline.  Since OTA does not meet the definition of a business as described in ASC 805, Business Combinations, 2019,the acquisition of OTA was accounted for as the purchase of treasury units and the assumption of related deferred income tax liability.  In consolidation, we announced thatpresent the Board declared a cash distribution54,807,352 EPD common units owned by OTA as treasury units, with their historical cost based on the $1.30 billion market value of $0.4425 perthe 54,807,352 new EPD common unit with respectunits issued to Skyline.

For information regarding the thirdimpact of the settlement on our earnings for the first quarter of 2019.  This distribution2020, see “Income Statement Highlights – Income Taxes” within this Item 2.

Issuance of $3.0 Billion of Senior Notes in January 2020

In January 2020, EPO issued $3.0 billion aggregate principal amount of senior notes comprised of (i) $1.0 billion principal amount of senior notes due January 2030 (“Senior Notes AAA”), (ii) $1.0 billion principal amount of senior notes due January 2051 (“Senior Notes BBB”) and (iii) $1.0 billion principal amount of senior notes due January 2060 (“Senior Notes CCC”).   Net proceeds from this offering were used by EPO for the repayment of $500 million principal amount of its Senior Notes Q that matured in January 2020, temporary repayment of amounts outstanding under its commercial paper program and for general company purposes.  In addition, net proceeds from this offering will be paidused 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 November 12, 2019 to unitholdersan unsecured and unsubordinated basis.


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Table of record as of the close of business on October 31, 2019.Contents


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:

     PolymerRefineryIndicative Gas     PolymerRefineryIndicative Gas
Natural  Normal NaturalGradeGradeProcessingNatural  Normal NaturalGradeGradeProcessing
Gas,Ethane,Propane,Butane,Isobutane,Gasoline,Propylene,Propylene,Gross SpreadGas,Ethane,Propane,Butane,Isobutane,Gasoline,Propylene,Propylene,Gross Spread
$/MMBtu$/gallon$/gallon$/gallon$/gallon$/pound$/pound$/gallon$/MMBtu$/gallon$/gallon$/gallon$/gallon$/pound$/pound$/gallon
(1)(2)(2)(2)(2)(3)(3)(4)(1)(2)(2)(2)(2)(3)(3)(4)
2018 by quarter:        
2019 by quarter:        
1st Quarter$3.01$0.25$0.85$0.96$1.00$1.41$0.53$0.33$0.40$3.15$0.30$0.67$0.82$0.85$1.16$0.38$0.24$0.31
2nd Quarter$2.80$0.29$0.87$1.00$1.20$1.53$0.52$0.37$0.47$2.64$0.21$0.55$0.63$0.65$1.21$0.37$0.24$0.25
3rd Quarter$2.91$0.43$0.99$1.21$1.25$1.54$0.60$0.45$0.58$2.23$0.17$0.44$0.51$0.66$1.06$0.38$0.23$0.21
4th Quarter$3.65$0.35$0.79$0.91$0.94$1.22$0.51$0.35$0.34$2.50$0.19$0.50$0.68$0.82$1.20$0.35$0.21$0.25
2018 Averages$3.09$0.33$0.88$1.02$1.10$1.43$0.54$0.38$0.45
2019 Averages$2.63$0.22$0.54$0.66$0.75$1.16$0.37$0.23$0.26
                
2019 by quarter:        
2020 by quarter:        
1st Quarter$3.15$0.30$0.67$0.82$0.85$1.16$0.38$0.24$0.31$1.95$0.14$0.37$0.57$0.63$0.93$0.31$0.18$0.19
2nd Quarter$2.64$0.21$0.55$0.63$0.65$1.21$0.37$0.24$0.25
3rd Quarter$2.23$0.17$0.44$0.51$0.66$1.06$0.38$0.23$0.21
2019 Averages$2.67$0.23$0.55$0.65$0.72$1.14$0.38$0.24$0.26

(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 plantfacility to extract the NGLs nor the transportation and fractionation costs to deliver the NGLs to market.   In addition, the actual gas processing spread earned at each plant is determined by regional pricing and extraction dynamics.   As presented in the table above, the indicative spread assumes that a gallon of NGLs is comprised of 47% ethane, 28% propane, 9% normal butane, 6% isobutane and 10% natural gasoline.  The value of an equivalent amount of energy in natural gas to one gallon of NGLs is assumed to be 8.4% of the price of a MMBtu of natural gas at Henry Hub.

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TableThe weighted-average indicative market price for NGLs was $0.35 per gallon in the first quarter of Contents


2020 versus $0.57 per gallon during the first quarter of 2019.  The following table presents selected average index prices for crude oil for the periods indicated:

WTIMidlandHoustonLLSWTIMidlandHoustonLLS
Crude Oil,Crude OilCrude Oil,Crude Oil,Crude OilCrude Oil,
$/barrel$/barrel
(1)(2)(3)
2018 by quarter: 
1st Quarter$62.87$62.51$65.47         $65.79
2nd Quarter$67.88$59.93$72.38$72.97
3rd Quarter$69.50$55.28$73.67$74.28
4th Quarter$58.81$53.64$66.34          $66.20
2018 Averages$64.77$57.84$69.47$69.81
 (1)(2)(3)
2019 by quarter:  
1st Quarter$54.90$53.70$61.19$62.35$54.90$53.70$61.19$62.35
2nd Quarter$59.81$57.62$66.47$67.07$59.81$57.62$66.47$67.07
3rd Quarter$56.45$56.12$59.75$60.64$56.45$56.12$59.75$60.64
4th Quarter$56.96$57.80$60.04 $60.76
2019 Averages$57.05$55.81$62.47$63.35$57.03$56.31$61.86$62.71
 
2020 by quarter: 
1st Quarter$46.17$45.51$47.81$48.15

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

The decline in commodity prices since the beginning of 2020 is attributable to the ongoing effects of the COVID-19 pandemic and, with respect to crude oil, the recent oil price dispute between Saudi Arabia and Russia.  See “Update on 2020 Outlook – Coronavirus and Oil Price Shock” within this Item 2 for information regarding these events.
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Fluctuations in our consolidated revenues and cost of sales amounts are explained in large part by changes in energy commodity prices, which fluctuate for a variety of reasons including supply and demand imbalances and geopolitical tensions.  The weighted-average indicative market price for NGLs was $0.39 per gallon in the third quarter of 2019 versus $0.82 per gallon during the third quarter of 2018.  Likewise, the weighted-average indicative market price for NGLs was $0.48 per gallon during the nine months ended September 30, 2019 compared to $0.72 per gallon during the same period in 2018.

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 1314 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report for information regarding our commodity hedging activities.

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Income Statement Highlights

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

  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2019  2018  2019  2018 
Revenues $7,964.1  $9,585.9  $24,783.9  $27,351.9 
Costs and expenses:                
Operating costs and expenses:                
Cost of sales  5,276.5   6,838.9   16,721.5   20,371.2 
Other operating costs and expenses  790.8   735.7   2,243.4   2,143.1 
Depreciation, amortization and accretion expenses  467.1   429.4   1,380.8   1,249.0 
Net gains attributable to asset sales  (0.1)  (6.7)  (2.6)  (8.1)
Asset impairment and related charges  39.4   4.6   51.2   21.4 
Total operating costs and expenses  6,573.7   8,001.9   20,394.3   23,776.6 
General and administrative costs  55.5   52.7   160.2   157.1 
Total costs and expenses  6,629.2   8,054.6   20,554.5   23,933.7 
Equity in income of unconsolidated affiliates  139.3   112.0   431.3   350.0 
Operating income  1,474.2   1,643.3   4,660.7   3,768.2 
Interest expense  (382.9)  (279.5)  (950.2)  (806.2)
Change in fair market value of Liquidity Option Agreement  (38.7)  (18.5)  (123.1)  (34.9)
Gain on step acquisition of unconsolidated affiliate  –   –   –   39.4 
Other, net  7.6   0.3   11.7   1.3 
Provision for income taxes  (15.4)  (11.0)  (37.4)  (34.5)
Net income  1,044.8   1,334.6   3,561.7   2,933.3 
Net income attributable to noncontrolling interests  (25.6)  (21.4)  (67.3)  (45.6)
Net income attributable to limited partners $1,019.2  $1,313.2  $3,494.4  $2,887.7 

  
For the Three Months
Ended March 31,
 
  2020  2019 
Revenues $7,482.5  $8,543.5 
Costs and expenses:        
Operating costs and expenses:        
Cost of sales  4,823.0   5,835.6 
Other operating costs and expenses  752.8   728.8 
Depreciation, amortization and accretion expenses  482.8   450.9 
Net losses (gains) attributable to asset sales  0.1   (0.4)
Asset impairment and related charges  1.6   4.8 
Total operating costs and expenses  6,060.3   7,019.7 
General and administrative costs  55.5   52.2 
Total costs and expenses  6,115.8   7,071.9 
Equity in income of unconsolidated affiliates  140.8   154.6 
Operating income  1,507.5   1,626.2 
Interest expense  (317.5)  (277.2)
Change in fair value of Liquidity Option  (2.3)  (57.8)
Other, net  8.1   1.5 
Benefit from (provision for) income taxes  179.2   (12.3)
Net income  1,375.0   1,280.4 
Net income attributable to noncontrolling interests  (24.9)  (19.9)
Net income attributable to limited partners $1,350.1  $1,260.5 

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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 September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended March 31,
 
 2019  2018  2019  2018  2020  2019 
NGL Pipelines & Services:                  
Sales of NGLs and related products $2,624.9  $3,898.2  $7,955.5  $9,324.5  $2,419.2  $2,671.2 
Midstream services  627.2   724.7   1,895.7   1,985.4   548.9   643.2 
Total  3,252.1   4,622.9   9,851.2   11,309.9   2,968.1   3,314.4 
Crude Oil Pipelines & Services:                        
Sales of crude oil  2,130.0   2,209.0   6,990.1   8,082.9   1,696.9   2,328.4 
Midstream services  348.3   285.9   962.1   764.1   342.0   278.9 
Total  2,478.3   2,494.9   7,952.2   8,847.0   2,038.9   2,607.3 
Natural Gas Pipelines & Services:                        
Sales of natural gas  440.0   589.0   1,627.1   1,681.5   399.2   655.7 
Midstream services  275.5   261.2   835.2   766.3   271.4   271.8 
Total  715.5   850.2   2,462.3   2,447.8   670.6   927.5 
Petrochemical & Refined Products Services:                        
Sales of petrochemicals and refined products  1,299.0   1,408.9   3,867.3   4,111.6   1,597.5   1,480.6 
Midstream services  219.2   209.0   650.9   635.6   207.4   213.7 
Total  1,518.2   1,617.9   4,518.2   4,747.2   1,804.9   1,694.3 
Total consolidated revenues $7,964.1  $9,585.9  $24,783.9  $27,351.9  $7,482.5  $8,543.5 


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Third Quarter of 2019 Compared to Third Quarter of 2018.  Total revenues for the thirdfirst quarter of 20192020 decreased $1.62$1.06 billion when compared to the thirdfirst quarter of 20182019 primarily due to a net $1.61$1.02 billion decrease in marketing revenues.  Revenues from the marketing of NGLs, petrochemicalscrude oil and refined productsnatural gas decreased a combined net $1.38 billion$888.0 million quarter-to-quarter primarily due to lower sales prices, which accounted for a $2.04 billion$610.0 million decrease, and lower sales volumes, which accounted for an additional $278.0 million decrease.  Revenues from the marketing of NGLs decreased a net $252.0 million quarter-to-quarter primarily due to lower sales prices, which accounted for a $962.4 million decrease, partially offset by the effects of higher sales volumes, which resulted in a $657.3$710.4 million increase.  Revenues from the marketing of natural gas decreased $149.0 million quarter-to-quarter primarily due to lower sales prices.  Revenues from the marketing of crude oil decreasedpetrochemicals and refined products increased a net $79.0 million quarter-to-quarter primarily due to lower sales prices, which accounted for a $429.9 million decrease, partially offset by higher sales volumes, which resulted in a $350.9 million increase.

Revenues from midstream services for the third quarter of 2019 decreased $10.6 million when compared to the third quarter of 2018.  Revenues from our natural gas processing plants decreased $125.5 million quarter-to-quarter primarily due to lower market values for the equity NGLs we receive as non-cash consideration for providing processing services to certain customers, which accounted for a $151.1 million decrease, partially offset by contributions from our recently completed Orla facility, which accounted for a $22.7 million increase.  We recognize revenues related to the equity NGLs we receive under commodity-based contracts (once the processing service has been performed and we are entitled to such volumes) at market value.

Midstream service revenues from our pipeline assets increased $48.5 million quarter-to-quarter primarily due to contributions from our Midland-to-ECHO 2 pipeline, which commenced operations in February 2019.  Revenues from our terminal assets increased $39.5 million quarter-to-quarter primarily due to an increase in loading volumes at EHT.

Lastly, revenues from our Mont Belvieu storage complex increased a combined $27.7$116.9 million quarter-to-quarter primarily due to higher storage, throughput and other fees.

Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018.  Total revenues for the nine months ended September 30, 2019 decreased $2.57 billion when compared to the nine months ended September 30, 2018 primarily due to a $2.76 billion decrease in marketing revenues.  Revenues from the marketing of NGLs, petrochemicals and refined products decreased a combined net $1.61 billion period-to-period primarily due to lower sales prices, which accounted for a $3.15 billion decrease, partially offset by higher sales volumes, which resulted in a $1.54 billion increase.  Revenues from the marketing of crude oil decreased $1.09 billion period-to-period primarily due to lower sales volumes, which accounted for a $906.0$197.1 million decrease, andincrease, partially offset by lower sales prices, which resulted in an additional $186.8$80.2 million decrease.

Revenues from midstream services for the nine months ended September 30, 2019 increased $192.5first quarter of 2020 decreased $37.9 million when compared to the nine months ended September 30, 2018.first quarter of 2019.  Revenues from our pipeline assets increased $234.9 million period-to-period primarily due to strong demand for transportation services in Texas. Our Midland-to-ECHO 1 and 2 pipelines accounted for a combined $160.2 million of this increase.  Revenues from our Mont Belvieu storage complex increased a combined $76.2 million period-to-period primarily due to higher storage, throughput and other fees. In addition, revenues from our terminal assets increased $56.6 million period-to-period primarily due to an increase in loading volumes at EHT. These increases were partially offset by lower revenues from our natural gas processing plants of $188.3facilities decreased a net $45.3 million period-to-periodquarter-to-quarter primarily due to the impact of lower market values forNGL prices in the first quarter of 2020 compared to the first quarter of 2019 on the value of equity NGLs we receive as non-cash consideration which accounted for a $275.3 million decrease, partially offset by contributionsprocessing services.  Revenues from our recently completed Orla facility,Midland-to-ECHO 2 pipeline, which accounted for a $131.8commenced limited service in February 2019 and full service in April 2019, increased $41.0 million increase.quarter-to-quarter.  Lastly, revenues from our Mont Belvieu NGL fractionation complex decreased $35.8 million quarter-to-quarter primarily due to lower fractionation fee revenues from third parties.

Operating costs and expenses

Third Quarter of 2019 Compared to Third Quarter of 2018.  Total operating costs and expenses for the thirdfirst quarter of 20192020 decreased $1.43 billion$959.4 million when compared to the thirdfirst quarter of 20182019 primarily due to lower cost of sales.  The cost of sales associated with our marketing of NGLs, petrochemicalscrude oil and refined productsnatural gas decreased a combined $1.47 billion $703.1 million quarter-to-quarter primarily due to lower purchase prices, which accounted for a $2.06 billion$488.4 million decrease, partially offset by higherand lower sales volumes, which accounted for a $590.4an additional $214.7 million increase. Other operating costs and expenses increased a net $55.1 million quarter-to-quarter primarily due to higher maintenance, power, chemical and employee compensation costs, which accounted for a combined $50.9 million increase.

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Depreciation, amortization and accretion expense increased $37.7 million quarter-to-quarter primarily due to assets placed into service since the third quarter of 2018 (e.g., the Shin Oak and Midland-to-ECHO 2 pipelines). Non-cash asset impairment charges increased $34.8 million quarter-to-quarter primarily due to the planned shutdown of certain natural gas processing plant and pipeline assets in South Texas and South Louisiana.

Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018.  Total operating costs and expenses for the nine months ended September 30, 2019 decreased $3.38 billion when compared to the nine months ended September 30, 2018 primarily due to lower cost of sales.decrease.  The cost of sales associated with our marketing of NGLs, petrochemicals and refined products decreased a combined net $1.77 billion$309.5 million period-to-periodquarter-to-quarter primarily due to lower purchase prices, which accounted for a $3.25$1.02 billion decrease, partially offset by higher sales volumes, which accounted for a $1.48 billion$706.6 million increase.  The cost of sales associated with our marketing of crude oil decreased $1.69 billion period-to-period primarily due to lower purchase prices, which accounted for a $947.3 million decrease, and lower sales volumes, which accounted for an additional $744.7 million decrease.

Other operating costs and expenses for the nine months ended September 30, 2019first quarter of 2020 increased a net $100.3$24.0 million period-to-periodquarter-to-quarter primarily due to higher maintenance and chemical expenses, ad valorem taxes, and employee compensation costs which accounted for a combined $124.0 million increase. These costs were partially offset by $33.9 million of expense recognized in the nine months ended September 30, 2018 in connection with our earnings allocation arrangement with an affiliate of Western Midstream Partners, LP (“Western”) involving the Midland-to-ECHO 1 pipeline.

and ad valorem taxes.  Depreciation, amortization and accretion expense increased $131.8$31.9 million period-to-periodquarter-to-quarter primarily due to assets placed into full or limited service since the thirdfirst quarter of 2018.  Non-cash asset impairment charges increased $29.8 million period-to-period primarily due to2019 (e.g., the planned shutdown isobutane dehydrogenation (“iBDH”) plant, Mentone and Orla facilities and the Enterprise Navigator ethylene terminal).
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General and administrative costs

General and administrative costs for the three and nine months ended September 30, 2019first quarter of 2020 increased $2.83.3 million and $3.1 million, respectively, when compared to the same periods in 2018first quarter of 2019 primarily due to higher employee-related costs.employee compensation costs and professional services expense.

Equity in income of unconsolidated affiliates

Equity income from our unconsolidated affiliates for the three and nine months ended September 30, 2019 increasedfirst quarter of 2020 decreased $27.313.8 million and $81.3 million, respectively, when compared to the same periods in 2018first quarter of 2019 primarily due to increases indecreased earnings from our investments in crude oil pipelines.

Operating income

Operating income for the three and nine months ended September 30, 2019first quarter of 2020 decreased $169.1 118.7 million and increased $892.5 million, respectively, when compared to the same periods in 2018first quarter of 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.




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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 September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended March 31,
 
 2019  2018  2019  2018  2020  2019 
Interest charged on debt principal outstanding $319.3  $296.5  $934.2  $886.3  $331.5  $307.5 
Impact of interest rate hedging program, including related amortization (1)  90.3   (1.7)  97.9   (0.5)  9.6   (1.1)
Interest costs capitalized in connection with construction projects (2)  (33.9)  (28.1)  (102.9)  (113.4)  (30.5)  (36.2)
Other (3)  7.2   12.8   21.0   33.8   6.9   7.0 
Total $382.9  $279.5  $950.2  $806.2  $317.5  $277.2 

(1)
Amount presented for the three and nine months ended September 30,first quarter of 2019 includes $13.3a $9.8 million and $23.1 million, respectively, ofbenefit from swaption premium income. Amount presented for the three and nine months ended September 30, 2018 includes $10.4 million and $29.4 million, respectively, of swaption premium income.  See discussion below for information regarding an unrealized $94.9 million loss related to forward-starting interest rate swaps recorded.
premiums.
(2)We capitalize interest costs incurred on funds used to construct property, plant and equipment while the asset is in its construction phase.  Capitalized interest amounts become part of the historical cost of an asset and are charged to earnings (as a component of depreciation expense) on a straight-line basis over the estimated useful life of the asset once the asset enters its intended service.  When capitalized interest is recorded, it reduces interest expense from what it would be otherwise.  Capitalized interest amounts fluctuate based on the timing of when projects are placed into service, our capital investment levels and the interest rates charged on borrowings.
(3)
Primarily reflects facility commitment fees charged in connection with our revolving credit facilities and amortization of debt issuance costs.Amount presented for the three and nine months ended September 30, 2018 includes $6.4 million and $14.2 million, respectively, of debt issuance costs that were written off in 2018 in connection with the redemption of junior subordinated notes.

Interest charged on debt principal outstanding, which is a key driver of interest expense, increased a net $22.8 24.0 million quarter-to-quarter primarily due to increased debt principal amounts outstanding during the thirdfirst quarter of 2019,2020, which accounted for a $24.131.2 million increase, partially offset by the effect of lower overall interest rates during the thirdfirst quarter of 2019,2020, which accounted for a $1.3 7.2 million decrease.  Our weighted-average debt principal balance for the thirdfirst quarter of 20192020 was $27.93 29.39 billion compared to $26.08$26.76 billion for the thirdfirst quarter of 2018.  For the nine months ended September 30, 2019, interest charged on debt principal outstanding increased a net $47.9 million period-to-period primarily due to increased debt principal amounts outstanding during the nine months ended September 30, 2019, which accounted for a $53.8 million increase, partially offset by the effect of lower overall interest rates during the nine months ended September 30, 2019, which accounted for a $5.9 million decrease.  Our weighted-average debt principal balance for the nine months ended September 30, 2019 was $27.29 billion compared to $25.76 billion for the nine months ended September 30, 2018.2019.  In general, our debt principal balances have increased over time due to the partial debt financing of our capital investments.

In July 2019, we sold options to be put into forward-starting swaps (referred to as “swaptions”) if the market rate of interest fell below the strike rate of the option upon expiration of the derivative instrument.  The premium we realized upon sale of the swaptions is reflected as a $13.3 million reduction in interest expense for the three and nine months ended September 30, 2019, respectively.

Due to declining interest rates, the counterparties to the swaptions sold in July 2019 exercised their right to put us into ten forward-starting swaps on September 30, 2019 having an aggregate notional value of $1.0 billion. 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 debt issuance. Under the terms of the forward-starting swaps, we will pay to the counterparties (at the expected settlement dates of the instruments) amounts based on a 30-year fixed interest rate applied to the notional amount and receive from the counterparties an amount equal to a 30-year variable interest rate on the same notional amount.  On September 30, 2019, the weighted-average fixed interest rate of the ten forward-starting swaps was 2.12%, which was 0.41% higher than the then applicable variable interest rate.  As a result, we incurred an unrealized, mark-to-market loss at inception totaling $94.9 million that is reflected as an increase in interest expense for the three and nine months ended September 30, 2019.  Prospectively, we will account for the forward-starting swaps as cash flow hedges, with any subsequent gains or losses on these derivative instruments reflected as a component of other comprehensive income and be amortized to earnings (through interest expense) over the 30-year period of the associated future debt issuance.
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Although we incurred a loss upon the exercise of these derivative instruments, we believe that the fixed interest rates that we will pay in connection with these forward-starting swaps are very favorable when compared to historical 30-year rates.   Settlement of amounts accrued under the ten forward-starting swaps, including any gains or losses incurred from changes in interest rates between now and the contractual settlement dates, will occur at their respective expiration dates in September 2020 and April 2021.

Change in fair value of Liquidity Option Agreement

We recognize non-cash expense associated with accretion and changes in management estimates that affect our valuation of the Liquidity Option Agreement. For the three and nine months ended September 30, 2019, expense attributable to increases in the fair value of the Liquidity Option Agreement increased $20.2 million and $88.2 million, respectively, when compared to the same periods in 2018.   Expense recognized during the three and nine months ending September 30, 2019 is primarily due to decreases in the applicable midstream industry weighted-average cost of capital, which is used as a discount factor in determining the present value of the liability, since June 30, 2019 and December 31, 2018, respectively. For additional information regarding the Liquidity Option Agreement,our debt obligations, see Note 157 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.

Gain on step acquisitionChange in fair value of unconsolidated affiliateLiquidity Option

Upon our acquisitionFor 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 remaining 50% member interest in Delaware Basin Gas Processing LLC (“Delaware Processing”) in March 2018, our existing equity investment in Delaware Processing was remeasured to fair value resultingLiquidity Option liability.   As discussed in the recognition of a non-cash gain of $39.4 million for the nine months ended September 30, 2018.

following section, Income taxes

Provision for income taxes primarily reflects, our state tax obligations under the Revised Texas Franchise Tax (the “Texas Margin Tax”).  Our provision for income taxes for the three and nine months ended September 30, 2019 increased $4.4 million and $2.9 million, respectively, when compared to the same periods in 2018.  Our partnership is not subject to U.S. federal income tax; however, our partners are individually responsible for paying federal income taxLiquidity Option Agreement were settled on their share of our taxable income.

March 5, 2020.

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

Income taxes

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

On March 5, 2020, we settled the Liquidity Option (see “Other Recent Developments” within this Item 2) and assumed OTA’s deferred tax liability, which mainly comprised the outside basis difference of OTA in the 54,807,352 EPD common units it received in October 2014.  Upon settlement of the Liquidity Option, the Liquidity Option liability was effectively replaced by the deferred tax liability of OTA as calculated in accordance with ASC 740, Income Taxes.  At March 5, 2020, the Liquidity Option liability amount was $511.9 million.  Since the book value of the Liquidity Option liability exceeded OTA’s estimated deferred tax liability of $439.7 million on that date, we recognized a non-cash benefit in earnings of $72.2 million, which is reflected in the “Benefit from (provision for) income taxes” line on our Unaudited Condensed Statement of Consolidated Operations for the three months ended March 31, 2020.  At March 31, 2020, OTA’s deferred tax liability decreased to $324.7 million primarily due to a decline in the fair value of OTA’s assets, which resulted in an additional non-cash benefit of $115.0 million in income tax expense for the first quarter of 2020.

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. 

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 September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended March 31,
 
 2019  2018  2019  2018  2020  2019 
Gross operating margin by segment:                  
NGL Pipelines & Services $1,008.3  $1,063.1  $2,933.8  $2,861.7  $1,042.0  $959.2 
Crude Oil Pipelines & Services  496.2   594.2   1,671.7   867.0   452.9   662.3 
Natural Gas Pipelines & Services  258.5   216.9   824.6   628.2   283.8   264.3 
Petrochemical & Refined Products Services  288.4   249.4   835.9   803.1   278.5   242.6 
Total segment gross operating margin (1)  2,051.4   2,123.6   6,266.0   5,160.0   2,057.2   2,128.4 
Net adjustment for shipper make-up rights  (15.3)  (0.3)  (15.7)  27.6   (9.7)  5.3 
Total gross operating margin (non-GAAP) $2,036.1  $2,123.3  $6,250.3  $5,187.6  $2,047.5  $2,133.7 

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

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

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“Income Statement Highlights”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 September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended March 31,
 
 2019  2018  2019  2018  2020  2019 
Operating income (GAAP) $1,474.2  $1,643.3  $4,660.7  $3,768.2 
Adjustments to reconcile operating income to total gross operating margin
(addition or subtraction indicated by sign):
                
Operating income $1,507.5  $1,626.2 
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  467.1   429.4   1,380.8   1,249.0   482.8   450.9 
Asset impairment and related charges in operating costs and expenses  39.4   4.6   51.2   21.4   1.6   4.8 
Net gains attributable to asset sales in operating costs and expenses  (0.1)  (6.7)  (2.6)  (8.1)
Net losses (gains) attributable to asset sales in operating costs and expenses  0.1   (0.4)
General and administrative costs  55.5   52.7   160.2   157.1   55.5   52.2 
Total gross operating margin (non-GAAP) $2,036.1  $2,123.3  $6,250.3  $5,187.6  $2,047.5  $2,133.7 

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

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

 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended March 31,
 
 2019  2018  2019  2018  2020  2019 
Segment gross operating margin:                  
Natural gas processing and related NGL marketing activities $288.0  $396.8  $829.3  $955.0  $252.3  $292.7 
NGL pipelines, storage and terminals  593.4   513.5   1,739.4   1,488.2   653.3   557.3 
NGL fractionation  126.9   152.8   365.1   418.5   136.4   109.2 
Total $1,008.3  $1,063.1  $2,933.8  $2,861.7  $1,042.0  $959.2 
                        
Selected volumetric data:                        
Equity NGL production (MBPD) (1)  111   139   138   156 
Fee-based natural gas processing (MMcf/d) (2)  5,291   5,080   5,275   4,751 
NGL pipeline transportation volumes (MBPD)  3,557   3,487   3,532   3,396   3,762   3,436 
NGL marine terminal volumes (MBPD)  602   606   590   592   742   540 
NGL fractionation volumes (MBPD)  1,003   989   990   942   1,133   969 
Equity NGL production volumes (MBPD) (1)  140   154 
Fee-based natural gas processing volumes (MMcf/d) (2,3)  4,659   4,758 

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

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Natural gas processing and related NGL marketing activities
Third Quarter of 2019 Compared to Third Quarter of 2018.  Gross operating margin from natural gas processing and related NGL marketing activities for the thirdfirst quarter of 20192020 decreased $108.840.4 million when compared to the thirdfirst quarter of 2018.2019.  Gross operating margin from our RockiesSouth Texas natural gas processing plants (including Meeker, Pioneer and Chaco)facilities decreased a combined $50.4$24.8 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $43.0an $18.6 million decrease, and higher maintenance and other operating costs,lower average processing fees, which accounted for an additional $5.9$5.2 million decrease.  On a combined basis, fee-based natural gas processing volumes at these plants increased 47 MMcf/d and equity NGL production volumes decreased 16 MBPD quarter-to-quarter.

Gross operating margin from our NGL marketing activities decreased a net $27.4 million quarter-to-quarter primarily due to lower average sales margins, which accounted for a $91.0 million decrease, partially offset by higher sales volumes, which accounted for a $63.1 million increase.  Results from marketing strategies that optimize our transportation and plant assets decreased $44.8 million quarter-to-quarter, partially offset by a $21.8 million increase in earnings related to the optimization of our storage and export assets.  In addition, results from NGL marketing decreased $4.4 million quarter-to-quarter due to non-cash, mark-to-market activity.

Gross operating margin from our Louisiana and MississippiRockies natural gas processing plantsfacilities (Meeker, Pioneer and Chaco) decreased $16.0 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities).  Net to our interest, fee-based natural gas processing volumes and equity NGL production volumes for these plants decreased 124 MMcf/d and 12 MBPD, respectively, quarter-to-quarter.

Gross operating margin from our South Texas natural gas processing plants decreaseda combined $11.917.9 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $4.7 million decrease, and lower deficiency fees, which accounted for an additional $4.4 million decrease.  Fee-based natural gas processing volumes and equity NGL production at our South Texas plants decreased 45 MMcf/d and increased 1 MBPD, respectively, quarter-to-quarter.

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Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018.  Gross operating margin from natural gas processing and related NGL marketing activities for the nine months ended September 30, 2019 decreased $125.7 million when compared to the nine months ended September 30, 2018.  Gross operating margin from our Rockies natural gas processing plants decreased a combined $111.2 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities), which accounted for an $80.721.9 million decrease, lowerpartially offset by higher processing and other fees, which accounted for a $20.0 $5.2 million decrease, and lower equity NGL sales volumes, which accounted for an additional $9.9 million decrease.increase.  On a combined basis, fee-based natural gas processing volumes at these plants increased 95 MMcf/d and equity NGL production volumes decreased 181 MMcf/d and 16 MBPD, period-to-period.respectively, quarter-to-quarter.

Gross operating margin from our NGL marketing activities decreased a net $21.2 million period-to-period primarily due to lower average sales margins, which accounted for a $127.0 million decrease, partially offset by higher sales volumes, which accounted for a $104.6 million increase.  Results from marketing strategies that optimize our plant, storage and export assets decreased a combined $17.9 million period-to-period, partially offset by higher earnings from the optimization of our transportation assets, which accounted for a $4.9 million increase.  In addition, results from NGL marketing decreased $8.1 million period-to-period due to non-cash, mark-to-market activity.

Gross operating margin from our Louisiana and MississippiPermian Basin natural gas processing plantsfacilities decreased a net $16.4 $14.4 million period-to-periodquarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $26.5$13.1 million decrease, and higher operating costs, which accounted for an additional $7.6 million decrease, partially offset by higher fee-based natural gas processing volumes, which accounted for an $8.0$11.0 million increase.  Fee-based processing volumes at our Permian Basin natural gas processing facilities increased 273 MMcf/d quarter-to-quarter primarily due to processing volumes contributed by the third processing train at our Orla natural gas processing facility and our Mentone natural gas processing facility, which were placed into service in July 2019 and December 2019, respectively.

Gross operating margin from our Louisiana and Mississippi natural gas processing facilities decreased $5.4 million quarter-to-quarter primarily due to lower average processing margins, which accounted for a $7.7 million decrease, and lower processing volumes, which accounted for an additional $1.5 million decrease, partially offset by higher average processing fees, which accounted for a $3.9 million increase.  Net to our interest, fee-based natural gas processing volumes and equity NGL production volumes increased 239decreased 208 MMcf/d quarter-to-quarter.  Gross operating margin from our Carthage natural gas processing facilities (Panola and 7 MBPD, respectively, period-to-period.Bulldog) decreased $4.1 million quarter-to-quarter primarily due to lower average processing margins.  Fee-based natural gas processing volumes at these facilities increased 70 MMcf/d.

Gross operating margin from our Permian Basin natural gas processing plantsNGL marketing activities increased a net $21.625.5 million period-to-periodquarter-to-quarter primarily due to higher fee-based natural gas processingsales volumes, which accounted for a $46.3$78.7 million increase, partially offset by lower average processing fees,sales margins, which accounted for a $17.5$52.7 million decrease.  Fee-based processing volumes atResults from marketing strategies that optimize our Permian Basin natural gas processing plantsexport, storage and plant assets increased 361 MMcf/d period-to-period primarilya combined $41.5 million quarter-to-quarter, partially offset by lower earnings from the optimization of our transportation assets, which accounted for a $3.4 million decrease.  In addition, results from NGL marketing decreased $12.6 million quarter-to-quarter due to non-cash, mark-to-market losses of $12.2 million in the start-upfirst quarter of our Orla natural gas processing facility.  The first, second and third processing trains at this facility commenced operations in May 2018, October 2018 and July 2019, respectively.2020.

NGL pipelines, storage and terminals
Third Quarter of 2019 Compared to Third Quarter of 2018.  Gross operating margin from our NGL pipelines, storage and terminal assets during the third first quarter of 20192020 increased  $79.9$96.0 million when compared to the third first quarter of 2018. The Shin Oak pipeline generated $37.7 million of gross2019.  Gross operating margin forfrom LPG-related activities at EHT increased $33.0 million quarter-to-quarter primarily due to higher export volumes of 205 MBPD.  The increase in export volumes is attributable to an LPG expansion project at EHT that we completed in the third quarter of 2019 on direct tariff movements of 113 MBPD (net to our interest) and 152 MBPD of offload volumes from affiliate pipelines.  2019. Gross operating margin from our underground storage facilities at the Mont Belvieu hubHouston Ship Channel Pipeline System increased $25.8 $8.2 million quarter-to-quarter primarily due to higher throughput and handling fees, which accounted for a $19.4 million208 MBPD increase and higher storage fees, which accounted for an additional $5.9 million increase.in transportation volumes.

Gross operating margin from our AegisShin Oak NGL Pipeline increased $15.8$24.7 million quarter-to-quarter primarily due to higher direct tariff transportation volumes, which accounted for a $22.4 million increase. Net to our interest, direct tariff movements on the Shin Oak NGL Pipeline increased 26 MBPD quarter-to-quarter.  Gross operating margin from our Chaparral NGL Pipeline increased $14.2 million quarter-to-quarter primarily due to higher transportation volumes of 143 MBPD.43 MBPD, which accounted for a $9.9 million increase, and higher average transportation fees, which accounted for an additional $2.9 million increase. Gross operating margin from our Aegis Pipeline increased $19.0 million quarter-to-quarter primarily due to a 154 MBPD increase in transportation volumes.

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Gross operating margin from our equity investment in the Front Range Pipeline increased $3.9 million quarter-to-quarter primarily due to higher average transportation fees, which accounted for a $2.9 million increase, and higher transportation volumes of 14 MBPD (net to our interest), which accounted for an additional $2.8 million increase.  Gross operating margin from our Morgan’s Point Ethane Export Terminal increased $3.7 million quarter-to-quarter primarily due to lower utility and compensation costs.  Gross operating margin from our Dixie Pipeline and related terminals increased a combined $7.9$3.0 million quarter-to-quarter primarily due to higher transportation volumes of 40 MBPD resulting from a capacity expansion project.  24 MBPD.

Gross operating margin from EHT increased $5.2our Appalachia-to-Texas Express, or “ATEX,” pipeline decreased $10.3 million quarter-to-quarter primarily due to higher exportlower transportation volumes, which increased 21 MBPD.decreased 32 MBPD quarter-to-quarter.

Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018.Gross operating margin from our NGL pipelines, storage and terminal assets during the nine months ended September 30, 2019 increased $251.2 million when compared to the nine months ended September 30, 2018.  Gross operating margin from our Mont Belvieu storage facility increased $92.0decreased $7.4 million period-to-periodquarter-to-quarter primarily due to higher throughput andlower handling fees,fee revenues.

NGL fractionation
Gross operating margin from NGL fractionation during the first quarter of 2020 increased $27.2 million when compared to the first quarter of 2019.  Gross operating margin at our Hobbs NGL fractionator increased $18.5 million quarter-to-quarter primarily due to lower major maintenance costs, which accounted for a $67.7$14.4 million increase, and higher storage fees,fractionation volumes of 18 MBPD, which accounted for an additional $22.2 $3.5 million increase. The Shin Oak pipeline contributed $80.8 millionfirst quarter of gross operating margin in the 2019 period on year-to-date transportation volumes of 111 MBPD of direct tariff movements (net to our interest) and 145 MBPD of offload volumes from affiliate pipelines.

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included downtime for major maintenance activities at Hobbs.  Gross operating margin fromat our Dixie Pipeline and related terminalsNorco NGL fractionator increased a combined $22.8$5.3 million period-to-periodquarter-to-quarter primarily due to lower maintenance and other operating costs, which accounted for an $11.6a $2.5 million increase, and higher transportationfractionation volumes of 2513 MBPD, which accounted for an additional $8.8$2.0 million increase.  Gross operating margin from our Aegis Pipeline increased $20.8 million period-to-period primarily due to higher transportation volumes of 50 MBPD.  Gross operating margin from our South Louisiana NGL Pipeline System increased $12.6 million period-to-period primarily due to a 62 MBPD increase in transportation volumes.

Gross operating margin from LPG activities at EHT increased $11.1 million period-to-period primarily due to higher export volumes of 12 MBPD, which accounted for a $4.6 million increase, and higher average loading fees, which accounted for an additional $3.9 million increase.

NGL fractionation
Third Quarter of 2019 Compared to Third Quarter of 2018.  Gross operating margin from NGL fractionation for the third quarter of 2019 decreased $25.9 million when compared to the third quarter of 2018.  Gross operating margin from our Mont Belvieu NGL fractionation complex decreased $19.1 millionwas essentially flat quarter-to-quarter primarily due to lower product blending revenues, which accounted for a $15.8 million decrease, and higher utility and other operating costs, which accounted for an additional $2.7 million decrease.  Fractionation volumes increased 13 MBPD (net to our interest) quarter-to-quarter.  Gross operating margin from our South Texas NGL fractionators decreased $4.1 million quarter-to-quarter primarily due to major maintenance activities completed at our Shoup fractionator during the third quarter of 2019.  NGL fractionation volumes at our South Texas NGL fractionators decreased 5 MBPD quarter-to-quarter.

Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018.Gross operating margin from NGL fractionation for the nine months ended September 30, 2019 decreased $53.4 million when compared to the nine months ended September 30, 2018.  Gross operating margin at our Hobbs NGL fractionator decreased $26.0 million period-to-period primarily due to the costs of major maintenance activities completed in February 2019, which accounted for a $12.8 million decrease, lower product blending revenues, which accounted for a $7.6 million decrease, and lower fractionation volumes, which accounted for an additional $5.6 million decrease.  NGL fractionation volumes at Hobbs decreased 11 MBPD period-to-period.

Gross operating margin from our Mont Belvieu NGL fractionation complex decreased $12.0 million period-to-period primarily due to lower product blending revenues, which accounted for a $33.2 million decrease, and higher operating costs, which accounted for an additional $17.4 million decrease, partiallybeing nearly offset by the impact of higher fractionation volumes, which accounted for a $43.5$7.4 million increase.  FractionationNGL fractionation volumes increased 29 87 MBPD quarter-to-quarter (net to our interest) period-to-period primarilyin part due to the start-up of our ninth NGL fractionator in May 2018.

Gross operating marginthe first fractionation train at our South Texas NGL fractionators decreased $8.9 million period-to-period primarily due to major maintenance activities at our Shoup fractionator.newly constructed NGL fractionation volumes at our Southfacility located in Chambers County, Texas NGL fractionators decreased 3 MBPD period-to-period.  Our Tebone NGL fractionator, which was restarted in February 2019 in light of regional demand for fractionation services, contributed 17 MBPD of fractionation volumes for the nine months ended September 30, 2019.


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(“Frac X”).

Crude Oil Pipelines & Services

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

 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended March 31,
 
 2019  2018  2019  2018  2020  2019 
Midland-to-ECHO pipeline network:            
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
 $89.3  $94.8  $298.6  $242.7  $60.2  $99.7 
Non-cash mark-to-market gain (loss) attributable to the
Midland-to-ECHO 1 pipeline
  10.0   186.7   91.2   (237.3)
Non-cash mark-to-market gain attributable to the Midland-to-ECHO 1 pipeline  0.9   67.2 
Total Midland-to-ECHO 1 pipeline and related business activities  99.3   281.5   389.8   5.4   61.1   166.9 
Midland-to-ECHO 2 pipeline  27.0   –   72.5   –   29.3   17.4 
Total Midland-to-ECHO pipeline network  126.3   281.5   462.3   5.4 
Total Midland-to-ECHO System  90.4   184.3 
Other crude oil pipelines, terminals and related marketing results  369.9   312.7   1,209.4   861.6   362.5   478.0 
Segment gross operating margin $496.2  $594.2  $1,671.7  $867.0 
Total $452.9  $662.3 
                        
Selected volumetric data:                        
Crude oil pipeline transportation volumes (MBPD)  2,321   1,914   2,315   1,971   2,393   2,227 
Crude oil marine terminal volumes (MBPD)  987   632   972   690   985   886 

Third Quarter
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Table of 2019 Compared to Third Quarter of 2018.  Contents

Gross operating margin from our Crude Oil Pipelines & Services segment for the thirdfirst quarter of 20192020 decreased $98.0$209.4 million when compared to the thirdfirst quarter of 2018.

2019.  Gross operating margin from our Midland-to-ECHO 1 pipeline and related business activities decreased $182.2$105.8 million quarter-to-quarter primarily due to changes inlower non-cash mark-to-market earnings, which wereaccounted for a $10.0$66.3 million gain in the third quarter of 2019 compared to a $186.7decrease, and lower earnings from related marketing activities, which accounted for an additional $44.9 million gain in the third quarter of 2018. Transportation volumes for the Midland-to-ECHO 1 pipeline increased 36 MBPD quarter-to-quarter (net to our interest).decrease.  Gross operating margin from our Midland-to-ECHO 2 pipeline which commenced full commercial service during the second quarter of 2019, was $27.0increased $11.9 million onprimarily due to higher transportation volumes of 211 MBPD.

Mark-to-market earnings attributable to the Midland-to-ECHO 1 pipeline are associated with the hedging 64 MBPD, which accounted for a $22.2 million increase, partially offset by higher operating costs of crude oil market price differentials (basis spreads) between the Midland and Houston markets based on the pipeline’s capacity available to us during the hedged periods. These hedges served to lock in a positive per barrel margin on our anticipated purchases of crude oil at Midland and subsequent anticipated sales to customers in the Houston area.  The mark-to-market gain for the third quarter of 2018 reflected a decrease in the basis spread between the Midland and Houston markets from June 30, 2018 to September 30, 2018 to an average of $13.13 per barrel through 2020 relative to our average hedged amount of $2.66 per barrel through 2020.  At September 30, 2019, there were a limited number of these hedges outstanding. For information regarding our commodity hedging activities, see Note 13 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.$10.6 million.

Gross operating margin from other crude oil marketing activities decreased $35.2$118.0 million quarter-to-quarter primarily due to lower average sales volumes,margins, which accounted for a $20.3$94.9 million decrease, and lower non-cash mark-to-market earnings, which accounted for an additional $13.7$22.8 million decrease. Gross operating margin from our West Texas System increased $12.8 million quarter-to-quarter primarily due to higher transportation volumes of 72 MBPD.  Gross operating margin from our South Texas Crude Oil Pipeline System increased $9.1 million quarter-to-quarter primarily due to higher deficiency fees.  Transportation volumes on the South Texas Crude Oil Pipeline System decreased 10 MBPD quarter-to-quarter.

Gross operating margin from our equity investment in the Seaway Pipeline decreased $16.5 million quarter-to-quarter primarily due to lower average transportation fees, which accounted for a $9.9 million decrease, and lower transportation volumes, which accounted for an additional $8.1 million decrease.  Transportation volumes on the Seaway Pipeline decreased 52 MBPD quarter-to-quarter (net to our interest).    Gross operating margin from our South Texas Crude Oil Pipeline System decreased $9.5 million quarter-to-quarter primarily due to lower deficiency fees in the first quarter of 2020.  Transportation volumes on the South Texas Crude Oil Pipeline System increased $25.010 MBPD quarter-to-quarter.

Gross operating margin from our West Texas System increased $13.4 million quarter-to-quarter primarily due to higher transportation volumes which accounted for a $27.4 million increase, and higher transportation fees, which accounted for an additional $12.5 million increase, partially offset by higher operating costs, which accounted for a $10.6 million decrease. Transportation volumes on the Seaway Pipeline increased 130 MBPD quarter-to-quarter (net to our interest) primarily due to an expansion of the Longhaul System that was completed in the first quarter of 2019.

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74 MBPD.  Lastly, gross operating margin from crude oil activities at EHT increased $32.4$15.4 million quarter-to-quarter primarily due to higher net export volumes of 25264 MBPD.

Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018.Gross operating margin from our Crude Oil Pipelines & Services segment for the nine months ended September 30, 2019 increased $804.7 million when compared to the nine months ended September 30, 2018.

Gross operating margin from our Midland-to-ECHO 1 pipeline and related business activities increased $384.4 million period-to-period primarily due to changes in non-cash mark-to-market earnings, which were a $91.2 million gain in the nine months ended September 30, 2019 compared to a $237.3 million loss in the nine months ended September 30, 2018.  As discussed earlier, mark-to-market earnings attributable to the Midland-to-ECHO 1 pipeline are associated with the hedging of crude oil market price differentials (basis spreads) between the Midland and Houston area markets.  Gross operating margin for the nine months ended September 30, 2018 was also reduced by $33.9 million in connection with the expected allocation of pipeline earnings to Western upon closing of their acquisition of a 20% ownership interest in Whitethorn Pipeline Company LLC (“Whitethorn”) in June 2018.  Transportation volumes for the Midland-to-ECHO 1 pipeline increased 47 MBPD period-to-period (net to our interest). Gross operating margin from our Midland-to-ECHO 2 pipeline was $72.5 million on transportation volumes of 195 MBPD.

Gross operating margin from other crude oil marketing activities increased $115.6 million period-to-period primarily due to higher average sales margins, which accounted for an $82.4 million increase, and higher non-cash mark-to-market earnings, which accounted for an additional $34.0 million increase.  These marketing activities benefitted from higher market price differentials for crude oil between the Permian Basin region, Cushing hub and Gulf Coast markets.  Gross operating margin from our West Texas System and equity investment in the Eagle Ford Crude Oil Pipeline System increased a combined $68.2 million period-to-period primarily due to higher transportation volumes of 70 MBPD (net to our interest).  Gross operating margin at our South Texas Crude Oil Pipeline System increased $14.3 million period-to-period primarily due to higher deficiency fees.  Transportation volumes on the South Texas Crude Oil Pipeline System decreased 11 MBPD period-to-period.

Gross operating margin from our equity investment in the Seaway Pipeline increased $67.8 million period-to-period primarily due to higher transportation volumes, which accounted for a $47.7 million increase, and higher transportation fees, which accounted for an additional $46.4 million increase, partially offset by higher operating costs, which accounted for a $29.6 million decrease. Transportation volumes on the Seaway Pipeline increased 75 MBPD period-to-period (net to our interest). Volumes at Seaway’s Texas City and Freeport marine terminals decreased a combined 36 MBPD (net to our interest) period-to-period.

Lastly, gross operating margin from crude oil activities at EHT increased $65.4 million period-to-period primarily due to higher net export volumes of 258 MBPD.


Natural Gas Pipelines & Services

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

For the Three Months
Ended March 31,
 
 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 2020 2019 
 2019  2018  2019  2018     
Segment gross operating margin $258.5  $216.9  $824.6  $628.2  $283.8  $264.3 
                        
Selected volumetric data:                        
Natural gas pipeline transportation volumes (BBtus/d)  14,474   14,040   14,341   13,594   13,854   14,197 

Third Quarter of 2019 Compared to Third Quarter of 2018. Gross operating margin from our Natural Gas Pipelines & Services segment for the thirdfirst quarter of 20192020 increased $41.6$19.5 million when compared to the thirdfirst quarter of 2018.

2019.  Gross operating margin from our natural gas marketing activities increased $36.1$31.6 million quarter-to-quarter primarily due to higher average sales margins that benefited from regional natural gas price spreads across Texas.
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Gross operating margin from our Acadian Gas System increased $7.4 million quarter-to-quarter primarily due to a $10.4 million benefit recognized in the third quarter of 2019 in connection with proceeds received from a legal settlement. Gross operating margin from our Permian Basin Gathering System increased $7.0 million quarter-to-quarter primarily due to higher gathering volumes, which accounted for a $3.4 million increase, and higher condensate sales, which accounted for an additional $3.3 million increase.  Gathering volumes for the Permian Basin system increased 315 BBtus/d quarter-to-quarter. Pipeline volumes for the remaining natural gas pipeline systems increased 138 BBtus/d quarter-to-quarter.

Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018.Gross operating margin from our Natural Gas Pipelines & Services segment for the nine months ended September 30, 2019 increased $196.4 million when compared to the nine months ended September 30, 2018.  Gross operating margin from our natural gas marketing activities increased $129.1 million period-to-period primarily due to higher average sales margins attributable to regional natural gas price spreads.

Gross operating margin from our Texas Intrastate System increased $57.3 million period-to-period primarily due to higher capacity reservation fees.  Transportation volumes on our Texas Intrastate System increased 191 BBtus/d.  Gross operating margin from our Acadian Gas System increased $19.9 million period-to-period primarily due to the aforementioned legal settlement, which accounted for $10.4 million of the increase, and higher capacity reservation fees on the Haynesville Extension, which accounted for an additional $9.7 million increase.non-cash mark-to-market earnings.

Gross operating margin from our Permian Basin Gathering System increased $13.8$10.9 million period-to-periodquarter-to-quarter primarily due to an increase inhigher condensate sales, which accounted for an $11.2a $7.2 million increase, and higher gatheringa 306 BBtus/d increase in natural gas volumes, which accounted for an additional $10.9$5.5 million increase, partially offset by higher operating costs, which accounted for an $8.9 million decrease.  Natural gas gathering volumes on the Permian Basin Gathering System increased 381 BBtus/d. increase.

Gross operating margin from our Haynesville Gathering System increased $12.3decreased $13.2 million period-to-periodquarter-to-quarter primarily due to lower gathering, compression and other fee revenues, which accounted for a 237$10.0 million decrease, and lower gathering volumes of 245 BBtus/d, increase in gathering volumes.  which accounted for an additional $3.9 million decrease.

Gross operating margin from our San Juan GatheringTexas Intrastate System decreased $15.6$8.8 million period-to-periodquarter-to-quarter primarily due to a 105lower capacity reservation fees.  Transportation volumes on our Texas Intrastate System increased 31 BBtus/d decrease in gathering volumes, which accounted for an $8.2 million decrease, and lower condensate sales, which accounted for an additional $4.0 million decrease.d.

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Petrochemical & Refined Products Services 

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

 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended March 31,
 
 2019  2018  2019  2018  2020  2019 
Segment gross operating margin:                  
Propylene production and related marketing activities $130.8  $94.3  $366.8  $350.2 
Butane isomerization and related DIB operations  15.5   29.4   60.7   80.2 
Octane enhancement and related operations  54.6   40.3   131.4   122.2 
Propylene production and related activities $108.6  $102.3 
Butane isomerization and related operations  16.1   24.0 
Octane enhancement and related plant operations  69.0   24.3 
Refined products pipelines and related activities  74.4   78.1   241.6   231.1   75.1   81.9 
Marine transportation and other  13.1   7.3   35.4   19.4 
Marine transportation and other services  9.7   10.1 
Total $288.4  $249.4  $835.9  $803.1  $278.5  $242.6 
                        
Selected volumetric data:                        
Propylene production volumes (MBPD)  105   93   99   97   98   90 
Butane isomerization volumes (MBPD)  109   105   110   111   105   111 
Standalone DIB processing volumes (MBPD)  103   100   97   89   105   93 
Octane additive and related plant production volumes (MBPD)  28   29   28   28 
Pipeline transportation volumes, primarily refined products and
 petrochemicals (MBPD)
  747   796   742   806 
Refined products and petrochemical marine terminal volumes (MBPD)  297   289   344   336 
Octane enhancement and related plant sales volumes (MBPD) (1)  34   24 
Pipeline transportation volumes, primarily refined products & petrochemicals (MBPD)  712   810 
Marine terminal volumes, primarily refined products and petrochemicals (MBPD)  271   338 


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(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 marketing activities
Third Quarter of 2019 Compared to Third Quarter of 2018.  Gross operating margin from propylene production and related marketing activities for the third first quarter of 20192020 increased $36.5$6.3 million when compared to the third first quarter of 2018.2019.  Gross operating margin from our Mont Belvieu propylene splitters increased $20.6 million quarter-to-quarter primarily due to higher propylene sales volumes.  Gross operating margin from our initial propane dehydrogenation (“PDH 1”) facility increased $17.2$12.2 million primarily due to higher propylene and associated by-product sales volumes.  Propylene production volumes from our splitter units and PDH facility increased a combined 12 MBPD quarter-to-quarter.

Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018.Gross operating margin from propylene production and related marketing activities for the nine months ended September 30, 2019 increased $16.6 million when compared to the nine months ended September 30, 2018.  Gross operating margin from our PDH facility, which commenced commercial operations in April 2018, increased $39.0 million period-to-periodquarter-to-quarter primarily due to higher propylene and associated by-product sales volumes.  Plant production for the PDH facility,1, which includes by-products, increased 5 MBPD period-to-period.  quarter-to-quarter.  Gross operating margin from our Mont Belvieu propylene splitters decreased $23.9$3.6 million period-to-periodquarter-to-quarter primarily due to lower average propylene fractionation fees, which accounted for a $14.4 million decrease, and lower propylene production volumes, which accounted for an additional $8.0 million decrease.higher major maintenance costs incurred during the first quarter of 2020. Propylene production volumes from our splitter units decreasedincreased 3 MBPD (net to our interest).

Butane isomerizationIsomerization and related DIB operations
Third Quarter of 2019 Compared to Third Quarter of 2018.  Gross operating margin from butane isomerization and deisobutanizer (“DIB”)related operations for the third quarter of 2019 decreased $13.9$7.9 million when compared to the third quarter of 2018quarter-to-quarter primarily due to lower average by-product sales prices, which accounted for a $6.5 million decrease, and higher maintenance and other operating costs at our isomerization facility, which accounted for an additional $3.1 million decrease.

Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018.Gross operating margin from butane isomerization and DIB operations for the nine months ended September 30, 2019 decreased $19.5 million when compared to the nine months ended September 30, 2018 primarily due to lower average by-product sales prices, which accounted for a $15.2 million decrease, and higher maintenance and other operating costs, which accounted for an additional $6.3 million decrease.prices.

Octane enhancement and related plant operations
Third Quarter of 2019 Compared to Third Quarter of 2018.  Gross operating margin from our octane enhancement and related plant operations, which includes our recently completed iBDH facility, and high purity isobutylene plant for the third quarter of 2019 increased $14.3$44.7 million when compared to the third quarter of 2018quarter-to-quarter primarily due to higher average sales margins.

Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018.Gross operating margin from our octane enhancement facilityvolumes, which accounted for a $26.0 million increase, and high purity isobutylene plant for the nine months ended September 30, 2019 increased $9.2 million when compared to the nine months ended September 30, 2018 primarily due to higher average sales margins.margins, which accounted for an additional $24.1 million increase, partially offset by higher operating expenses, which accounted for a $6.5 million decrease.

Refined products pipelines and related activities
Third Quarter of 2019 Compared to Third Quarter of 2018.  Gross operating margin from refined products pipelines and related marketing activities forduring the thirdfirst quarter of 20192020 decreased $3.7$6.8 million when compared to the thirdfirst quarter of 2018.2019 primarily due to lower storage revenues from our refined products terminal in Beaumont, Texas.  Terminaling volumes at Beaumont decreased a net 36 MBPD quarter-to-quarter.

Marine transportation and other services
Gross operating margin from marine transportation and other services during the first quarter of 2020 decreased $0.4 million when compared to the first quarter of 2019.   Gross operating margin from our refined products marine terminal located on the Neches River near Beaumont, Texas decreased $4.3transportation business increased $2.1 million quarter-to-quarter primarily due to higher operating costs, which accounted for a $2.1 million decrease, and lower storage fee revenues, which accounted for an additional $1.4 million decrease.

Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018.Gross operating margin from refined products pipelines and related marketing activities for the nine months ended September 30, 2019 increased $10.5 million when compared to the nine months ended September 30, 2018.day rates.  Gross operating margin from our refined products marketing activities increased $9.3ethylene export terminal and related operations was a $2.7 million period-to-period primarilyloss in the first quarter of 2020 due to higher average sales margins.

operating expenses incurred for the start-up of our ethylene export terminal, which was placed into limited service in December 2019.
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Marine transportation and other
Third Quarter of 2019 Compared to Third Quarter of 2018.  Gross operating margin from marine transportation for the third quarter of 2019 increased $5.8 million when compared to the third quarter of 2018 primarily due to higher barge fees quarter-to-quarter.

Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018.Gross operating margin from marine transportation for the nine months ended September 30, 2019 increased $16.0 million when compared to the nine months ended September 30, 2018 primarily due to higher barge fees period-to-period, which accounted for $23.5 million of the increase, partially offset by higher operating costs, which accounted for an $8.0 million decrease.


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 expendituresinvestments and working capital needs for the reasonably foreseeable future.  At September 30, 2019,March 31, 2020, we had $6.21 $7.0 billion of consolidated liquidity, which was comprised of $5.0 $5.0 billion of available borrowing capacity under EPO’s revolving credit facilities and $$2.0 1.21 bbillionillion of unrestricted cash on hand.  On October 15, 2019, we repaid $800.0 million principal amountApril 3, 2020, our liquidity position was enhanced when EPO entered into its April 2020 364-Day Credit Agreement, which provides EPO with an incremental $1.0 billion of borrowing capacity (see “Other Recent Developments” within this Item 2).  EPO’s Senior Notes LL at their maturity using unrestricted cash.aggregate borrowing capacity under its revolving credit facilities, including that of the April 2020 364-Day Credit Agreement, is now $6.0 billion.

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

Common Unit Repurchases under 2019 Buyback Program

In JanuaryEPD repurchased 6,357,739 common units under its 2019 Buyback Program through open market purchases in the Board approvedfirst quarter of 2020.  The total purchase price of these repurchases (including commissions and fees) was $140.1 million, and represented 1.9% of our consolidated CFFO for the twelve months ended March 31, 2020. The repurchased units were cancelled immediately upon acquisition. As of March 31, 2020, the remaining available capacity under the 2019 Buyback Program which authorized the partnershipwas $1.78 billion.

In addition to repurchase up to $2.0 billion of EPD’s common units.  For additional information regarding the 2019 Buyback Program, see “Significant Recent Developments” within this Part I, Item 2.  No repurchasesprivately held affiliates of EPCO acquired 1,459,000 of EPD’s common units on the open market during the first quarter of 2020.  In the aggregate, 7,816,739 common units were made under this programpurchased on the open market during the thirdfirst quarter of 2019.2020 under the 2019 Buyback Program and by privately held affiliates of EPCO.

Consolidated Debt

The following table presents scheduled maturities of our consolidated debt obligations outstanding at September 30, 2019March 31, 2020 for the years indicated (dollars in millions):

     Scheduled Maturities of Debt 
  Total  
Remainder
of 2019
  2020  2021  2022  2023  Thereafter 
Principal amount of senior and junior debt obligations at
    September 30, 2019
 $28,196.4  $800.0  $1,500.0  $1,325.0  $1,400.0  $1,250.0  $21,921.4 
     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 

In October 2019, we repaid $800.0At March 31, 2020, there were no borrowings outstanding under EPO’s revolving credit facilities.

As discussed under “Other Recent Developments” within this Item 2, EPO issued $3.0 billion aggregate principal amount of senior notes in January 2020.  The net proceeds from this debt offering were used (i) to repay $500 million principal amount of senior notes maturing in January 2020, (ii) for the temporary repayment of amounts outstanding under EPO’s Senior Notes LL at their maturity using unrestricted cash on hand.commercial paper program and (iii) for general company purposes.  In addition, net proceeds from the January 2020 senior notes offering will be used for the repayment of $1.0 billion principal amount of senior notes maturing in September 2020.






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Amendment to Multi-Year Revolving Credit Agreement
In September 2019, EPO entered into an amendment (the “First Amendment”) to its revolving credit agreement dated September 13, 2017 (the “Multi-Year Revolving Credit Agreement”).  The First Amendment reduces the borrowing capacity under the Multi-Year Revolving Credit Agreement from $4.0 billion to $3.5 billion (which may be increased by up to $500 million to $4.0 billion at EPO’s election provided certain conditions are met) and extends the maturity date to September 10, 2024, although the maturity date may be extended further at EPO’s request by up to two years, with the consent of required lenders as set forth under the credit agreement.  Borrowings under this revolving credit agreement may be used for working capital, capital expenditures, acquisitions and general company purposes.  There are currently no principal amounts outstanding under this revolving credit agreement.

Renewal of 364-Day Revolving Credit Agreement
In September 2019, EPO entered into a 364-Day Revolving Credit Agreement that replaced its prior 364-day credit facility.  The new 364-Day Revolving Credit Agreement matures in September 2020. Under the terms of the new 364-Day Revolving Credit Agreement, EPO may borrow up to $1.5 billion (which may be increased by up to $200 million to $1.7 billion at EPO’s election, provided certain conditions are met) at a variable interest rate for a term of up to 364 days, subject to the terms and conditions set forth therein.  To the extent that principal amounts are outstanding at the maturity date, EPO may elect to have the entire principal balance then outstanding continued as non-revolving term loans for a period of one additional year, payable in September 2021. Borrowings under this revolving credit agreement may be used for working capital, capital expenditures, acquisitions and general company purposes.  There are currently no principal amounts outstanding under this revolving credit agreement.

Issuance of $2.5 Billion of Senior Notes in July 2019
In July 2019, EPO issued $2.5 billion aggregate principal amount of senior notes comprised of $1.25 billion principal amount of senior notes due July 2029 (“Senior Notes YY”) and $1.25 billion principal amount of senior notes due January 2050 (“Senior Notes ZZ”).  Net proceeds from this offering were used by EPO for the repayment of debt and for general company purposes, including for growth capital expenditures.

Senior Notes YY were issued at 99.955% of their principal amount and have a fixed interest rate of 3.125% per year.  Senior Notes ZZ were issued at 99.792% of their principal amount and have a fixed interest rate of 4.20% per year.

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

Credit Ratings

At NovemberAs of May 8, 2019,2020, 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.

Issuance of Common Units

On March 5, 2020, we settled our obligations under DRIPthe Liquidity Option Agreement. As a result, EPD issued 54,807,352 of its common units to Skyline and EUPPindirectly 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 issued and delivered a combined 2,897,990 common unitshas registration statements on file with the SEC in the six months ended June 30, 2019 in connection with its distribution reinvestment plan (“DRIP”) and employee unit purchase plan (“EUPP”). In total, the net cash proceeds EPD received from these issuances was $82.2 million.

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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.  In August 2019,February 2020, a total of 1,422,063 1,410,020 common units were purchased on the open market and delivered to participants in connection with the DRIP and EUPP.  Other than amounts tiedApart from $0.5 million attributable to the plan discount available to all participants in the EUPP, the funds used to effect these purchases were sourced entirely 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 NovemberMay 12, 2019.2020.

For additional information regarding EPD’s issuance ofEPD issued and delivered a combined 1,516,779 common units underin the first quarter of 2019 in connection with the DRIP and EUPP, registration statements, see Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.which generated net cash proceeds totaling $42.7 million.

Cash Flows from Operating, InvestingDistributions

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

In light of current economic conditions, management will evaluate future cash distributions in 2020 on a quarterly basis.  The payment of any quarterly cash distribution is subject to Board approval and Financing Activitiesmanagement’s evaluation of our financial condition, results of operations and cash flows in connection with such payments.












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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 Nine Months
Ended September 30,
  
For the Three Months
Ended March 31,
 
 2019  2018  2020  2019 
Net cash flows provided by operating activities $4,826.2  $4,275.3  $2,012.2  $1,160.4 
Cash used in investing activities  3,372.8   3,182.8   1,071.7   1,174.5 
Cash used in financing activities  655.7   883.7 
Cash provided by (used in) financing activities  765.1   (288.5)

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 20182019 Form 10-K.10-K and Part II, Item 1A of this quarterly report.

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

Operating activities
Net cash flows provided by operating activities for the nine months ended September 30, 2019first quarter of 2020 increased a net $550.9851.8 million when compared to the nine months ended September 30, 2018first quarter of 2019 primarily due to:

a $901.5 million quarter-to-quarter increase primarily due to the timing of cash receipts and payments related to operations; partially offset by

•
a $$37.6612.5 m million period-to-period increaseillion quarter-to-quarter decrease resulting from higher year-to-datelower partnership earnings in 2019the first quarter of 2020 when compared to the same nine month period in 2018first quarter of 2019 (determined by adjusting our $628.4$94.6 million period-to-periodquarter-to-quarter increase in net income for changes in the non-cash items identified on our Unaudited Condensed Statements of Consolidated Cash Flows).

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

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

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

a $25.8 million quarter-to-quarter decrease in investments in unconsolidated affiliates primarily related to NGL and crude oil pipeline projects.




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Financing activities
Cash provided by financing activities for the first quarter of 2020 was $765.1 million compared to cash used in financing activities of $288.5 million in the first quarter of 2019.  The $1.05 billion quarter-to-quarter change in cash flow from financing activities was primarily due to:

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

•
an $85.588.5 million period-to-periodquarter-to-quarter increase in cash distributions received on earnings from unconsolidated affiliates primarily dueused to investments in crude oil pipeline businesses; partially offset byacquire common units under our 2019 Buyback Program;

•
a $147.142.7 million period-to-period decrease primarily due to the timing of cash receipts and payments related to operations.

For information regarding significant changes in our consolidated net income and underlying segment results, see “Results of Operations” within this Part I, Item 2.
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Investing activities
Cash used in investing activities for the nine months ended September 30, 2019 increased a net $190.0 million when compared to the nine months ended September 30, 2018 primarily due to:

•
a $297.9 million period-to-period increase in expenditures for consolidated property, plant and equipment (see “Capital Investments” within this Part I, Item 2 for additional information); partially offset by

•
a $150.6 million decrease period-to-period in net cash used for business combinations.  In March 2018, we paid $150.6 million to acquire a 50% equity interest in Delaware Processing.

Financing activities
Cash used in financing activities for the nine months ended September 30, 2019 decreased $228.0 million when compared to the nine months ended September 30, 2018 primarily due to:

•
a net $430.1 million period-to-period increase in net cash inflows from debt.  In the nine months ended September 30, 2019, we issued $2.5 billion aggregate principal amount of senior notes, partially offset by the repayment or repurchase of $724.2 million principal amount of senior and junior subordinated notes.  In the nine months ended September 30, 2018, we issued $2.7 billion aggregate principal amount of senior notes and junior subordinated notes and $950.2 million of short-term notes under EPO’s commercial paper program, partially offset by the repayment of $2.3 billion in principal amount of senior and junior subordinated notes; and

•
a $368.8 million period-to-period increase in cash contributions from noncontrolling interests.  In July 2019, Altus acquired a noncontrolling 33% equity interest in our consolidated subsidiary that owns the Shin Oak pipeline for an initial payment of $440.7 million.  In June 2019, an affiliate of American Midstream, LP acquired a noncontrolling 25% equity interest in our consolidated subsidiary that owns the Pascagoula natural gas processing plant for $36.0 million in cash.  In June 2018, Western acquired a noncontrolling 20% equity interest in our consolidated subsidiary that owns the Midland-to-ECHO 1 pipeline for $189.6 million in cash.  In addition, cash contributions from noncontrolling interests in connection with the construction of our ethylene export facility increased $47.0 million period-to-period; partially offset by

•
a $367.2 million period-to-periodquarter-to-quarter decrease in net cash proceeds from the issuance of common units in connection with ourthe 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;

•
ana $88.229.6 million period-to-periodquarter-to-quarter decrease in cash contributions from noncontrolling interests. Cash contributions from noncontrolling interests in connection with the construction of our ethylene export facility decreased $31.5 million quarter-to-quarter; and

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

•
the use of $81.1 million in the nine months ended September 30, 2019 to acquire 2,909,128 common units under the 2019 Buyback Program.

Non-GAAP Cash Flow Measures

Distributable Cash Flow
Our partnership agreement requires us to make quarterly distributions to our unitholders of all available cash, after any cash reserves established by Enterprise GP in its sole discretion.  Cash reserves include those for the proper conduct of our business, including those for capital expenditures,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
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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 the previous section titled “Cash Flows from Operating, Investing and Financing Activities”“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 September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended March 31,
 
 2019  2018  2019  2018  2020  2019 
Net income attributable to limited partners (GAAP) (1) $1,019.2  $1,313.2  $3,494.4  $2,887.7  $1,350.1  $1,260.5 
Adjustments to net income attributable to limited partners to derive DCF
(addition or subtraction indicated by sign):
                        
Depreciation, amortization and accretion expenses  493.6   457.0   1,456.7   1,330.8   509.0   474.5 
Cash distributions received from unconsolidated affiliates (2)  170.6   139.2   485.1   392.7   137.2   143.5 
Equity in income of unconsolidated affiliates  (139.3)  (112.0)  (431.3)  (350.0)  (140.8)  (154.6)
Change in fair market value of derivative instruments  85.8   (204.1)  2.0   254.9   (29.5)  (96.3)
Change in fair value of Liquidity Option Agreement  38.7   18.5   123.1   34.9 
Gain on step acquisition of unconsolidated affiliate  –   –   –   (39.4)
Change in fair value of Liquidity Option  2.3   57.8 
Deferred income tax expense (benefit)  (184.1)  1.8 
Sustaining capital expenditures (3)  (90.8)  (76.2)  (232.5)  (215.3)  (68.9)  (61.6)
Other, net  61.0   9.4   76.0   50.5   11.0   1.1 
Subtotal DCF, before proceeds from asset sales and monetization of interest rate derivative instruments accounted for as cash flow hedges $1,638.8  $1,545.0  $4,973.5  $4,346.8   1,586.3   1,626.7 
Proceeds from asset sales  0.7   21.5   16.8   24.1   0.6   1.7 
Monetization of interest rate derivative instruments accounted
for as cash flow hedges
  –   –   –   1.5   (33.3)  – 
DCF (non-GAAP) $1,639.5  $1,566.5  $4,990.3  $4,372.4  $1,553.6  $1,628.4 
                        
Cash distributions paid to limited partners with respect to period $974.4  $948.5  $2,907.0  $2,822.2  $979.9  $963.5 
                        
Cash distribution per unit declared by Enterprise GP with respect to period(4) $0.4425  $0.4325  $1.3200  $1.2900  $0.4450  $0.4375 
                        
Total DCF retained by partnership with respect to period (4)(5) $665.1  $618.0  $2,083.3  $1,550.2  $573.7  $664.9 
                        
Distribution coverage ratio (5)(6)  1.68x  1.65x  1.72x  1.55x  1.6x  1.7x

(1)
For a discussion of the primary drivers of changes in our comparative income statement amounts, see “Income Statements Highlights”“Income Statement Highlights” within this Part I, Item 2.
(2)Reflects both distributions received on earnings from unconsolidated affiliates and those attributable to aearnings and the return of capital from unconsolidated affiliates.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 2 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.
(5)(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.

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

 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended March 31,
 
 2019  2018  2019  2018  2020  2019 
Net cash flows provided by operating activities (GAAP) $1,642.5  $1,577.5  $4,826.2  $4,275.3  $2,012.2  $1,160.4 
Adjustments to reconcile net cash flows provided by operating activities to DCF (addition or subtraction indicated by sign):
                        
Net effect of changes in operating accounts  77.0   33.4   409.0   261.9   (341.7)  559.8 
Sustaining capital expenditures  (90.8)  (76.2)  (232.5)  (215.3)  (68.9)  (61.6)
Distributions received from unconsolidated affiliates attributable to the return of capital  10.3   4.5 
Proceeds from asset sales  0.6   1.7 
Net income attributable to noncontrolling interest  (24.9)  (19.9)
Monetization of interest rate derivative instruments accounted for as cash flow hedges  (33.3)  – 
Other, net  10.8   31.8   (12.4)  50.5   (0.7)  (16.5)
DCF (non-GAAP) $1,639.5  $1,566.5  $4,990.3  $4,372.4  $1,553.6  $1,628.4 


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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 September 30, 2019March 31, 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 September 30,
  
For the Nine Months
Ended September 30,
  
For the Twelve Months Ended
September 30,
  
For the Three Months
Ended March 31,
  
For the Twelve Months Ended
March 31,
 
 2019  2018  2019  2018  2019  2020  2019  2020 
Net cash flows provided by operating activities (GAAP) $1,642.5  $1,577.5  $4,826.2  $4,275.3  $6,677.2  $2,012.2  $1,160.4  $7,372.3 
Adjustments to net cash flows provided by operating activities to derive FCF (addition or subtraction indicated by sign):                                
Cash used in investing activities  (1,086.3)  (1,093.2)  (3,372.8)  (3,182.8)  (4,471.6)  (1,071.7)  (1,174.5)  (4,472.7)
Cash contributions from noncontrolling interests  491.2   15.1   590.8   222.0   606.9   5.2   34.8   603.2 
Cash distributions paid to noncontrolling interests  (22.8)  (22.6)  (69.7)  (50.9)  (100.4)  (29.9)  (18.0)  (118.1)
FCF (non-GAAP) $1,024.6  $476.8  $1,974.5  $1,263.6  $2,712.1  $915.8  $2.7  $3,384.7 

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


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Capital Investments

As previously discussed, capital investing activity throughout the domestic energy industry is being significantly reduced in response to the demand and supply disruptions attributable to COVID-19 and the oil price shock. We, currentlyalong with many other midstream energy companies, have $9.1 billionreviewed our planned capital investments in light of growth capital projects scheduled to be completed by the end of 2023 including the following major projects:these adverse macroeconomic events.

our iBDH facility (fourth quarter of 2019),

the Shin Oak NGL pipeline (full service capacity expected to be available in fourth quarter of 2019),

our ethylene export terminalAs previously noted and related infrastructure (fourth quarter of 2019 through the fourth quarter of 2020),

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

our Mentone cryogenic natural gas processing plant and related infrastructure (first quarter of 2020),

increase in LPG loading capacity at EHT (fourth quarter of 2020),

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

our Midland-to-ECHO 3 and 4 pipelines (third quarter of 2020 and first half of 2021, respectively),

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

expansion and extension of Acadian Gas System (Gillis Lateral and related projects) (mid-2021),

expansion of our ATEX pipeline (fiscal 2022), and

construction of our PDH 2 facility (first half of 2023).

Basedbased on information currently available, we now expect our total capital investments for 20192020 to approximate a net $4.3$2.8 billion to $3.3 billion (previously $3.4 billion to $4.4 billion), which reflects growth capital expendituresinvestments of $4.5$2.5 billion $350to $3.0 billion (previously $3.0 billion to $4.0 billion) and approximately $300 million for sustaining capital expenditures and $0.6 billion of cash contributions from noncontrolling interests.  We(previously $400 million). Based on sanctioned projects, we currently expect our growth capital investments for 2021 and 2022 to approximate $3.0$2.5 billion to $4.0and $1.5 billion, in 2020.

respectively. Our revised forecast of capital investments for 2019 and 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.

74We placed a tenth NGL fractionator (“Frac X”) located in Chambers County, Texas into service in the first quarter of 2020. In addition, expansion projects on our Texas Express Pipeline and Front Range Pipeline were placed into commercial service in April 2020. We currently have $6.9 billion of growth capital projects scheduled to be completed by the end of 2023 including the following major projects:

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

Table
components of Contentsour Midland-to-ECHO System (third quarter of 2020 into 2021);

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

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

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

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

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

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

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

 
For the Nine Months
Ended September 30,
  
For the Three Months
Ended March 31,
 
 2019  2018  2020  2019 
Capital investments for property, plant and equipment: (1)
            
Growth capital projects (2) $3,072.4  $2,782.7  $1,006.5  $1,077.4 
Sustaining capital projects (3)  229.7   221.5   73.0   71.5 
Total $3,302.1  $3,004.2  $1,079.5  $1,148.9 
                
Cash used for business combinations, net $–  $150.6 
        
Investments in unconsolidated affiliates $100.1  $95.1  $3.3  $29.1 

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

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Comparison of Three Months Ended March 31, 2020 with Three Months Ended March 31, 2019

Fluctuations in our investments inattributable to our growth capital projects and investments inthose of our unconsolidated affiliates are explained in large part by increases or decreases in expenditures forthe funding of announced major expansion projects.  Our most significant growth capital investments for the nine months ended September 30, 2019 involve projects at our Mont Belvieu complex, crude oil pipelines in Texas and expansion projects involving our Gulf Coast export terminals. Fluctuations in investments inattributable to sustaining capital projects are explained in large part byprimarily due to the timing and cost of pipeline integrity and similar projects.

Comparison of Nine Months Ended September 30, 2019 with Nine Months Ended September 30, 2018

InvestmentsIn total, investments in growth capital projects at our Mont Belvieu complex increased $403.1decreased $70.9 million period-to-periodquarter-to-quarter primarily due to construction activities surrounding Frac X and Frac XI,the following (all of which accounted for a combined $425.5 million increase, our iBDH facility, which accounted for a $68.9 million increase, and expansion projects involving our DIBs, which accounted for an additional $62.9 million increase, partially offset by lower expenditures attributable to our PDH facility and ninth Mont Belvieu-area NGL fractionator (“Frac IX”), which accounted for a combined $182.8 million decrease.  Our PDH facility and Frac IX were both placed into service duringoccurred since the secondfirst quarter of 2018.2019):

Investments in growth capital projects for ethylene-related pipelines, storage facilities and export assets increased $199.8 million period-to-period.

Investments in growth capital projects in supportcompletion of Permian Basin production decreased $315.2 million period-to-period primarily due to lower expenditures at our Orla natural gas processing facility, which accounted for a $314.3 million decrease, and for ourthe Shin Oak NGL Pipeline, which accounted for a $154.8 million decrease;

lower investments in natural gas processing facilities and related infrastructure that support Permian Basin production, which accounted for an additional $235.5$114.6 million decrease,decrease. We completed the last phase of our Orla plant in July 2019 and placed our Mentone I plant into service in December 2019; partially offset by, increased expenditures at

higher investments in crude oil pipelines, including those comprising our MentoneMidland-to-ECHO System, and related infrastructure that support Permian Basin production, which accounted for an overall $96.9 million increase;

higher investments in natural gas processing plant,pipelines and related infrastructure in support of East Texas and Louisiana production, which accounted for a $194.4$48.5 million increase.  The third processing train at our Orla natural gas processing facility was placed into service in July 2019.increase; and

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





75higher investments in propylene production, NGL fractionation and other related plant assets and infrastructure at our Mont Belvieu complex, which accounted for a combined $42.3 million increase.

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Investments in our unconsolidated affiliates decreased $25.8 million quarter-to-quarter primarily due to lower spending on our Texas Express Pipeline expansion project, which accounted for a $10.5 million decrease, and lower spending on our joint venture dock infrastructure at Corpus Christi, which accounted for an additional $8.2 million decrease.

Critical Accounting Policies and Estimates

A discussion of our critical accounting policies and estimates is included in our 20182019 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.


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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 March 31, 2020 declined by an estimated $10.45 billion when compared to those reported in our 2019 Form 10-K primarily due to lower NGL and crude oil prices in the first quarter of 2020.

The principal amount of our consolidated debt obligations were $28.229.90 billion at September 30, 2019March 31, 2020 compared to $26.42$27.88 billion at December 31, 2018.  For information regarding the scheduled maturities of such debt, see “Liquidity and Capital Resources – Consolidated Debt”2019.  See “Other Recent Developments” within this Part I, Item 2.  See Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements under Part I, Item 1 of this quarterly report2 for information regarding our consolidated debt obligations.

Since December 31, 2018, we have entered into additional long-term purchase commitments for NGLs with third-party suppliers.  On a combined basis, these new agreements increased our estimated long-term purchase obligations by $3.6 billion, with $1.3 billion committed overEPO’s senior notes offering in January 2020 and the next five years and $2.3 billion thereafter.  At September 30, 2019, our estimated long-term purchase obligations totaled $12.7 billion after reflecting the agreements added during the first nine monthsrelated use of 2019 and those commitments that expired during the year.  At December 31, 2018, our estimated long-term purchase obligations totaled $10.8 billion.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.

Recent Accounting Developments

For information regarding recent changes in our accounting for leases, see Note 2 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

Related Party Transactions

For information regarding our related party transactions, see Note 1415 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.


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ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK.

General

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

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

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

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

the hedged forecasted transaction occurs within the expected time period.

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

See Note 1314 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report for additional information regarding our derivative instruments and hedging activities.

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Commodity Hedging Activities

The prices of natural gas, NGLs, crude oil, petrochemicals and refined products are subject to fluctuations in response to changes in supply and demand, market conditions and a variety of additional factors that are beyond our control.  In order to manage such price risks, we enter into commodity derivative instruments such as physical forward contracts, futures contracts, fixed-for-float swaps and basis swaps and option contracts.swaps.

The following table summarizes our portfolio of commodity derivative instruments outstanding at September 30, 2019March 31, 2020 (volume measures as noted):

Volume (1)AccountingVolume (1)Accounting
Derivative Purpose
Current (2)
Long-Term (2)
Treatment
Current (2)
Long-Term (2)
Treatment
Derivatives designated as hedging instruments:      
Natural gas processing:      
Forecasted natural gas purchases for plant thermal reduction (billion cubic feet (“Bcf”))15.2n/aCash flow hedge
Forecasted sales of NGLs (million barrels (“MMBbls”))
1.8n/aCash flow hedge
Forecasted natural gas purchases for plant thermal reduction (Bcf)11.9n/aCash flow hedge
Octane enhancement:      
Forecasted purchase of NGLs (MMBbls)1.0n/aCash flow hedge0.7n/aCash flow hedge
Forecasted sales of octane enhancement products (MMBbls)8.11.6Cash flow hedge13.6n/aCash flow hedge
Natural gas marketing:      
Forecasted purchase of natural gas (Bcf)4.5n/aCash flow hedge
Natural gas storage inventory management activities (Bcf)3.2n/aFair value hedge4.4n/aFair value hedge
NGL marketing:      
Forecasted purchases of NGLs and related hydrocarbon products (MMBbls)100.01.5Cash flow hedge126.30.4Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products (MMBbls)121.71.2Cash flow hedge140.02.2Cash flow hedge
NGLs inventory management activities (MMBbls)0.3n/aFair value hedge0.8n/aFair value hedge
Refined products marketing:      
Forecasted purchases of refined products (MMBbls)0.9n/aCash flow hedge5.1n/aCash flow hedge
Forecasted sales of refined products (MMBbls)0.9n/aCash flow hedge6.8n/aCash flow hedge
Refined products inventory management activities (MMBbls)0.5n/aFair value hedge
Crude oil marketing:      
Forecasted purchases of crude oil (MMBbls)10.4n/aCash flow hedge24.5n/aCash flow hedge
Forecasted sales of crude oil (MMBbls)13.8n/aCash flow hedge31.4n/aCash flow hedge
Propylene marketing:      
Forecasted sales of NGLs for propylene marketing activities (MMBbls)0.3n/aCash flow hedge0.6n/aCash flow hedge
Commercial energy:   
Forecasted purchases of power related to asset operations (terawatt hours (“TWh”))0.2n/aCash flow hedge
Derivatives not designated as hedging instruments:      
Natural gas risk management activities (Bcf) (3)38.20.6Mark-to-market54.50.3Mark-to-market
NGL risk management activities (MMBbls) (3)2.4n/aMark-to-market15.7n/aMark-to-market
Refined products risk management activities (MMBbls) (3)7.6n/aMark-to-market5.1n/aMark-to-market
Crude oil risk management activities (MMBbls) (3)22.26.1Mark-to-market33.99.0Mark-to-market
Commercial energy risk management activities (TWh) (3)0.1n/aMark-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 JanuaryDecember 2021, December 20192020 and December 2022, respectively.
(3)Reflects the use of derivative instruments to manage risks associated with transportation, processing, storage assets and storage assets.end use power requirements.

At September 30, 2019,March 31, 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 natural gas processing margins and (iii) hedging the fair value of commodity products held in inventory.inventory and (iii) hedging natural gas processing margins.  

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Sensitivity Analysis

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

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

Natural gas marketing portfolio
  Portfolio Fair Value at   Portfolio Fair Value at 
Scenario
Resulting
Classification
December 31,
2018
 
September 30,
2019
 
October 15,
2019
 
Resulting
Classification
December 31,
2019
 
March 31,
2020
 
April 15,
2020
 
Fair value assuming no change in underlying commodity pricesAsset (Liability) $7.8  $2.5  $3.1 Asset (Liability) $1.1  $28.8  $31.5 
Fair value assuming 10% increase in underlying commodity pricesAsset (Liability)  8.0   0.2   1.5 Asset (Liability)  (4.3)  24.9   27.7 
Fair value assuming 10% decrease in underlying commodity pricesAsset (Liability)  7.7   4.7   4.7 Asset (Liability)  6.6   32.8   35.2 

NGL and refined products marketing, natural gas processing and octane enhancement portfolio
  Portfolio Fair Value at   Portfolio Fair Value at 
Scenario
Resulting
Classification
December 31,
2018
 
September 30,
2019
 
October 15,
2019
 
Resulting
Classification
December 31,
2019
 
March 31,
2020
 
April 15,
2020
 
Fair value assuming no change in underlying commodity pricesAsset (Liability) $77.5  $48.0  $47.0 Asset (Liability) $43.7  $119.8  $86.5 
Fair value assuming 10% increase in underlying commodity pricesAsset (Liability)  56.2   (1.2)  2.2 Asset (Liability)  (19.0)  85.6   51.3 
Fair value assuming 10% decrease in underlying commodity pricesAsset (Liability)  98.9   97.2   91.8 Asset (Liability)  106.4   154.0   121.7 

Crude oil marketing portfolio
  Portfolio Fair Value at   Portfolio Fair Value at 
Scenario
Resulting
Classification
December 31,
2018
 
September 30,
2019
 
October 15,
2019
 
Resulting
Classification
December 31,
2019
 
March 31,
2020
 
April 15,
2020
 
Fair value assuming no change in underlying commodity pricesAsset (Liability) $(26.5) $27.4  $31.0 Asset (Liability) $(9.6) $122.5  $125.7 
Fair value assuming 10% increase in underlying commodity pricesAsset (Liability)  (88.6)  (0.2)  1.8 Asset (Liability)  (50.6)  103.1   106.7 
Fair value assuming 10% decrease in underlying commodity pricesAsset (Liability)  35.6   55.0   60.2 Asset (Liability)  31.5   142.0   144.7 





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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.  The composition of our derivative instrument portfolios may change depending on our hedging requirements.

Sensitivity Analysis

At March 31, 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.

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.

At September 30, 2019, our interest rate hedging portfolio consisted of 12 forward-starting swaps, which hedge the expected underlying benchmark interest rates related to future issuances of debt.  The following table summarizes our portfolio of theseforward-starting swaps at September 30, 2019March 31, 2020 (dollars in millions).:

Hedged Transaction
Number and Type
of Derivatives
Outstanding
Notional
Amount
Expected
Settlement
Date
Weighted-Average
Fixed Rate
Locked
Accounting
Treatment
Number and Type
of Derivatives
Outstanding
Notional
Amount
Expected
Settlement
Date
Weighted-Average
Fixed Rate
Locked
Accounting
Treatment
Future long-term debt offering1 forward-starting swap (1)$75.09/20202.39%Cash flow hedge1 forward-starting swap$75.04/20212.41%Cash flow hedge
Future long-term debt offering1 forward-starting swap (1)$75.04/20212.41%Cash flow hedge5 forward-starting swaps$500.04/2021
2.13%
Cash flow hedge
Future long-term debt offering5 forward-starting swaps (2)$500.09/20202.12%Cash flow hedge2 forward-starting swaps (1)$150.02/20221.72%Cash flow hedge
Future long-term debt offering5 forward-starting swaps (2)$500.04/2021
2.13%
Cash flow hedge1 forward starting swap (1)$100.04/20211.46%Cash flow hedge
Future long-term debt offering2 forward starting swaps (1)$150.02/20221.48%Cash flow hedge
Future long-term debt offering2 forward starting swaps (1)$100.02/20220.95%Cash flow hedge

(1)These swaps were entered into in May 2019.
(2)These swaps were entered into in September 2019 as a resultduring the first quarter of a swaption exercise.  See “Interest Rate Hedging Activities” under Note 13 of the Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report for additional information regarding the swaption exercise and related loss at inception.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
   
Forward-Starting Swap
Portfolio Fair Value at
 
Scenario
Resulting
Classification
December 31,
2018
 
September 30,
2019
 
November 7,
2019
 
Resulting
Classification
December 31,
2019
 
March 31,
2020
 
April 15,
2020
 
Fair value assuming no change in underlying interest ratesAsset (Liability) $–  $(118.6) $(37.1)Asset (Liability) $(13.5) $(258.3) $(249.2)
Fair value assuming 10% increase in underlying interest ratesAsset (Liability)  –   (71.7)  5.0 Asset (Liability)  38.2   (229.8)  (220.0)
Fair value assuming 10% decrease in underlying interest ratesAsset (Liability)  –   (168.0)  (79.2)Asset (Liability)  (68.3)  (287.6)  (279.3)

The $81.5$235.7 million changedecrease in the fair value of this portfolio from September 30,December 31, 2019 to November 7, 2019April 15, 2020 was primarily due to an increase in the underlying 30-year variabledeclining interest rates relative to the fixed rates specified in the swap agreements.  Upon settlement, we would expect that any loss on these swaps would ultimately be offset by lower interest rates stated in the associated swap agreements.



on future debt issuances.
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ITEM 4.  CONTROLS AND PROCEDURES.

Disclosure Controls and Procedures

As of the end of the period covered by this quarterly report, our management carried out an evaluation, with the participation of (i) A. James Teague, our general partner’s ChiefCo-Chief Executive Officer of Enterprise GP and (ii) W. Randall Fowler, our general partner’s PresidentCo-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 principalco-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 thirdfirst quarter of 2019,2020, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting. 

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

Section 302 and 906 Certifications

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


PART II.  OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS.

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

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

For additional information regarding our litigation matters, see “Litigation” under Note 1516 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report, which subsection is incorporated by reference into this Part II, Item 1.


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ITEM 1A.  RISK FACTORS.

An investment in our securities involves certain risks. Security holders and potential investors in our securities should carefully consider the risks described under “Risk Factors” set forth in Part I, Item 1A of our 20182019 Form 10-K, in addition to other information in such annual report.report and this quarterly report (including the additional risk factor set forth below).  The risk factors set forth in our 20182019 Form 10-K and as set forth below are important factors that could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us or on our behalf.

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

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

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

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











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

Recent Issuance of Unregistered Securities

On March 5, 2020, we settled our obligations under the Liquidity Option Agreement. As a result, EPD issued 54,807,352 of its common units (the “Liquidity Option Units”) as consideration for our acquisition of 100% of the issued and outstanding capital stock of OTA.  For additional information regarding this transaction, see “Other Recent Developments – Settlement of Liquidity Option” within Part I, Item 2 of this quarterly report.

The issuance and sale of the Liquidity Option Units was exempt from registration under Section 4(a)(2) of the Securities Act because the transaction did not involve a public offering.

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

Issuer Purchases of Equity Securities

The following table summarizes our equity repurchase activity during the thirdfirst quarter of 2019:2020:

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)            
   July 2019  –  $–   –  $1,923,165 
   August 2019  –  $–   –  $1,923,165 
   September 2019  –  $–   –  $1,923,165 
Vesting of phantom unit awards:                
   July 2019  –  $–   n/a   n/a 
   August 2019 (2)  85,412  $28.82   n/a   n/a 
   September 2019  –  $–   n/a   n/a 
Period 
Total Number
of Units
Purchased
  
Average
Price Paid
per Unit
  
Total
Number
Of Units
Purchased
as Part of
2019 Buyback
Program
  
Remaining
Dollar Amount
of Units
That May
Be Purchased
Under the 2019 Buyback
Program
($ thousands)
 
2019 Buyback Program: (1)            
   January 2020  –  $–   2,909,128  $1,918,911 
   February 2020  –  $–   2,909,128  $1,918,911 
   March 2020  6,357,739  $22.02   9,266,867  $1,778,911 
Vesting of phantom unit awards:                
   January 2020  –  $–   n/a   n/a 
   February 2020 (2)  1,291,427  $25.96   n/a   n/a 
   March 2020 (3)  1,297  $23.34   n/a   n/a 

(1)In January 2019, we announced the 2019 Buyback Program, which authorized the repurchase of up to $2 billion of EPD’s common units.  See “Significant Recent Developments”Units repurchased under Part I, Item 2 of this quarterly report for additional information.  The repurchased unitsprogram during 2020 were cancelled immediately upon acquisition.
(2)
Of the 248,962 4,200,676 phantom unit awards that vested in August 2019February 2020 and converted to common units, 85,4121,291,427 units were sold back to us by employees to cover related withholding tax requirements. These repurchases are not part of any announced program.  We cancelled these units immediately upon acquisition.
(3)Of the 4,262 phantom unit awards that vested in March 2020 and converted to common units, 1,297 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.

On November 6, 2019, Dan Duncan LLC executed Amendment No. 2 to Enterprise GP’s Fifth Amended and Restated Limited Liability Company Agreement in response to changes to the Internal Revenue Code enacted by the Bipartisan Budget Act of 2015 relating to partnership audit and adjustment procedures.  The foregoing description of the amendment is qualified in its entirety by reference to the full text thereof, which is filed as Exhibit 3.12 hereto and incorporated by reference herein.

None.
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ITEM 6.  EXHIBITS.


Exhibit NumberExhibit*
2.1
Merger Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form 8-K filed December 15, 2003).
2.2
Amendment No. 1 to Merger Agreement, dated as of August 31, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form 8-K filed September 7, 2004).
2.3
Parent Company Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.2 to Form 8-K filed December 15, 2003).
2.4
Amendment No. 1 to Parent Company Agreement, dated as of April 19, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.1 to Form 8-K filed April 21, 2004).
2.5
Purchase and Sale Agreement (Gas Plants), dated as of December 15, 2003, by and between El Paso Corporation, El Paso Field Services Management, Inc., El Paso Transmission, L.L.C., El Paso Field Services Holding Company and Enterprise Products Operating L.P. (incorporated by reference to Exhibit 2.4 to Form 8-K filed December 15, 2003). 
2.6
Agreement and Plan of Merger, dated as of June 28, 2009, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Sub B LLC, TEPPCO Partners, L.P. and Texas Eastern Products Pipeline Company, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed June 29, 2009).
2.7
Agreement and Plan of Merger, dated as of June 28, 2009, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Sub A LLC, TEPPCO Partners, L.P. and Texas Eastern Products Pipeline Company, LLC (incorporated by reference to Exhibit 2.2 to Form 8-K filed June 29, 2009).
2.8
Agreement and Plan of Merger, dated as of September 3, 2010, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise ETE LLC, Enterprise GP Holdings L.P. and EPE Holdings, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed September 7, 2010).
2.9
Agreement and Plan of Merger, dated as of September 3, 2010, by and among Enterprise Products GP, LLC, Enterprise GP Holdings L.P. and EPE Holdings, LLC (incorporated by reference to Exhibit 2.2 to Form 8-K filed September 7, 2010).
2.10
Contribution Agreement, dated as of September 30, 2010, by and between Enterprise Products Company and Enterprise Products Partners L.P. (incorporated by reference to Exhibit 2.1 to Form 8-K filed October 1, 2010).
2.11
Agreement and Plan of Merger, dated as of April 28, 2011, by and among Enterprise Products Partners L.P., Enterprise Products Holdings LLC, EPD MergerCo LLC, Duncan Energy Partners L.P. and DEP Holdings, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed April 29, 2011).
2.12
Contribution and Purchase Agreement, dated as of October 1, 2014, by and among Enterprise Products Partners L.P., Oiltanking Holding Americas, Inc. and OTB Holdco, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed October 1, 2014).

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2.13
Agreement and Plan of Merger, dated as of November 11, 2014, by and among Enterprise Products Partners L.P., Enterprise Products Holdings LLC, EPOT MergerCo LLC, Oiltanking Partners, L.P. and OTLP GP, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed November 12, 2014).

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2.14
Amendment No. 1 dated as of June 6, 2018 to Contribution and Purchase Agreement, by and among Enterprise Products Partners L.P., Oiltanking Holding Americas, Inc., Enterprise Products Holdings LLC and Marquard & Bahls, AG (incorporated by reference to Exhibit 2.2 to Form 8-K filed June 12, 2018).
3.1
Certificate of Limited Partnership of Enterprise Products Partners L.P. (incorporated by reference to Exhibit 3.6 to Form 10-Q filed November 9, 2007).
3.2
Certificate of Amendment to Certificate of Limited Partnership of Enterprise Products Partners L.P., filed on November 22, 2010 with the Delaware Secretary of State (incorporated by reference to Exhibit 3.6 to Form 8-K filed November 23, 2010).
3.3
Sixth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated November 22, 2010 (incorporated by reference to Exhibit 3.2 to Form 8-K filed November 23, 2010).
3.4
Amendment No. 1 to Sixth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated effective as of August 11, 2011 (incorporated by reference to Exhibit 3.1 to Form 8-K filed August 16, 2011).
3.5
Amendment No. 2 to Sixth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated effective as of August 21, 2014 (incorporated by reference to Exhibit 3.1 to Form 8-K filed August 26, 2014).
3.6
Amendment No. 3 to the Sixth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated as of November 28, 2017 (incorporated by reference to Exhibit 3.1 to Form 8-K filed December 1, 2017).
3.7
Amendment No. 4 to the Sixth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated as of February 26, 2019 (incorporated by reference to Exhibit 3.7 to Form 10-K filed March 1, 2019).
3.8
Amendment No. 5 to the Sixth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated as of March 5, 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).
3.93.10
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).
3.103.11
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).
3.113.12
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).
3.12#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, 2019.2019 (incorporated by reference to Exhibit 3.12 to Form 10-Q filed November 8, 2019).
3.133.14
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).
3.143.15
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).
3.153.16
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 Registrant’s Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934 (incorporated by reference to Exhibit 4.2 to Form 10-K filed February 28, 2020).

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4.3
Indenture, dated as of March 15, 2000, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and First Union National Bank, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed March 14, 2000).

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4.34.4
Second Supplemental Indenture, dated as of February 14, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 10-K filed March 31, 2003).
4.44.5
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).
4.54.6
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).
4.64.7
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).
4.74.8
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).
4.8
Amended and Restated Eighth Supplemental Indenture, dated as of August 25, 2006, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed August 25, 2006).
4.9
Ninth Supplemental Indenture, dated as of May 24, 2007, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed May 24, 2007).
4.10
Tenth Supplemental Indenture, dated as of June 30, 2007, among Enterprise Products Operating L.P., as Original Issuer, Enterprise Products Partners L.P., as Parent Guarantor, Enterprise Products Operating LLC, as New Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.54 to Form 10-Q filed August 8, 2007).
4.114.10
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).
4.124.11
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).
4.134.12
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).
4.144.13
 
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).
4.154.14
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).


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4.164.15
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).
4.174.16
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).
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4.184.17
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).
4.194.18
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).
4.204.19
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).
4.214.20
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).
4.224.21
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).
4.234.22
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).
4.244.23
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).
4.254.24
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).
4.264.25
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).
4.274.26
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).
4.284.27
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).

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4.294.28
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
Form of Global Note representing $499.2 million principal amount of 6.875% Series B Senior Notes due 2033 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 10-K filed March 31, 2003).
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4.31
Form of Global Note representing $350.0 million principal amount of 6.65% Series B Senior Notes due 2034 with attached Guarantee (incorporated by reference to Exhibit 4.19 to Form S-3 Registration Statement, Reg. No. 333-123150, filed March 4, 2005).
4.32
Form of Global Note representing $250.0 million principal amount of 5.75% Series B Senior Notes due 2035 with attached Guarantee (incorporated by reference to Exhibit 4.32 to Form 10-Q filed November 4, 2005).
4.33
Form of Global Note representing an aggregate of $550.0 million principal amount of Junior Subordinated Notes due 2066 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.2 to Form 8-K filed August 25, 2006).
4.34
Form of Global Note representing $700.0 million principal amount of 6.50% Senior Notes due 2019 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.4 to Form 8-K filed April 3, 2008).
4.354.34
Form of Global Note representing $500.0 million principal amount of 5.25% Senior Notes due 2020 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed October 5, 2009).
4.364.35
Form of Global Note representing $600.0 million principal amount of 6.125% Senior Notes due 2039 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed October 5, 2009).
4.37
Form of Global Note representing $349.7 million principal amount of 6.65% Senior Notes due 2018 with attached Guarantee (incorporated by reference to Exhibit D to Exhibit 4.1 to Form 8-K filed October 28, 2009).
4.384.36
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).
4.394.37
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).
4.404.38
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).
4.414.39
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).
4.424.40
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).
4.434.41
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).
4.444.42
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).
4.454.43
Form of Global Note representing $750.0 million principal amount of 4.85% Senior Notes due 2042 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.25 to Form 10-Q filed May 10, 2012).

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4.464.44
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).
4.474.45
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).
4.484.46
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).
4.494.47
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).
4.504.48
Form of Global Note representing $1.15 billion principal amount of 5.10% Senior Notes due 2045 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed February 12, 2014).
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4.514.49
Form of Global Note representing $800.0 million principal amount of 2.55% Senior Notes due 2019 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.4 to Form 8-K filed October 14, 2014).
4.524.50
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).
4.534.51
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).
4.544.52
Form of Global Note representing $400.0 million principal amount of 4.85% Senior Notes due 2044 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed March 18, 2013).
4.55
Form of Global Note representing $750.0 million principal amount of 1.65% Senior Notes due 2018 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed May 7, 2015).
4.564.53
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).
4.574.54
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).
4.584.55
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).
4.594.56
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).
4.604.57
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).
4.614.58
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).
4.624.59
Form of Global Note representing $1.0 billion principal amount of Junior Subordinated Notes E due 2077 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed August 16, 2017).

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4.634.60
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).
4.644.61
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).
4.654.62
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).
4.664.63
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).
4.674.64
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).
4.684.65
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).
4.694.66
Form of Global Note representing $1,250.0 million principal amount of 3.125% Senior Notes due 2029 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed July 8, 2019).
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4.704.67
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).
4.714.68
Replacement Capital Covenant, dated July 18, 2006, executed by Enterprise Products Operating L.P. in favorForm of the covered debtholders described thereinGlobal Note representing $1,000.0 million principal amount of 2.800% Senior Notes due 2030 with attached Guarantee (incorporated by reference to Exhibit 99.1A to Exhibit 4.3 to Form 8-K filed July 19, 2006)January 15, 2020).
4.724.69
First Amendment to Replacement Capital Covenant dated August 25, 2006, executed by Enterprise Products Operating L.P. in favorForm of the covered debtholders described thereinGlobal Note representing $1,000.0 million principal amount of 3.700% Senior Notes due 2051 with attached Guarantee (incorporated by reference to Exhibit 99.2B to Exhibit 4.3 to Form 8-K filed August 25, 2006)January 15, 2020).
4.734.70
Replacement Capital Covenant, dated May 24, 2007, executed by Enterprise Products Operating L.P. and Enterprise Products Partners L.P. in favorForm of the covered debtholders described thereinGlobal Note representing $1,000.0 million principal amount of 3.950% Senior Notes due 2060 with attached Guarantee (incorporated by reference to Exhibit 99.1C to Exhibit 4.3 to Form 8-K filed May 24, 2007)January 15, 2020).
4.744.71
Replacement Capital Covenant, dated October 27, 2009, executed by Enterprise Products Operating LLC and Enterprise Products Partners L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 4.9 to Form 8-K filed October 28, 2009).
4.754.72
Amendment to Replacement Capital Covenants, dated May 6, 2015, executed by Enterprise Products Operating LLC and Enterprise Products Partners L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 4.59 to Form 10-Q filed May 8, 2015).
4.764.73
Indenture, dated February 20, 2002, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as Subsidiary Guarantors, and First Union National Bank, NA, as Trustee (incorporated by reference to Exhibit 99.2 to the Form 8-K filed by TEPPCO Partners, L.P. on February 20, 2002).
4.774.74
Supplemental Indenture, dated June 27, 2002, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as Initial Subsidiary Guarantors, Val Verde Gas Gathering Company, L.P., as New Subsidiary Guarantor, and Wachovia Bank, National Association, formerly known as First Union National Bank, as Trustee (incorporated by reference to Exhibit 4.6 to the Form 10-Q filed by TEPPCO Partners, L.P. on August 14, 2002).
4.784.75
Full Release of Guarantee, dated July 31, 2006, by Wachovia Bank, National Association, as Trustee, in favor of Jonah Gas Gathering Company (incorporated by reference to Exhibit 4.8 to the Form 10-Q filed by TEPPCO Partners, L.P. on November 7, 2006).

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4.79
Fourth Supplemental Indenture, dated June 30, 2007, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Val Verde Gas Gathering Company, L.P., TE Products Pipeline Company, LLC and TEPPCO Midstream Companies, LLC, as Subsidiary Guarantors, and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.3 to the Form 8-K filed by TE Products Pipeline Company, LLC on July 6, 2007).
4.80
Sixth Supplemental Indenture, dated March 27, 2008, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.12 to the Form 10-Q filed by TEPPCO Partners, L.P. on May 8, 2008).
4.814.76
Seventh Supplemental Indenture, dated March 27, 2008, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.13 to the Form 10-Q filed by TEPPCO Partners, L.P. on May 8, 2008).
4.824.77
Eighth Supplemental Indenture, dated October 27, 2009, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 to the Form 8-K filed by TEPPCO Partners, L.P. on October 28, 2009).
4.834.78
Full Release of Guarantee, dated November 23, 2009, of TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P. by U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.64 to Form 10-K filed March 1, 2010).
4.844.79
Indenture, dated May 14, 2007, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and The Bank of New York Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 99.1 of the Form 8-K filed by TEPPCO Partners, L.P. on May 15, 2007).
4.854.80
First Supplemental Indenture, dated May 18, 2007, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and The Bank of New York Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.2 to the Form 8-K filed by TEPPCO Partners, L.P. on May 18, 2007).
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4.864.81
Second Supplemental Indenture, dated as of June 30, 2007, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Val Verde Gas Gathering Company, L.P., as Existing Subsidiary Guarantors, TE Products Pipeline Company, LLC and TEPPCO Midstream Companies, LLC, as New Subsidiary Guarantors, and The Bank of New York Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.2 to the Form 8-K filed by TE Products Pipeline Company, LLC on July 6, 2007).
4.874.82
Third Supplemental Indenture, dated as of October 27, 2009, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and The Bank of New York Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.2 to the Form 8-K filed by TEPPCO Partners, L.P. on October 28, 2009).
4.884.83
Full Release of Guarantee, dated as of November 23, 2009, of TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P. by The Bank of New York Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.70 to Form 10-K filed March 1, 2010).

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4.894.84
Registration Rights Agreement, by anddated as of March 5, 2020, between Enterprise Products Partners L.P. and Oiltanking HoldingSkyline North Americas, Inc. dated as of October 1, 2014 (incorporated by reference to Exhibit 4.1 to Form 8-K filed October 1, 2014)March 5, 2020).
10.1***10.1
Retirement, Consulting Services and Release Agreement, dated effective as of August 16, 2019, between Enterprise Products Company and William Ordemann (incorporated by reference to Exhibit 10.1 to Form 8-K filed August 22, 2019).
10.2
April 2020 364-Day Revolving Credit Agreement, dated as of September 10, 2019April 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 September 11, 2019)April 6, 2020).
10.310.2
Guaranty Agreement, dated as of September 10, 2019,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 September 11, 2019).
10.4
First Amendment to Revolving Credit Agreement, dated as of September 10, 2019, among Enterprise Products Operating LLC, the Lenders party thereto, and Wells Fargo Bank, National Association, as Administrative Agent (incorporated by reference to Exhibit 10.3 to Form 8-K filed September 11, 2019)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 ninethree months ended September 30, 2019.March 31, 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 ninethree months ended September 30, 2019.March 31, 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 ninethree months ended September 30, 2019.March 31, 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 ninethree months ended September 30, 2019.March 31, 2020.
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) ourthe Unaudited Condensed Consolidated Balance Sheets, as of September 30, 2019 and December 31, 2018; (ii) ourthe Unaudited Condensed Statements of Consolidated Operations, for(iii) the three and nine months ended September 30, 2019 and 2018; (iii) our Unaudited Condensed Statements of Consolidated Comprehensive Income, for(iv) the three and nine months ended September 30, 2019 and 2018; (iv) our Unaudited Condensed Statements of Consolidated Cash Flows, for(v) the nine months ended September 30, 2019 and 2018; (v) our Unaudited Condensed Statements of Consolidated Equity for the three and nine months ended September 30, 2019 and 2018; and (vi) the notesNotes to ourthe 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.

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SIGNATURES
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on NovemberMay 8, 2019.2020.

  
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:
SeniorExecutive Vice President – Accounting, and 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















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