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, 20202021

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

For the transition period from ___  to  ___.

Commission file number:  1-14323

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

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

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

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

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

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

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

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

There were 2,182,880,9792,182,129,957 common units of Enterprise Products Partners L.P. outstanding at the close of business on October 31, 2020.2021. 

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 PresentationOperations
89
 
2.  Summary of Significant Accounting Policies
910
 
3.  Inventories
10
 
4.  Property, Plant and Equipment
11
 
5.  Investments in Unconsolidated Affiliates
1213
 
6.  Intangible Assets and Goodwill
13
 
7.  Debt Obligations
1415
 
8.  Capital Accounts
1718
 
9.  Revenues
2221
 
10.  Business Segments and Related Information
2422
 
11.  Income TaxesEarnings Per Unit
2726
 
12.  Earnings Per UnitEquity-Based Awards
2926
 
13.  Equity-Based Awards
30
14.  Derivative Instruments,  Hedging Activities and Fair Value Measurements
3128
14.  Related Party Transactions
34
 
15.  Related Party TransactionsIncome Taxes
3735
 
16.  Commitments and Contingent Liabilities
38
 
17.  Supplemental Cash Flow Information
41
18.  Condensed Consolidating Financial Information
4240
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations.
4941
Item 3.
Quantitative and Qualitative Disclosures About Market Risk.
8068
Item 4.
Controls and Procedures.
8470
   
PART II.  OTHER INFORMATION.
Item 1.
Legal Proceedings.
8470
Item 1A.
Risk Factors.
8570
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds.
8671
Item 3.
Defaults Upon Senior Securities.
8671
Item 4.
Mine Safety Disclosures.
8671
Item 5.
Other Information.
8772
Item 6.
Exhibits.
8772
   
Signatures
9681

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,
2020
  
December 31,
2019
  
September 30,
2021
  
December 31,
2020
 
ASSETS            
Current assets:            
Cash and cash equivalents $1,032.2  $334.7  $2,213.5  $1,059.9 
Restricted cash  98.9   75.3   144.6   98.2 
Accounts receivable – trade, net of allowance for doubtful accounts
of $13.8 at September 30, 2020 and $12.4 at December 31, 2019
  3,776.2   4,873.6 
Accounts receivable – trade, net of allowance for credit losses
of $50.0 at September 30, 2021 and $46.5 at December 31, 2020
  6,119.5   4,802.6 
Accounts receivable – related parties  4.1   2.5   3.0   5.6 
Inventories  3,192.6   2,091.4 
Derivative assets  132.9   127.2 
Inventories (see Note 3)  3,095.9   3,303.5 
Derivative assets (see Note 13)  694.9   228.6 
Prepaid and other current assets  556.4   358.2   557.0   411.0 
Total current assets  8,793.3   7,862.9   12,828.4   9,909.4 
Property, plant and equipment, net  42,360.1   41,603.4 
Investments in unconsolidated affiliates  2,485.4   2,600.2 
Intangible assets, net of accumulated amortization of $1,796.8 at
September 30, 2020 and $1,687.5 at December 31, 2019 (see Note 6)
  3,348.6   3,449.0 
Property, plant and equipment, net (see Note 4)
  42,253.8   41,912.8 
Investments in unconsolidated affiliates (see Note 5)
  2,433.4   2,429.2 
Intangible assets, net (see Note 6)
  3,190.0   3,309.1 
Goodwill (see Note 6)
  5,745.2   5,745.2   5,448.9   5,448.9 
Other assets  1,003.6   472.5   1,165.4   1,097.3 
Total assets $63,736.2  $61,733.2  $67,319.9  $64,106.7 
                
LIABILITIES AND EQUITY                
Current liabilities:                
Current maturities of debt (see Note 7) $1,325.0  $1,981.9  $1,399.3  $1,325.0 
Accounts payable – trade  896.0   1,004.5   708.1   704.6 
Accounts payable – related parties  121.3   162.3   124.7   149.5 
Accrued product payables  4,317.1   4,915.7   7,997.1   5,395.4 
Accrued interest  235.1   431.7   225.2   455.6 
Derivative liabilities  329.7   122.4 
Derivative liabilities (see Note 13)  770.1   349.2 
Other current liabilities  622.7   511.2   646.2   608.7 
Total current liabilities  7,846.9   9,129.7   11,870.7   8,988.0 
Long-term debt (see Note 7)
  28,537.0   25,643.2   28,132.8   28,540.7 
Deferred tax liabilities (see Note 11)
  463.3   100.4 
Deferred tax liabilities (see Note 15)
  511.3   464.7 
Other long-term liabilities  735.2   1,032.4   771.2   686.6 
Commitments and contingent liabilities (see Note 16)
        0   0 
Redeemable preferred limited partner interests: (see Note 8)
                
Series A cumulative convertible preferred units (“preferred units”)
(50,000 units outstanding at September 30, 2020)
  49.1     
Series A cumulative convertible preferred units (“preferred units”)
(50,412 units outstanding at September 30, 2021 and 50,138 units outstanding
at December 31, 2020)
  49.3   49.3 
Equity: (see Note 8)
                
Partners’ equity:                
Common limited partner interests (2,182,880,979 units issued and outstanding at September 30, 2020, 2,189,226,130 units issued and outstanding at December 31, 2019)  26,381.9   24,692.6 
Common limited partner interests (2,182,129,957 units issued and outstanding at
September 30, 2021, 2,182,308,958 units issued and outstanding at December 31, 2020)
  26,390.3   25,766.6 
Treasury units, at cost  (1,297.3)  0   (1,297.3)  (1,297.3)
Accumulated other comprehensive income (loss)  (49.3)  71.4 
Accumulated other comprehensive loss  (171.8)  (165.2)
Total partners’ equity  25,035.3   24,764.0   24,921.2   24,304.1 
Noncontrolling interests in consolidated subsidiaries  1,069.4   1,063.5   1,063.4   1,073.3 
Total equity  26,104.7   25,827.5   25,984.6   25,377.4 
Total liabilities, preferred units, and equity $63,736.2  $61,733.2  $67,319.9  $64,106.7 


See Notes to Unaudited Condensed Consolidated Financial Statements.
2

Table of Contents

ENTERPRISE 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 September 30,
  
For the Nine Months
Ended September 30,
 
 2020  2019  2020  2019  2021  2020  2021  2020 
Revenues:                        
Third parties $6,914.5  $7,948.5  $20,126.3  $24,730.2  $10,800.4  $6,914.5  $29,382.2  $20,126.3 
Related parties  7.5   15.6   29.2   53.7   30.9   7.5   54.5   29.2 
Total revenues (see Note 9)  6,922.0   7,964.1   20,155.5   24,783.9   10,831.3   6,922.0   29,436.7   20,155.5 
Costs and expenses:                                
Operating costs and expenses:                                
Third parties  5,288.2   6,217.6   15,087.4   19,342.4 
Third party and other costs  9,068.1   5,288.2   24,063.9   15,087.4 
Related parties  283.0   356.1   914.5   1,051.9   340.4   283.0   964.7   914.5 
Total operating costs and expenses  5,571.2   6,573.7   16,001.9   20,394.3   9,408.5   5,571.2   25,028.6   16,001.9 
General and administrative costs:                                
Third parties  16.3   19.1   63.1   60.9 
Third party and other costs  16.4   16.3   56.6   63.1 
Related parties  34.0   36.4   99.7   99.3   30.9   34.0   98.5   99.7 
Total general and administrative costs  50.3   55.5   162.8   160.2   47.3   50.3   155.1   162.8 
Total costs and expenses (see Note 10)  5,621.5   6,629.2   16,164.7   20,554.5   9,455.8   5,621.5   25,183.7   16,164.7 
Equity in income of unconsolidated affiliates  82.0   139.3   336.1   431.3   137.6   82.0   447.2   336.1 
Operating income  1,382.5   1,474.2   4,326.9   4,660.7   1,513.1   1,382.5   4,700.2   4,326.9 
Other income (expense):                                
Interest expense  (320.5)  (382.9)  (958.2)  (950.2)  (315.9)  (320.5)  (954.8)  (958.2)
Change in fair market value of Liquidity Option (see Note 8)  0   (38.7)  (2.3)  (123.1)
Change in fair market value of Liquidity Option  0   0   0   (2.3)
Interest income  2.2   6.9   12.3   8.9   0.9   2.2   2.7   12.3 
Other, net  0.7   0.7   2.5   2.8   0.1   0.7   (0.1)  2.5 
Total other expense, net  (317.6)  (414.0)  (945.7)  (1,061.6)  (314.9)  (317.6)  (952.2)  (945.7)
Income before income taxes  1,064.9   1,060.2   3,381.2   3,599.1   1,198.2   1,064.9   3,748.0   3,381.2 
Benefit from (provision for) income taxes (see Note 11)  19.1   (15.4)  138.6   (37.4)
Benefit from (provision for) income taxes (see Note 15)  (16.1)  19.1   (57.3)  138.6 
Net income  1,084.0   1,044.8   3,519.8   3,561.7   1,182.1   1,084.0   3,690.7   3,519.8 
Net income attributable to noncontrolling interests  (31.4)  (25.6)  (82.4)  (67.3)  (28.3)  (31.4)  (82.3)  (82.4)
Net income attributable to preferred units (see Note 8)  0*  0   0*  0 
Net income attributable to preferred units  (0.8)  0*  (2.7)  0*
Net income attributable to common unitholders $1,052.6  $1,019.2  $3,437.4  $3,494.4  $1,153.0  $1,052.6  $3,605.7  $3,437.4 
                                
* Amount is negligible                
*Amount is negligible                
                                
Earnings per unit: (see Note 12)
                
Basic earnings per common unit $0.48  $0.46  $1.56  $1.59 
Diluted earnings per common unit $0.48  $0.46  $1.56  $1.59 
Earnings per unit: (see Note 11)
                
Basic and diluted earnings per common unit $0.52  $0.48  $1.64  $1.56 













See Notes to Unaudited Condensed Consolidated Financial Statements.
3

Table of Contents


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,
  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
 2020  2019  2020  2019  2021  2020  2021  2020 
                        
Net income $1,084.0  $1,044.8  $3,519.8  $3,561.7  $1,182.1  $1,084.0  $3,690.7  $3,519.8 
Other comprehensive income (loss):                                
Cash flow hedges: (see Note 14)                
Cash flow hedges: (see Note 13)                
Commodity hedging derivative instruments:                                
Changes in fair value of cash flow hedges  (4.2)  72.3   392.7   58.6   (100.6)  (4.2)  (852.2)  392.7 
Reclassification of losses (gains) to net income
  29.5   (91.5)  (334.8)  (152.0)  117.1   29.5   633.8   (334.8)
Interest rate hedging derivative instruments:                                
Changes in fair value of cash flow hedges  62.6   (18.6)  (207.7)  (23.8)  0   62.6   182.9   (207.7)
Reclassification of losses to net income
  9.9   9.4   29.2   27.8   10.3   9.9   29.1   29.2 
Total cash flow hedges  97.8   (28.4)  (120.6)  (89.4)  26.8   97.8   (6.4)  (120.6)
Other  0   0   (0.1)  (0.6)  0.1   0   (0.2)  (0.1)
Total other comprehensive income (loss)
  97.8   (28.4)  (120.7)  (90.0)  26.9   97.8   (6.6)  (120.7)
Comprehensive income  1,181.8   1,016.4   3,399.1   3,471.7   1,209.0   1,181.8   3,684.1   3,399.1 
Comprehensive income attributable to noncontrolling interests  (31.4)  (25.6)  (82.4)  (67.3)  (28.3)  (31.4)  (82.3)  (82.4)
Comprehensive income attributable to preferred units (see Note 8)  0*  0   0*  0 
Comprehensive income attributable to preferred units  (0.8)  0*  (2.7)  0*
Comprehensive income attributable to common unitholders $1,150.4  $990.8  $3,316.7  $3,404.4  $1,179.9  $1,150.4  $3,599.1  $3,316.7 
  
*Amount is negligible




























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,
 
  2020  2019 
Operating activities:      
Net income $3,519.8  $3,561.7 
Reconciliation of net income to net cash flows provided by operating activities:        
Depreciation, amortization and accretion  1,545.1   1,456.7 
Asset impairment and related charges  90.4   51.3 
Equity in income of unconsolidated affiliates  (336.1)  (431.3)
Distributions received from unconsolidated affiliates attributable to earnings
  337.4   431.2 
Net gains attributable to asset sales  (2.1)  (2.6)
Deferred income tax expense (benefit)  (149.0)  10.9 
Change in fair market value of derivative instruments  (53.7)  2.0 
Change in fair market value of Liquidity Option  2.3   123.1 
Non-cash expense related to long-term operating leases (see Note 16)  29.6   32.4 
Net effect of changes in operating accounts (see Note 17)  (692.0)  (409.0)
Other operating activities  (0.1)  (0.2)
Net cash flows provided by operating activities  4,291.6   4,826.2 
Investing activities:        
Capital expenditures  (2,671.6)  (3,302.1)
Investments in unconsolidated affiliates  (9.9)  (100.1)
Distributions received from unconsolidated affiliates attributable to the return of capital
  124.9   53.9 
Proceeds from asset sales  8.4   16.8 
Other investing activities  (16.0)  (41.3)
Cash used in investing activities  (2,564.2)  (3,372.8)
Financing activities:        
Borrowings under debt agreements  6,672.1   44,629.6 
Repayments of debt  (4,406.6)  (42,855.3)
Debt issuance costs  (46.3)  (26.3)
Monetization of interest rate derivative instruments  (33.3)  0 
Cash distributions paid to common unitholders (see Note 8)  (2,919.6)  (2,871.1)
Cash payments made in connection with distribution equivalent rights  (20.0)  (16.4)
Cash distributions paid to noncontrolling interests  (97.8)  (69.7)
Cash contributions from noncontrolling interests  21.2   590.8 
Net cash proceeds from the issuance of common units  0   82.2 
Repurchase of common units under 2019 Buyback Program (see Note 8)  (173.8)  (81.1)
Net cash proceeds from the issuance of preferred units (see Note 8)  32.5   0 
Other financing activities  (34.7)  (38.4)
Cash used in financing activities
  (1,006.3)  (655.7)
Net change in cash and cash equivalents, including restricted cash  721.1   797.7 
Cash and cash equivalents, including restricted cash, at beginning of period  410.0   410.1 
Cash and cash equivalents, including restricted cash, at end of period $1,131.1  $1,207.8 




  
For the Nine Months
Ended September 30,
 
  2021  2020 
Operating activities:      
Net income $3,690.7  $3,519.8 
Reconciliation of net income to net cash flows provided by operating activities:        
Depreciation and accretion  1,281.0   1,262.6 
Amortization of intangible assets  113.3   109.3 
Amortization of major maintenance costs for reaction-based plants  19.0   0 
Other amortization expense  180.4   173.2 
Impairment of assets other than goodwill (see Note 4)
  112.9   90.4 
Equity in income of unconsolidated affiliates  (447.2)  (336.1)
Distributions received from unconsolidated affiliates attributable to earnings
  405.9   337.4 
Net losses (gains) attributable to asset sales and related matters  8.4   (2.1)
Deferred income tax expense (benefit)  33.1   (149.0)
Change in fair market value of derivative instruments  (86.3)  (53.7)
Change in fair market value of Liquidity Option  0   2.3 
Non-cash expense related to long-term operating leases (see Note 16)  29.5   29.6 
Net effect of changes in operating accounts (see Note 17)  1,047.1   (692.0)
Other operating activities  (0.5)  (0.1)
Net cash flows provided by operating activities  6,387.3   4,291.6 
Investing activities:        
Capital expenditures  (1,805.7)  (2,671.6)
Investments in unconsolidated affiliates  (1.3)  (9.9)
Distributions received from unconsolidated affiliates attributable to the return of capital
  41.2   124.9 
Proceeds from asset sales  58.1   8.4 
Other investing activities  (13.8)  (16.0)
Cash used in investing activities  (1,721.5)  (2,564.2)
Financing activities:        
Borrowings under debt agreements  11,158.5   6,672.1 
Repayments of debt  (11,491.8)  (4,406.6)
Debt issuance costs  (15.1)  (46.3)
Monetization of interest rate derivative instruments  75.2   (33.3)
Cash distributions paid to common unitholders (see Note 8)  (2,948.5)  (2,919.6)
Cash payments made in connection with distribution equivalent rights  (23.1)  (20.0)
Cash distributions paid to noncontrolling interests  (115.1)  (97.8)
Cash contributions from noncontrolling interests  23.0   21.2 
Repurchase of common units under 2019 Buyback Program (see Note 8)  (88.8)  (173.8)
Net cash proceeds from the issuance of preferred units  0   32.5 
Other financing activities  (40.1)  (34.7)
Cash used in financing activities
  (3,465.8)  (1,006.3)
Net change in cash and cash equivalents, including restricted cash  1,200.0   721.1 
Cash and cash equivalents, including restricted cash, at beginning of period  1,158.1   410.0 
Cash and cash equivalents, including restricted cash, at end of period $2,358.1  $1,131.1 







See Notes to Unaudited Condensed Consolidated Financial Statements.
5

Table of Contents



ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 20202021
(Dollars in millions)

 Partners’ Equity        Partners’ Equity       
 
Common
Limited
Partner
Interests
  
Treasury
Units
  
Accumulated
Other
Comprehensive
Income (Loss)
  
Noncontrolling
Interests in
Consolidated
Subsidiaries
  Total  
Common
Limited
Partner
Interests
  
Treasury
Units
  
Accumulated
Other
Comprehensive
Income (Loss)
  
Noncontrolling
Interests in
Consolidated
Subsidiaries
  Total 
For the Three Months Ended September 30, 2020:               
Balance, June 30, 2020 $26,321.1  $(1,297.3) $(147.1) $1,064.7  $25,941.4 
For the Three Months Ended September 30, 2021:
               
Balance, June 30, 2021 $26,268.8  $(1,297.3) $(198.7) $1,074.0  $25,846.8 
Net income  1,052.6   0   0   31.4   1,084.0   1,153.0   0   0   28.3   1,181.3 
Cash distributions paid to common unitholders  (972.7)  0   0   0   (972.7)  (983.5)  0   0   0   (983.5)
Cash payments made in connection with
distribution equivalent rights
  (7.1)  0   0   0   (7.1)  (7.9)  0   0   0   (7.9)
Cash distributions paid to noncontrolling interests  0   0   0   (36.0)  (36.0)  0   0   0   (43.7)  (43.7)
Cash contributions from noncontrolling interests  0   0   0   1.5   1.5   0   0   0   4.9   4.9 
Amortization of fair value of equity-based awards  39.5   0   0   0   39.5   35.1   0   0   0   35.1 
Repurchase and cancellation of common units under
2019 Buyback Program (see Note 8)
  (33.7)  0   0   0   (33.7)  (74.9)  0   0   0   (74.9)
Common units exchanged for preferred units, with common
units received being immediately cancelled (see Note 8)
  (17.5)  0   0   0   (17.5)
Cash flow hedges  0   0   97.8   0   97.8   0   0   26.8   0   26.8 
Other, net  (0.3)  0   0   7.8   7.5   (0.3)  0   0.1   (0.1)  (0.3)
Balance, September 30, 2020 $26,381.9  $(1,297.3) $(49.3) $1,069.4  $26,104.7 
Balance, September 30, 2021
 $26,390.3  $(1,297.3) $(171.8) $1,063.4  $25,984.6 



 Partners’ Equity        Partners’ Equity       
 
Common
Limited
Partner
Interests
  
Treasury
Units
  
Accumulated
Other
Comprehensive
Income (Loss)
  
Noncontrolling
Interests in
Consolidated
Subsidiaries
  Total  
Common
Limited
Partner
Interests
  
Treasury
Units
  
Accumulated
Other
Comprehensive
Income (Loss)
  
Noncontrolling
Interests in
Consolidated
Subsidiaries
  Total 
For the Nine Months Ended September 30, 2020:               
Balance, December 31, 2019 $24,692.6  $0  $71.4  $1,063.5  $25,827.5 
For the Nine Months Ended September 30, 2021:
               
Balance, December 31, 2020
 $25,766.6  $(1,297.3) $(165.2) $1,073.3  $25,377.4 
Net income  3,437.4   0   0   82.4   3,519.8   3,605.7   0   0   82.3   3,688.0 
Cash distributions paid to common unitholders  (2,919.6)  0   0   0   (2,919.6)  (2,948.5)  0   0   0   (2,948.5)
Cash payments made in connection with
distribution equivalent rights
  (20.0)  0   0   0   (20.0)  (23.1)  0   0   0   (23.1)
Cash distributions paid to noncontrolling interests  0   0   0   (97.8)  (97.8)  0   0   0   (115.1)  (115.1)
Cash contributions from noncontrolling interests  0   0   0   21.2   21.2   0   0   0   23.0   23.0 
Amortization of fair value of equity-based awards  120.1   0   0   0   120.1   114.6   0   0   0   114.6 
Repurchase and cancellation of common units under
2019 Buyback Program (see Note 8)
  (173.8)  0   0   0   (173.8)  (88.8)  0   0   0   (88.8)
Common units issued to Skyline North Americas, Inc. in
connection with settlement of Liquidity Option (see Note 8)
  1,297.3   0   0   0   1,297.3 
Treasury units acquired in connection with settlement
of Liquidity Option, at cost (see Note 8)
  0   (1,297.3)  0   0   (1,297.3)
Common units exchanged for preferred units, with common
units received being immediately cancelled (see Note 8)
  (17.5)  0   0   0   (17.5)
Cash flow hedges  0   0   (120.6)  0   (120.6)  0   0   (6.4)  0   (6.4)
Other, net  (34.6)  0   (0.1)  0.1   (34.6)  (36.2)  0   (0.2)  (0.1)  (36.5)
Balance, September 30, 2020 $26,381.9  $(1,297.3) $(49.3) $1,069.4  $26,104.7 
Balance, September 30, 2021
 $26,390.3  $(1,297.3) $(171.8) $1,063.4  $25,984.6 














See Notes to Unaudited Condensed Consolidated Financial Statements.  For information regarding Unit History and
Accumulated Other Comprehensive Income (Loss), 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, 20192020
(Dollars in millions)

  Partners’ Equity       
  
Common
Limited
Partner
Interests
  
Accumulated
Other
Comprehensive
Income (Loss)
  
Noncontrolling
Interests in
Consolidated
Subsidiaries
  Total 
For the Three Months Ended September 30, 2019:            
     Balance, June 30, 2019 $24,450.5  $(10.7) $535.6  $24,975.4 
   Net income  1,019.2   0   25.6   1,044.8 
   Cash distributions paid to common unitholders  (963.2)  0   0   (963.2)
   Cash payments made in connection with distribution equivalent rights  (5.9)  0   0   (5.9)
   Cash distributions paid to noncontrolling interests  0   0   (22.8)  (22.8)
   Cash contributions from noncontrolling interests  0   0   491.2   491.2 
   Amortization of fair value of equity-based awards  36.7   0   0   36.7 
   Cash flow hedges  0   (28.4)  0   (28.4)
   Other, net  (2.2)  0   (0.1)  (2.3)
    Balance, September 30, 2019 $24,535.1  $(39.1) $1,029.5  $25,525.5 


 Partners’ Equity        Partners’ Equity       
 
Common
Limited
Partner
Interests
  
Accumulated
Other
Comprehensive
Income (Loss)
  
Noncontrolling
Interests in
Consolidated
Subsidiaries
  Total  
Common
Limited
Partner
Interests
  
Treasury
Units
  
Accumulated
Other
Comprehensive
Income (Loss)
  
Noncontrolling
Interests in
Consolidated
Subsidiaries
  Total 
For the Nine Months Ended September 30, 2019:            
Balance, December 31, 2018 $23,802.6  $50.9  $438.7  $24,292.2 
For the Three Months Ended September 30, 2020:
               
Balance, June 30, 2020 $26,321.1  $(1,297.3) $(147.1) $1,064.7  $25,941.4 
Net income  3,494.4   0   67.3   3,561.7   1,052.6   0   0   31.4   1,084.0 
Cash distributions paid to common unitholders  (2,871.1)  0   0   (2,871.1)  (972.7)  0   0   0   (972.7)
Cash payments made in connection with distribution equivalent rights  (16.4)  0   0   (16.4)  (7.1)  0   0   0   (7.1)
Cash distributions paid to noncontrolling interests  0   0   (69.7)  (69.7)  0   0   0   (36.0)  (36.0)
Cash contributions from noncontrolling interests  0   0   590.8   590.8   0   0   0   1.5   1.5 
Net cash proceeds from the issuance of common units  82.2   0   0   82.2 
Common units issued in connection with employee compensation  45.6   0   0   45.6 
Amortization of fair value of equity-based awards  39.5   0   0   0   39.5 
Repurchase and cancellation of common units under
2019 Buyback Program (see Note 8)
  (81.1)  0   0   (81.1)  (33.7)  0   0   0   (33.7)
Amortization of fair value of equity-based awards  107.2   0   0   107.2 
Common units exchanged for preferred units, with common units received being immediately cancelled  (17.5)  0   0   0   (17.5)
Cash flow hedges  0   (89.4)  0   (89.4)  0   0   97.8   0   97.8 
Other, net  (28.3)  (0.6)  2.4   (26.5)  (0.3)  0   0   7.8   7.5 
Balance, September 30, 2019 $24,535.1  $(39.1) $1,029.5  $25,525.5 
Balance, September 30, 2020
 $26,381.9  $(1,297.3) $(49.3) $1,069.4  $26,104.7 








  Partners’ Equity       
  
Common
Limited
Partner
Interests
  
Treasury
Units
  
Accumulated
Other
Comprehensive
Income (Loss)
  
Noncontrolling
Interests in
Consolidated
Subsidiaries
  Total 
For the Nine Months Ended September 30, 2020:
               
     Balance, December 31, 2019
 $24,692.6  $0  $71.4  $1,063.5  $25,827.5 
   Net income  3,437.4   0   0   82.4   3,519.8 
   Cash distributions paid to common unitholders  (2,919.6)  0   0   0   (2,919.6)
   Cash payments made in connection with
      distribution equivalent rights
  (20.0)  0   0   0   (20.0)
   Cash distributions paid to noncontrolling interests  0   0   0   (97.8)  (97.8)
   Cash contributions from noncontrolling interests  0   0   0   21.2   21.2 
   Amortization of fair value of equity-based awards  120.1   0   0   0   120.1 
   Repurchase and cancellation of common units under
      2019 Buyback Program (see Note 8)
  (173.8)  0   0   0   (173.8)
   Common units issued to Skyline North Americas, Inc. in
      connection with settlement of Liquidity Option
  1,297.3   0   0   0   1,297.3 
   Treasury units acquired in connection with settlement
      of Liquidity Option, at cost
  0   (1,297.3)  0   0   (1,297.3)
   Common units exchanged for preferred units, with common units received being immediately cancelled  (17.5)  0   0   0   (17.5)
   Cash flow hedges  0   0   (120.6)  0   (120.6)
   Other, net  (34.6)  0   (0.1)  0.1   (34.6)
     Balance, September 30, 2020
 $26,381.9  $(1,297.3) $(49.3) $1,069.4  $26,104.7 








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

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

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

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

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

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

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

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

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

We, Enterprise GP, EPCO along with Mr. Fowler, who is alsoand Dan Duncan LLC are affiliates under the Executive Vice Presidentcollective common control of the DD LLC Trustees and Chief Financial Officer of EPCO.the EPCO Trustees.  EPCO, together with its privately held affiliates, owned approximately 32.2% of EPD’sthe Partnership’s common units outstanding and 30% of its preferred units outstanding at September 30, 2020.  See Note 8 for information regarding our issuance of preferred units on September 30, 2020.2021.

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

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

Note 1.  Partnership Organization and Basis of PresentationOperations

The Partnership isWe 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.”  The Partnership’sOur preferred units are not publicly traded.  We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO and are a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, petrochemicals and refined products. 

The Partnership isWe are owned by itsour limited partners (preferred and common unitholders) from an economic perspective.   Enterprise GP, which owns a non-economic general partner interest in the Partnership,us, manages our operations. The Partnership conductsPartnership.  We conduct substantially all of our business operations through EPO and its business through EPO.  We, Enterprise GP, EPCOconsolidated subsidiaries.

Our fully integrated, midstream energy asset network (or “value chain”) links producers of natural gas, NGLs and Dan Duncan LLC are affiliates under the collective common controlcrude oil from some of the DD LLC Trusteeslargest supply basins in the United States (“U.S.”), Canada and the EPCO Trustees.  Gulf of Mexico with domestic consumers and international markets.  Our midstream energy operations include:

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

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

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

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

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

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

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

Our results of operations for the nine months ended September 30, 20202021 are not necessarily indicative of results expected for the full year of 2020.2021.  In our opinion, the accompanying Unaudited Condensed Consolidated Financial Statements include all adjustments consisting of normal recurring accruals necessary for fair presentation.  Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with United States (“U.S.”) generally accepted accounting principles (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”).

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

These Unaudited Condensed Consolidated Financial Statements and Notes thereto should be read in conjunction with the Audited Consolidated Financial Statements and Notes thereto included in our annual report on Form 10-K for the year ended December 31, 20192020  (the “2019“2020 Form 10-K”) filed with the SEC on February 28, 2020.March 1, 2021.




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


Note 2.  Summary of Significant Accounting Policies

Apart from those matters noted below,described in this footnote, there have been no changes inupdates to our significant accounting policies since those reported under Note 2 of the 20192020 Form 10-K.

Allowance for Credit Losses

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

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

Allowance for credit losses, December 31, 2020
 $46.5 
Charged to costs and expenses  2.5 
Charged to other accounts  4.4 
Deductions  (3.4)
Allowance for credit losses, September 30, 2021
 $50.0 

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,
2020
  
December 31,
2019
  
September 30,
2021
  
December 31,
2020
 
Cash and cash equivalents $1,032.2  $334.7  $2,213.5  $1,059.9 
Restricted cash  98.9   75.3   144.6   98.2 
Total cash, cash equivalents and restricted cash shown in the
Unaudited Condensed Statements of Consolidated Cash Flows
 $1,131.1  $410.0  $2,358.1  $1,158.1 

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

Recent Accounting Developments

Credit Losses
In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.  The new guidance, referred to as the current expected credit loss model, requires the measurement of  expected credit losses for financial assets (e.g., accounts receivable) held at the reporting date based on historical experience, current economic conditions, and reasonable and supportable forecasts.  These result in the more timely recognition of losses.  The adoption of this new guidance on January 1, 2020 did not have a material impact on our consolidated financial statements.

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

The adoption of this new guidance on January 1, 2020 did not have a material impact on our consolidated financial statements.  See Note 14 for information regarding our fair value measurements.
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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


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


Note 3.  Inventories

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

 
September 30,
2020
  
December 31,
2019
  
September 30,
2021
  
December 31,
2020
 
NGLs $1,678.1  $1,094.9  $2,500.8  $1,888.1 
Petrochemicals and refined products  800.8   311.5   368.9   642.6 
Crude oil  696.1   674.2   201.3   758.1 
Natural gas  17.6   10.8   24.9   14.7 
Total $3,192.6  $2,091.4  $3,095.9  $3,303.5 
10

Inventories
Table of NGLs, refined products and crude oil increased since December 31, 2019 primarily due to the use of working capital in connection with our marketing activities.Contents
ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 September 30,
 
For the Nine Months
Ended September 30,
 
2020 2019 2020 2019 2021 2020 2021 2020 
Cost of sales (1) $4,313.7  $5,276.5  $12,331.9  $16,721.5  $8,112.8  $4,313.7  $21,215.8  $12,331.9 
Lower of cost or net realizable value adjustments
recognized in cost of sales
  4.4   6.8   55.6   17.1   1.3   4.4   14.2   55.6 

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



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

Note 4.  Property, Plant and Equipment

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

 
Estimated
Useful Life
in Years
  
September 30,
2020
  
December 31,
2019
  
Estimated
Useful Life
in Years
  
September 30,
2021
  
December 31,
2020
 
Plants, pipelines and facilities (1)  3-45(5) $49,050.9  $47,201.2   3-45(5) $50,766.1  $49,972.8 
Underground and other storage facilities (2)  5-40(6)  4,133.7   3,965.5   5-40(6)  4,281.2   4,207.5 
Transportation equipment (3)  3-10   204.1   198.9   3-10   208.2   204.9 
Marine vessels (4)  15-30   928.9   905.9   15-30   941.8   932.7 
Land      376.7   372.3       383.0   371.9 
Construction in progress      2,468.9   2,641.2       2,182.6   1,807.7 
Total      57,163.2   55,285.0 
Subtotal      58,762.9   57,497.5 
Less accumulated depreciation      14,803.1   13,681.6       16,593.1   15,584.7 
Subtotal property, plant and equipment, net      42,169.8   41,912.8 
Capitalized major maintenance costs for reaction-based
plants, net of accumulated amortization (7)
      84.0   0 
Property, plant and equipment, net     $42,360.1  $41,603.4      $42,253.8  $41,912.8 

(1)Plants, pipelines and facilities include processing plants; NGL, natural gas, crude oil and petrochemical and refined products pipelines; terminal loading and unloading facilities; buildings; office furniture and equipment; laboratory and shop equipment and related assets.
(2)Underground and other storage facilities include underground product storage caverns; above ground storage tanks; water wells and related assets.
(3)Transportation equipment includes tractor-trailer tank trucks and other vehicles and similar assets used in our operations.
(4)Marine vessels include tow boats, barges and related equipment used in our marine transportation business.
(5)In general, the estimated useful lives of major assets within this category are: processing plants, 20-35 years; pipelines and related equipment, 5-45 years; terminal facilities, 10-35 years; buildings, 20-40 years; office furniture and equipment, 3-20 years; and laboratory and shop equipment, 5-35 years.
(6)In general, the estimated useful lives of assets within this category are: underground storage facilities, 5-35 years; storage tanks, 10-40 years; and water wells, 5-35 years.
(7)
For reaction-based plants, we use the deferral method when accounting for major maintenance activities.  Under the deferral method, major maintenance costs are capitalized and amortized over the period until the next major overhaul project.   On a weighted-average basis, the expected amortization period for these costs is 2.6 years.

Property, plant and equipment at September 30, 2021 and December 31, 2020 includes $79.1 million and $69.7 million, respectively, of asset retirement costs capitalized as an increase in the associated long-lived asset.
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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table presents information regarding our asset retirement obligations, or AROs, since December 31, 2020:

ARO liability balance, December 31, 2020
 $149.5 
Liabilities incurred (1)  6.5 
Revisions in estimated cash flows (2)  3.9 
Liabilities settled (3)  (0.7)
Accretion expense (4)  8.0 
ARO liability balance, September 30, 2021
 $167.2 

(1)Represents the initial recognition of estimated ARO liabilities during period.
(2)Represents subsequent adjustments to estimated ARO liabilities during period.
(3)Represents cash payments to settle ARO liabilities during period.
(4)Represents net change in ARO liability balance attributable to the passage of time and other adjustments, including true-up amounts associated with revised closure estimates.

Of the $167.2 million total ARO liability recorded at September 30, 2021, $12.9 million was reflected as a current liability and $154.3 million as a long-term liability.

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

For the Three Months
Ended September 30,
 
For the Nine Months
Ended September 30,
  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
2020 2019 2020 2019  2021  2020  2021  2020 
Depreciation expense (1) $420.7  $394.7  $1,251.6  $1,164.6  $425.3  $420.7  $1,273.0  $1,251.6 
Accretion expense (1)  4.2   0.8   8.0   11.0 
Capitalized interest (2)  34.5   33.9   96.9   102.9   23.0   34.5   63.8   96.9 

(1)Depreciation and accretion expense is a component of “Third party and other costs” within “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.


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

Asset impairment charges

In March 2021, we entered into agreements to sell a coal bed natural gas gathering system and related matters

Val Verde treating facility, both of which were components of our San Juan Gathering System, to a third party for $39.1 million in cash.  The transaction closed and was effective on April 1, 2021.  We recognized non-cash assetan impairment charge of $44.3 million attributable to this transaction, which reflects the write down of $37.5 million of property, plant and equipment and $6.8 million of intangible assets (see Note 6) to their respective fair values.  The remainder of our impairment charges of $77.0 million and $90.4 million duringfor the three and nine monthsmonth periods ended September 30, 2021 and 2020 respectively, primarily dueare attributable to the complete write-off of assets that wouldare no longer expected to be used or constructed.  These charges include the $42.0 million of expense we recognized in September 2020 in connection with our cancellation of the Midland-to-ECHO 4 pipeline construction project. We recognized

Asset impairment charges of $39.4 million and $51.2 million during the three and nine months ended September 30, 2019, respectively, primarily duerelated to the complete write-off of assets that would no longer be used.  These impairment chargesoperations are a component of “Third party and other costs” within “Operating costs and expenses” as presented on our Unaudited Condensed Statements of Consolidated Operations. We recognized $0.1 million of impairment charges in the three and nine months ended September 30, 2019 that are a component of general and administrative costs.

We are closely monitoring the recoverability of our long-lived assets, investments in unconsolidated affiliates and goodwill in light of the adverse economic effects of the coronavirus disease 2019 (“COVID-19”) pandemic.  If the adverse economic impacts of the pandemic persist for longer periods than currently expected, these developments could result in the recognition of additional non-cash impairment charges in the future.

In connection with our cancellation of the Midland-to-ECHO 4 pipeline project, we reclassified $311.7 million of pipe and related items that were purchased for the project from construction in progress to long-term spare parts, where they will be held for future use.  Long-term spare parts is a component of “Other assets” as presented on our Unaudited Condensed Consolidated Balance Sheet.

Asset Retirement Obligations

Property, plant and equipment at September 30, 2020 and December 31, 2019 includes $70.2 million and $69.6 million, respectively, of asset retirement costs capitalized as an increase in the associated long-lived asset.  The following table presents information regarding our asset retirement obligations, or AROs, since December 31, 2019:

12
ARO liability balance, December 31, 2019 $132.1 
Liabilities incurred  3.5 
Liabilities settled  (0.6)
Revisions in estimated cash flows  2.9 
Accretion expense  6.1 
ARO liability balance, September 30, 2020 $144.0 


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

Note 5.  Investments in Unconsolidated Affiliates

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


 
September 30,
2020
  
December 31,
2019
  
September 30,
2021
  
December 31,
2020
 
NGL Pipelines & Services $676.4  $703.8  $656.4  $671.6 
Crude Oil Pipelines & Services  1,774.8   1,866.5   1,742.1   1,723.7 
Natural Gas Pipelines & Services  29.9   27.3   32.1   31.4 
Petrochemical & Refined Products Services  4.3   2.6   2.8   2.5 
Total $2,485.4  $2,600.2  $2,433.4  $2,429.2 

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

  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2020  2019  2020  2019 
NGL Pipelines & Services $29.3  $25.9  $90.8  $82.7 
Crude Oil Pipelines & Services  51.8   113.2   243.2   348.8 
Natural Gas Pipelines & Services  1.4   1.6   4.3   4.9 
Petrochemical & Refined Products Services  (0.5)  (1.4)  (2.2)  (5.1)
Total $82.0  $139.3  $336.1  $431.3 

  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2021  2020  2021  2020 
NGL Pipelines & Services $30.5  $29.3  $87.5  $90.8 
Crude Oil Pipelines & Services  105.2   51.8   354.2   243.2 
Natural Gas Pipelines & Services  1.4   1.4   4.3   4.3 
Petrochemical & Refined Products Services  0.5   (0.5)  1.2   (2.2)
Total $137.6  $82.0  $447.2  $336.1 

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

Note 6.  Intangible Assets and Goodwill


Identifiable Intangible Assets

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

 September 30, 2020  December 31, 2019  September 30, 2021  December 31, 2020 
 
Gross
Value
  
Accumulated
Amortization
  
Carrying
Value
  
Gross
Value
  
Accumulated
Amortization
  
Carrying
Value
  
Gross
Value
  
Accumulated
Amortization
  
Carrying
Value
  
Gross
Value
  
Accumulated
Amortization
  
Carrying
Value
 
NGL Pipelines & Services:                                    
Customer relationship intangibles $447.8  $(217.0) $230.8  $447.8  $(206.3) $241.5  $447.8  $(231.3) $216.5  $447.8  $(221.3) $226.5 
Contract-based intangibles  162.6   (52.2)  110.4   162.6   (43.9)  118.7   166.0   (59.3)  106.7   162.6   (55.0)  107.6 
Segment total  610.4   (269.2)  341.2   610.4   (250.2)  360.2   613.8   (290.6)  323.2   610.4   (276.3)  334.1 
Crude Oil Pipelines & Services:                                                
Customer relationship intangibles  2,203.5   (287.5)  1,916.0   2,203.5   (243.5)  1,960.0   2,195.0   (339.2)  1,855.8   2,195.0   (291.6)  1,903.4 
Contract-based intangibles  283.1   (246.7)  36.4   276.9   (235.0)  41.9   283.1   (259.5)  23.6   283.1   (249.9)  33.2 
Segment total  2,486.6   (534.2)  1,952.4   2,480.4   (478.5)  2,001.9   2,478.1   (598.7)  1,879.4   2,478.1   (541.5)  1,936.6 
Natural Gas Pipelines & Services:                                                
Customer relationship intangibles  1,350.3   (504.2)  846.1   1,350.3   (481.6)  868.7   1,350.3   (541.1)  809.2   1,350.3   (512.2)  838.1 
Contract-based intangibles  470.7   (401.7)  69.0   468.0   (395.5)  72.5   231.1   (181.2)  49.9   470.7   (403.8)  66.9 
Segment total  1,821.0   (905.9)  915.1   1,818.3   (877.1)  941.2   1,581.4   (722.3)  859.1   1,821.0   (916.0)  905.0 
Petrochemical & Refined Products Services:                                                
Customer relationship intangibles  181.4   (62.2)  119.2   181.4   (57.5)  123.9   181.4   (72.4)  109.0   181.4   (68.3)  113.1 
Contract-based intangibles  46.0   (25.3)  20.7   46.0   (24.2)  21.8   44.9   (25.6)  19.3   44.9   (24.6)  20.3 
Segment total  227.4   (87.5)  139.9   227.4   (81.7)  145.7   226.3   (98.0)  128.3   226.3   (92.9)  133.4 
Total intangible assets $5,145.4  $(1,796.8) $3,348.6  $5,136.5  $(1,687.5) $3,449.0  $4,899.6  $(1,709.6) $3,190.0  $5,135.8  $(1,826.7) $3,309.1 

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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table presents the amortization expense of our intangible assets by business segment for the periods indicated:

 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
 2020  2019  2020  2019  2021  2020  2021  2020 
NGL Pipelines & Services $6.2  $7.3  $19.0  $25.4  $6.2  $6.2  $18.3  $19.0 
Crude Oil Pipelines & Services  16.0   25.1   55.7   71.2   20.3   16.0   57.2   55.7 
Natural Gas Pipelines & Services  9.0   10.3   28.8   31.2   11.5   9.0   32.7   28.8 
Petrochemical & Refined Products Services  1.9   2.1   5.8   6.5   1.7   1.9   5.1   5.8 
Total $33.1  $44.8  $109.3  $134.3  $39.7  $33.1  $113.3  $109.3 

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

Remainder
of 2020
  2021  2022  2023  2024 
Remainder
of 2021
Remainder
of 2021
  2022  2023  2024  2025 
$45.1  $145.5  $162.3  $169.9  $165.7 37.4  $169.6  $173.8  $177.9  $174.4 

Impairment of Intangible Asset

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

Goodwill

Goodwill represents the excess of the purchase price of an acquired business over the amounts assigned to assets acquired and liabilities assumed in the transaction.  There has been no change in our goodwill amounts since those reported in our 20192020 Form 10-K.

We are closely monitoring the recoverability of our long-lived assets, which include goodwill, in light of the COVID-19 pandemic (see Note 4).pandemic.
  

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

Note 7.  Debt Obligations

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

 
September 30,
2020
  
December 31,
2019
  
September 30,
2021
  
December 31,
2020
 
EPO senior debt obligations:            
Commercial Paper Notes, variable-rates $0  $482.0  $0  $0 
Senior Notes Q, 5.25% fixed-rate, due January 2020  0   500.0 
Senior Notes Y, 5.20% fixed-rate, due September 2020
  0   1,000.0 
Senior Notes TT, 2.80% fixed-rate, due February 2021
  750.0   750.0 
Senior Notes RR, 2.85% fixed-rate, due April 2021
  575.0   575.0 
September 2020 364-Day Revolving Credit Agreement, variable-rate, due September 2021  0   0 
Senior Notes VV, 3.50% fixed-rate, due February 2022  750.0   750.0 
Senior Notes CC, 4.05% fixed-rate, due February 2022  650.0   650.0 
Senior Notes HH, 3.35% fixed-rate, due March 2023  1,250.0   1,250.0 
Senior Notes JJ, 3.90% fixed-rate, due February 2024  850.0   850.0 
Multi-Year Revolving Credit Agreement, variable-rate, due September 2024  0   0 
Senior Notes MM, 3.75% fixed-rate, due February 2025  1,150.0   1,150.0 
Senior Notes PP, 3.70% fixed-rate, due February 2026  875.0   875.0 
Senior Notes SS, 3.95% fixed-rate, due February 2027  575.0   575.0 
Senior Notes WW, 4.15% fixed-rate, due October 2028  1,000.0   1,000.0 
Senior Notes YY, 3.125% fixed-rate, due July 2029  1,250.0   1,250.0 
Senior Notes AAA, 2.80% fixed-rate, due January 2030  1,250.0   0 
Senior Notes D, 6.875% fixed-rate, due March 2033  500.0   500.0 
Senior Notes H, 6.65% fixed-rate, due October 2034  350.0   350.0 
Senior Notes J, 5.75% fixed-rate, due March 2035  250.0   250.0 
Senior Notes W, 7.55% fixed-rate, due April 2038  399.6   399.6 
Senior Notes R, 6.125% fixed-rate, due October 2039  600.0   600.0 
Senior Notes Z, 6.45% fixed-rate, due September 2040  600.0   600.0 
Senior Notes BB, 5.95% fixed-rate, due February 2041  750.0   750.0 
Senior Notes DD, 5.70% fixed-rate, due February 2042  600.0   600.0 
Senior Notes EE, 4.85% fixed-rate, due August 2042  750.0   750.0 
Senior Notes GG, 4.45% fixed-rate, due February 2043  1,100.0   1,100.0 
Senior Notes II, 4.85% fixed-rate, due March 2044  1,400.0   1,400.0 
Senior Notes KK, 5.10% fixed-rate, due February 2045  1,150.0   1,150.0 
Senior Notes QQ, 4.90% fixed-rate, due May 2046  975.0   975.0 
Senior Notes UU, 4.25% fixed-rate, due February 2048  1,250.0   1,250.0 
Senior Notes XX, 4.80% fixed-rate, due February 2049  1,250.0   1,250.0 
Senior Notes ZZ, 4.20% fixed-rate, due January 2050  1,250.0   1,250.0 
Senior Notes BBB, 3.70% fixed-rate, due January 2051  1,000.0   0 
Senior Notes DDD, 3.20% fixed-rate, due February 2052  1,000.0   0 
Senior Notes NN, 4.95% fixed-rate, due October 2054  400.0   400.0 
Senior Notes CCC, 3.95% fixed rate, due January 2060  1,000.0   0 
Senior Notes TT, 2.80% fixed-rate, due February 2021
  0   750.0 
Senior Notes RR, 2.85% fixed-rate, due April 2021
  0   575.0 
Senior Notes VV, 3.50% fixed-rate, due February 2022
  750.0   750.0 
Senior Notes CC, 4.05% fixed-rate, due February 2022
  650.0   650.0 
September 2021 364-Day Revolving Credit Agreement, variable-rate, due September 2022  0   0 
Senior Notes HH, 3.35% fixed-rate, due March 2023
  1,250.0   1,250.0 
Senior Notes JJ, 3.90% fixed-rate, due February 2024
  850.0   850.0 
Senior Notes MM, 3.75% fixed-rate, due February 2025
  1,150.0   1,150.0 
Senior Notes PP, 3.70% fixed-rate, due February 2026
  875.0   875.0 
September 2021 Multi-Year Revolving Credit Agreement, variable-rate, due September 2026  0   0 
Senior Notes SS, 3.95% fixed-rate, due February 2027
  575.0   575.0 
Senior Notes WW, 4.15% fixed-rate, due October 2028
  1,000.0   1,000.0 
Senior Notes YY, 3.125% fixed-rate, due July 2029
  1,250.0   1,250.0 
Senior Notes AAA, 2.80% fixed-rate, due January 2030
  1,250.0   1,250.0 
Senior Notes D, 6.875% fixed-rate, due March 2033
  500.0   500.0 
Senior Notes H, 6.65% fixed-rate, due October 2034
  350.0   350.0 
Senior Notes J, 5.75% fixed-rate, due March 2035
  250.0   250.0 
Senior Notes W, 7.55% fixed-rate, due April 2038
  399.6   399.6 
Senior Notes R, 6.125% fixed-rate, due October 2039
  600.0   600.0 
Senior Notes Z, 6.45% fixed-rate, due September 2040
  600.0   600.0 
Senior Notes BB, 5.95% fixed-rate, due February 2041
  750.0   750.0 
Senior Notes DD, 5.70% fixed-rate, due February 2042
  600.0   600.0 
Senior Notes EE, 4.85% fixed-rate, due August 2042
  750.0   750.0 
Senior Notes GG, 4.45% fixed-rate, due February 2043
  1,100.0   1,100.0 
Senior Notes II, 4.85% fixed-rate, due March 2044
  1,400.0   1,400.0 
Senior Notes KK, 5.10% fixed-rate, due February 2045
  1,150.0   1,150.0 
Senior Notes QQ, 4.90% fixed-rate, due May 2046
  975.0   975.0 
Senior Notes UU, 4.25% fixed-rate, due February 2048
  1,250.0   1,250.0 
Senior Notes XX, 4.80% fixed-rate, due February 2049
  1,250.0   1,250.0 
Senior Notes ZZ, 4.20% fixed-rate, due January 2050
  1,250.0   1,250.0 
Senior Notes BBB, 3.70% fixed-rate, due January 2051
  1,000.0   1,000.0 
Senior Notes DDD, 3.20% fixed-rate, due February 2052
  1,000.0   1,000.0 
Senior Notes EEE, 3.30% fixed-rate, due February 2053
  1,000.0   0 
Senior Notes NN, 4.95% fixed-rate, due October 2054
  400.0   400.0 
Senior Notes CCC, 3.95% fixed rate, due January 2060
  1,000.0   1,000.0 
TEPPCO senior debt obligations:                
TEPPCO Senior Notes, 7.55% fixed-rate, due April 2038  0.4   0.4 
TEPPCO Senior Notes, 7.55% fixed-rate, due April 2038
  0.4   0.4 
Total principal amount of senior debt obligations  27,500.0   25,232.0   27,175.0   27,500.0 
EPO Junior Subordinated Notes C, variable-rate, due June 2067 (1)
  232.2   232.2   232.2   232.2 
EPO Junior Subordinated Notes D, fixed/variable-rate, due August 2077 (2)
  700.0   700.0   700.0   700.0 
EPO Junior Subordinated Notes E, fixed/variable-rate, due August 2077 (3)
  1,000.0   1,000.0   1,000.0   1,000.0 
EPO Junior Subordinated Notes F, fixed/variable-rate, due February 2078 (4)
  700.0   700.0   700.0   700.0 
TEPPCO Junior Subordinated Notes, variable-rate, due June 2067 (1)
  14.2   14.2   14.2   14.2 
Total principal amount of senior and junior debt obligations  30,146.4   27,878.4   29,821.4   30,146.4 
Other, non-principal amounts  (284.4)  (253.3)  (289.3)  (280.7)
Less current maturities of debt  (1,325.0)  (1,981.9)  (1,399.3)  (1,325.0)
Total long-term debt $28,537.0  $25,643.2  $28,132.8  $28,540.7 

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

References to “TEPPCO” mean TEPPCO Partners, L.P. prior to its merger with one of our wholly owned subsidiaries in October 2009.
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Variable Interest Rates

The following table presents the range of interest rates and weighted-average interest rates paid on our consolidated variable-rate debt during the nine months ended September 30, 2020:2021:

Range of Interest
Rates Paid
Weighted-Average
Interest Rate Paid
Commercial Paper Notes1.78%0.15% to 2.08%0.25%1.86%0.21%
EPO Junior Subordinated Notes C and TEPPCO Junior Subordinated Notes3.02%2.90% to 4.68%3.00%3.87%2.95%

Amounts borrowed under EPO’s September 2021 364-Day Revolving Credit Agreement and September 2021 Multi-Year Revolving Credit AgreementsAgreement bear interest, at its election, equal to: (i) LIBOR, plus an additional variable spread; or (ii) an alternate base rate, which is the greatergreatest 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 RateLIBOR for an interest period of one month in effect on such day plus 1%, and a variable spread. The applicable spreads are determined based on EPO's debt ratings.

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

Scheduled Maturities of Debt

The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations at September 30, 20202021 for the next five years, and in total thereafter:

     Scheduled Maturities of Debt 
  Total  
Remainder
of 2020
  2021  2022  2023  2024  Thereafter 
Principal amount of senior and junior debt obligations $30,146.4  $0  $1,325.0  $1,400.0  $1,250.0  $850.0  $25,321.4 
   Scheduled Maturities of Debt 
 Total 
Remainder
of 2021
 2022 2023 2024 2025 Thereafter 
Senior Notes $27,175.0  $0  $1,400.0  $1,250.0  $850.0  $1,150.0  $22,525.0 
Junior Subordinated Notes  2,646.4   0   0   0   0   0   2,646.4 
Total $29,821.4  $0  $1,400.0  $1,250.0  $850.0  $1,150.0  $25,171.4 

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

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

September 20202021 364-Day Revolving Credit Agreement

In September 2020,2021, EPO entered into a new 364-Day Revolving Credit Agreement (the “September 2021 364-Day Revolving Credit Agreement”) that replaced its September 20192020 364-Day Revolving Credit Agreement.  The new 364-Day Revolving Credit Agreement matures in September 2021. There waswere no principal amountamounts outstanding under the September 20192020 364-Day Revolving Credit Agreement when it expired and was replaced by the September 20202021 364-Day Revolving Credit Agreement.  At September 30, 2021, there were no principal amounts outstanding under the September 2021 364-Day Revolving Credit Agreement.

Under the terms of the September 20202021 364-Day Revolving Credit Agreement, EPO may borrow up to $1.5 billion (which may be increased by up to $200$200.0 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.  The September 2021 364-Day Revolving Credit Agreement matures in September 2022. 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 2022.2023.  Borrowings under the September 20202021 364-Day Revolving Credit Agreement may be used for working capital, capital expenditures, acquisitions and general company purposes.
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The September 20202021 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 September 20202021 364-Day Revolving Credit Agreement also restricts EPO’s ability to pay cash distributions to its parent, Enterprise Products Partners L.P.,the Partnership, 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 September 20202021 364-Day Revolving Credit Agreement are not secured by any collateral; however, they are guaranteed by Enterprise Products Partners L.P.the Partnership.

15September 2021 Multi-Year Revolving Credit Agreement

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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTSIn September 2021, EPO entered into a new revolving credit agreement that matures in September 2026 (the “September 2021 Multi-Year Revolving Credit Agreement”).  The September 2021 Multi-Year Revolving Credit Agreement replaced EPO’s prior multi-year revolving credit agreement that was scheduled to mature in September 2024.  There were no principal amounts outstanding under the prior multi-year revolving credit agreement when it was replaced by the September 2021 Multi Year Revolving Credit Agreement.  At September 30, 2021, there were no principal amounts outstanding under the September 2021 Multi-Year Revolving Credit Agreement.

Under the terms of the September 2021 Multi-Year Revolving Credit Agreement, EPO may borrow up to $3.0 billion (which may be increased by up to $500.0 million to $3.5 billion at EPO’s election, provided certain conditions are met) at a variable interest rate for a term of five years, subject to the terms and conditions set forth therein.  Borrowings under the September 2021 Multi-Year Revolving Credit Agreement may be used as a backstop for commercial paper and for working capital, capital expenditures, acquisitions and general company purposes.

August 2020The September 2021 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 September 2021 Multi-Year Revolving Credit Agreement also restricts EPO’s ability to pay cash distributions to the Partnership, 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 September 2021 Multi-Year Revolving Credit Agreement are not secured by any collateral; however, they are guaranteed by the Partnership.

September 2021 Senior Notes Offering

In August 2020,September 2021, EPO issued $1.0 billion in principal amount of 3.20% senior notes due February 20522053 (“Senior Notes DDD”EEE”) and $250.0 million in principal amount of 2.80% reopened.  Senior Notes AAA (as defined below).  The reopened Senior Notes AAA and the Senior Notes DDDEEE were issued at 107.211% and 99.233%99.170% of their principal amounts, respectively.amount and have a fixed rate of interest of 3.30% per year.

We received aggregate net proceeds of $1.25 billion from the sale of the notes after deducting underwriting discounts and other estimated offering expenses payable by us.  Net proceeds from the issuance of these senior notes will be used for general company purposes, including for growth capital investments, and to repay all or partthe repayment of debt (including the repayment of a portion of our $750.0 million in principal amount of 3.50% Senior Notes TT, which matureVV and/or a portion of our $650.0 million in February 2021.

The reopened Senior Notes AAA represent a re-opening of an outstanding series of EPO’s senior notes. EPO originally issued $1.0 billion principal amount of 4.05% Senior Notes AAA on January 15, 2020. The reopened Senior Notes AAA form a single series with the original notes of that series, trade under the same CUSIP number, and have the same terms as to status, redemption or otherwise as the original notes of that series.CC, in each case at their maturity in February 2022).

EPO’s fixed-rate senior notes are unsecured obligations of EPO that rank equal with its existing and future unsecured and unsubordinated indebtedness.  They are senior to any existing and future subordinated indebtedness of EPO.  EPO’s senior notes are subject to make-whole redemption rights and were issued under indentures containing certain covenants, which generally restrict its ability (with certain exceptions) to incur debt secured by liens and engage in sale and leaseback transactions. 

April 2020 364-Day RevolvingLetters of Credit Agreement

In April 2020,At September 30, 2021, EPO entered into an additional 364-day revolvinghad $88.0 million of letters of credit agreement (the “April 2020 364-Day Revolving Credit Agreement”). The new agreement provided EPO with an incremental $1.0 billion of borrowing capacity at a variable interest rate for a term of 364 days, subjectoutstanding primarily related to the terms and conditions set forth therein.our commodity hedging activities.
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Following execution
Table of the September 2020 364-Day Revolving Credit Agreement, EPO terminated the April 2020 364-Day Revolving Credit Agreement on September 11, 2020.Contents

ENTERPRISE PRODUCTS PARTNERS L.P.
January 2020 Senior Notes OfferingNOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 were used by EPO for the repayment of $1.0 billion principal amount of its Senior Notes Y that matured in September 2020.

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

Lender Financial Covenants

We were in compliance with the financial covenants of our consolidated debt agreements at September 30, 2020.2021.

Letters of Credit

At September 30, 2020, EPO had $200.7 million of letters of credit outstanding primarily related to our commodity hedging activities.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Parent-Subsidiary Guarantor Relationships

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


Note 8.  Capital Accounts

Common Limited Partner Interests

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

Common units outstanding at December 31, 2019
2,189,226,130
Common units issued to Skyline North Americas, Inc. in connection with
   settlement of Liquidity Option in March 2020
  54,807,3522,182,308,958 
Treasury units acquired in connection with settlement of Liquidity Option in March 2020(54,807,352)
Common unit repurchases under 2019 Buyback Program  (6,357,739709,816)
Common units issued in connection with the vesting of phantom unit awards, net  2,912,2143,553,313 
Other  19,63826,148 
Common units outstanding at March 31, 20202021  2,185,800,2432,185,178,603 
Common units issued in connection with the vesting of phantom unit awards, net  96,190203,066 
Common units outstanding at June 30, 20202021  2,185,896,4332,185,381,669 
Common units exchanged for preferred units in September 2020,
   with the common units received being immediately cancelled
(1,120,588)
Common unit repurchases under 2019 Buyback Program  (1,984,5073,367,377)
Common units issued in connection with the vesting of phantom unit awards, net  89,641115,665 
UnitsCommon units outstanding at September 30, 20202021  2,182,880,9792,182,129,957 

Registration Statements
We have a universal shelf registration statement (the “2019 Shelf”) on file with the SEC which allows the Partnership and EPO (each on a standalone basis) to issue an unlimited amount of equity and debt securities, respectively. EPO issued $4.25 billion of senior notes during 2020 using the 2019 Shelf (see Note 7).

In addition, EPDthe Partnership has a registration statement on file with the SEC covering the issuance of up to $2.54 billion of its common units in amounts, at prices and on terms to be determined bybased on market conditions and other factors at the time of such offerings in connection with its(referred to as the Partnership’s at-the-market (“ATM”) program.  During the nine months ended September 30, 2020 and 2019, EPDprogram).  The Partnership did not issue any common units under its ATM program.  After taking into accountprogram during the aggregate sales price of common units sold under the ATM program throughnine months ended September 30, 2020, EPD has the2021.  The Partnership’s capacity to issue additional common units under itsthe ATM program up to an aggregate sales priceremains at $2.54 billion as of $2.54 billion. The existing ATM registration statement expires in November 2020, at which time we expect to file a replacement ATM registration statement with the SEC in order to maintain our financial flexibility.September 30, 2021.

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

March 2020 Issuance of Common Units to Skyline North Americas, Inc. and related acquisition of Treasury Units
In February 2020, the Partnership received notice from Marquard & Bahls AG (“M&B”) of M&B’s election to exercise its rights (the “Liquidity Option”) under the Liquidity Option Agreement among the Partnership, OTA Holdings, Inc., a Delaware corporation previously named Oiltanking Holding Americas, Inc. (“OTA”), and M&B dated October 1, 2014 (the “Liquidity Option Agreement”).  On March 5, 2020, the Partnership settled its obligations under the Liquidity Option Agreement by issuing 54,807,352 new common units to Skyline North Americas, Inc. (“Skyline,” an affiliate of M&B) in exchange for the capital stock of OTA.   As a result of the settlement, OTA became a consolidated subsidiary of ours and we indirectly acquired the 54,807,352 Partnership common units owned by OTA (which were issued by the Partnership 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 Partnership common units it owned and the related deferred tax liability, respectively.

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


At March 5, 2020, the Partnership’s accrual for the Liquidity Option liability was $511.9 million.  The Liquidity Option liability, at any measurement date, represented the fair value of estimated federal and state income taxes that we believe a market participant would assume 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 common units issued by the Partnership to Skyline was $1.30 billion based on a closing price of $23.67 per unit on March 5, 2020.

The 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, the Partnership 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 the Partnership prepare and file a registration statement to permit and otherwise facilitate the public resale of all or a portion of the Partnership’s common units owned by Skyline and its affiliates.  The Partnership’s obligation to Skyline to effect such transactions is limited to 5 registration statements and underwritten offerings.  In May 2020, the Partnership filed a registration statement on behalf of Skyline for the resale of up to 54,807,352 common units. This registration statement is effective and, in June 2020, the Partnership filed a prospectus supplement to this registration statement that allows Skyline to sell up to $500 million of the Partnership’s common units it owns in connection with an “at-the-market” program that it administers.   We do not receive any proceeds from such offerings.

As a result of the Liquidity Option settlement, the partners’ equity balance for common units (as presented on our Unaudited Condensed Consolidated Balance Sheet) increased by $1.30 billion, representing the market value of the Partnership’s common units issued to Skyline.

Since OTA does not meet the definition of a business as described in Accounting Standards Codification (“ASC”) 805, Business Combinations, the OTA transaction was accounted for as the reacquisition of limited partner units and the assumption of OTA’s related deferred tax liability by the Partnership.  In consolidation, we present the limited partner units owned by OTA as treasury units, with their historical cost equal to the $1.30 billion market value of the Partnership common units issued to Skyline.  On September 30, 2020, OTA exchanged the common units it holds for preferred units issued by the Partnership.  For information regarding the preferred units and exchange transaction, see “Redeemable Preferred Limited Partner Interests” within this Note 8.

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.

Prior to March 5, 2020, changes in the estimated fair value of the Liquidity Option liability were recognized in earnings as a component of other income (expense) on our Unaudited Condensed Statements of Consolidated Operations.  We recognized $2.3 million of expense for the period January 1, 2020 to March 5, 2020 attributable to changes in the estimated fair value of the Liquidity Option.  We recognized $38.7 million and $123.1 million of such expense for the three and nine months ended September 30, 2019, respectively.

Common Unit Repurchases Under 2019 Buyback Program
In January 2019, we announced that the Board of Enterprise GP had approved a $2.0 billion multi-year unit buyback program (the “2019 Buyback Program”), which provides the Partnership with an additional method to return capital to investors. The 2019 Buyback Program authorizes the Partnership to repurchase its common units from time to time, including through open market purchases and negotiated transactions.  The timing and pace of buy backs under the program will be determined by a number of factors including (i) our financial performance and flexibility, (ii) organic growth and acquisition opportunities with higher potential returns on investment, (iii) the Partnership’s unit market 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.

The Partnership repurchased an aggregate 3,367,377 and 4,077,193 common units through open market purchases during the three and nine months ended September 30, 2021, respectively.  The total cost of these repurchases, including commissions and fees, was $74.9 million and $88.8 million, respectively.  During the three and nine months ended September 30, 2020, the Partnership repurchased 1,984,507 and 8,342,246 common units, respectively, under the 2019 Buyback Program.  The total cost of these repurchases, including commissions and fees, was $33.7 million and $173.8 million, respectively.  Units repurchased under the 2019 Buyback Program are immediately cancelled upon acquisition.  At September 30, 2021, the remaining available capacity under the 2019 Buyback Program was $1.64 billion.
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


The Partnership repurchased an aggregate 8,342,246 common units under the 2019 Buyback Program through open market and private purchases during the nine months ended September 30, 2020.  The total purchase price of these repurchases was $173.8 million including commissions and fees. During the nine months ended September 30, 2019, the Partnership repurchased 2,909,128 common units under the 2019 Buyback Program for a total purchase price of $81.1 million including commissions and fees.  Units repurchased under the 2019 Buyback Program are immediately cancelled upon acquisition.

At September 30, 2020, the remaining available capacity under the 2019 Buyback Program was $1.75 billion.

Common Units Issued in Connection With the Vesting of Phantom Unit Awards
During the nine months ended September 30, 2020, afterAfter taking into account tax withholding requirements, the Partnership issued a net 3,098,0453,872,044 new common units to employees in connection with the vesting of phantom unit awards.awards during the nine months ended September 30, 2021.  See Note 1312 for information regarding our phantom unit awards.

Common Units Delivered Under DRIP and EUPP
The Partnership has registration statements on file with the SEC in connection with its distribution reinvestment plan (“DRIP”) and employee unit purchase plan (“EUPP”). In July 2019, the Partnership announced that, beginning with the quarterly distribution payment paid in August 2019, it would use common units purchased on the open market, rather than issuing new common units, to satisfy its delivery obligations under the DRIP and EUPP.  This election is subject to change in future quarters depending on the Partnership’s need for equity capital.

During the nine months ended September 30, 2020, a total2021, agents of the Partnership purchased 5,148,4684,754,016 common units were purchased on the open market and delivered them to participants in connection with the DRIP and EUPP.  Apart from $1.8$2.9 million attributable to the plan discount available to all participants in the EUPP, the funds used to effect these purchases were sourced from the DRIP and EUPP participants.  No other Partnership funds were used to satisfy these obligations.  We plan to use open market purchases to satisfy DRIP and EUPP reinvestments in connection with the distribution expected to be paid on November 12, 2020.2021.

Redeemable Preferred Limited Partner InterestsUnits

On September 30, 2020,The following table summarizes changes in the Partnership issued and sold an aggregatenumber of 50,000our Series A Cumulative Convertible Preferred Units in a private placement transaction.  The stated value(“preferred units”) outstanding since December 31, 2020:

Preferred units outstanding at December 31, 2020
50,138
Paid in-kind distribution to related party274
Preferred units outstanding at March 31, 2021, June 30, 2021 and September 30, 2021
50,412

We present the capital accounts attributable to our preferred unitholders as mezzanine equity on our consolidated balance sheets since the terms of each preferred unit is $1,000 per unit.  The total offering price for the preferred units was $50.0allow for cash redemption by such unitholders in the event of a Change of Control (as defined in our partnership agreement), without regard to the likelihood of such an event.

During the nine months ended September 30, 2021, the Partnership made quarterly distributions to its third party and related party preferred unitholders valued at $2.8 million, consisting of paid-in-kind distributions of 274 new preferred units and $2.5 million of which $32.5 million was received in cash with the remaining $17.5 million funded through the exchange of 1,120,588 of the Partnership’s common units owned by the purchasers.  Cash proceeds from the preferred unit offering include $15.0 million received fromcash.

In March 2021, a privately held affiliate of EPCO for the purchase of 15,000 preferred units.

Concurrently, the Partnership exchanged all of the 54,807,352 Partnership common units owned directly by OTA for 855,915 ofsold its entire ownership interest in the Partnership’s new preferred units having an equivalent value.  The preferred units held by OTA, like the common units OTA held prior to the exchange, are accounted for as treasury units by the Partnership in consolidation.  The historical cost of the treasury units did not change as a result of the exchange and remains at the $1.30 billion recognized in March 2020 in connection with settlement of the Liquidity Option.third parties.
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


The preferred units represent a new class of limited partner interests authorized under the Partnership’s Seventh Amended and Restated Agreement of Limited Partnership dated September 30, 2020 (the “Amended Partnership Agreement”).  As described in the Amended Partnership Agreement, key terms of the preferred units include the following:

With respect to distribution and liquidation rights, the preferred units rank senior to the Partnership’s common units. Preferred units held by persons other than the Partnership, its subsidiaries and its affiliates generally will vote on an as-converted basis with the Partnership’s common units and have certain class voting rights with respect to certain protective matters.

Holders of the preferred units are entitled to receive cumulative quarterly distributions at a rate of 7.25% per annum. The Partnership is prohibited from paying distributions on its common units unless full cumulative distributions on the preferred units are paid or set aside for payment. The Partnership may satisfy its obligation to pay distributions to the preferred unitholders through the issuance, in whole or in part, of additional preferred units (referred to as paid-in kind or “PIK” distributions), with the remainder in cash, subject to certain rights of a holder to elect all cash and other conditions as described in the Amended Partnership Agreement.  The exchange by OTA of its common units for PIK-eligible preferred units enables the Partnership to more effectively manage its consolidated cash balances.

Subject to certain limitations, each preferred unitholder may elect to convert its preferred units on or after September 30, 2025 into a number of the Partnership’s common units equal to (a) the number of preferred units to be converted multiplied by (b) the quotient of (i) $1,000 plus any accrued and unpaid distributions per preferred unit, divided by (ii) 92.5% of the volume-weighted average price of the Partnership’s common units at the time of conversion (as defined in the underlying agreements). In addition, each preferred unitholder may convert its preferred units into common units if EPO’s senior notes cease to have an investment grade rating or a Change of Control (as defined in the Amended Partnership Agreement) occurs, in each case based on the conversion ratio specified in the Amended Partnership Agreement.

•
The Partnership may elect to redeem the preferred units for cash, in whole or in part, based on a redemption price outlined in the following schedule, plus any accrued and unpaid distributions at the redemption date:

$1,100 per preferred unit from September 30, 2020 through September 29, 2022;
$1,070 per preferred unit from September 30, 2022 through September 29, 2024;
$1,030 per preferred unit from September 30, 2024 through September 29, 2025;
$1,010 per preferred unit from September 30, 2025 through September 29, 2026; and
$1,000 per preferred unit on or after September 30, 2026; however,
if a Change of Control event occurs prior to September 30, 2026, the redemption price is $1,010 per preferred unit.

In connection with a redemption at the Partnership’s election, the Partnership may convert up to 50% of the preferred units being redeemed into common units (and to pay cash with respect to the remainder), with each such preferred unit being converted on the applicable redemption date into a number of common units equal to (i) the then-applicable preferred unit redemption price divided by (ii) 92.5% of the volume-weighted average price of the Partnership’s common units at the time of conversion (as defined in the underlying agreements).

The Partnership has agreed to prepare and file a registration statement that would permit or otherwise facilitate the public resale of any common units resulting from the conversion of the preferred units to common units.

Our Unaudited Condensed Consolidated Balance Sheet at September 30, 2020 presents the capital accounts of the third-party and related party purchasers of the preferred units as mezzanine equity since the terms of the preferred units allow for cash redemption by the holders in a Change of Control event, without regard to the likelihood of such an event.  The preferred units held by OTA are presented as treasury units in consolidation since their ultimate disposition remains under the control of the Partnership.
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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       
  
Commodity
Derivative
Instruments
  
Interest Rate
Derivative
Instruments
  Other  
Total
 
Accumulated Other Comprehensive Income, December 31, 2019 $55.1  $13.9  $2.4  $71.4 
Other comprehensive income (loss) for period, before reclassifications  392.7   (207.7)  (0.1)  184.9 
Reclassification of losses (gains) to net income during period  (334.8)  29.2   0   (305.6)
Total other comprehensive income (loss) for period  57.9   (178.5)  (0.1)  (120.7)
Accumulated Other Comprehensive Income (Loss), September 30, 2020 $113.0  $(164.6) $2.3  $(49.3)
  Cash Flow Hedges       
  
Commodity
Derivative
Instruments
  
Interest Rate
Derivative
Instruments
  Other  
Total
 
Accumulated Other Comprehensive Income (Loss), December 31, 2020
 $(93.2) $(74.3) $2.3  $(165.2)
Other comprehensive income (loss) for period, before reclassifications  (852.2)  182.9   (0.3)  (669.6)
Reclassification of losses to net income during period  633.8   29.1   0.1   663.0 
Total other comprehensive income (loss) for period  (218.4)  212.0   (0.2)  (6.6)
Accumulated Other Comprehensive Income (Loss), September 30, 2021
 $(311.6) $137.7  $2.1  $(171.8)

 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   392.7   (207.7)  (0.1)  184.9 
Reclassification of losses (gains) to net income during period  (152.0)  27.8   0   (124.2)  (334.8)  29.2   0   (305.6)
Total other comprehensive income (loss) for period  (93.4)  4.0   (0.6)  (90.0)  57.9   (178.5)  (0.1)  (120.7)
Accumulated Other Comprehensive Income (Loss), September 30, 2019 $59.3  $(100.8) $2.4  $(39.1)
Accumulated Other Comprehensive Income (Loss), September 30, 2020
 $113.0  $(164.6) $2.3  $(49.3)

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

   
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
   
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
Losses (gains) on cash flow hedges:Location 2020  2019  2020  2019 Location 2021  2020  2021  2020 
Interest rate derivativesInterest expense $9.9  $9.4  $29.2  $27.8 Interest expense $10.3  $9.9  $29.1  $29.2 
Commodity derivativesRevenue  19.5   (93.6)  (344.7)  (161.4)Revenue  116.8   19.5   614.9   (344.7)
Commodity derivativesOperating costs and expenses  10.0   2.1   9.9   9.4 Operating costs and expenses  0.3   10.0   18.9   9.9 
Total  $39.4  $(82.1) $(305.6) $(124.2)  $127.4  $39.4  $662.9  $(305.6)

For information regarding our interest rate and commodity derivative instruments, see Note 14.13.

Cash Distributions

On October 7, 2020,12, 2021, we announced that the Board declared a quarterly cash distribution of $0.4450$0.45 per common unit, or $1.78$1.80 per common unit on an annualized basis, to be paid to the Partnership’s common unitholders with respect to the third quarter of 2020.2021.  The quarterly distribution is payable on November 12, 20202021 to unitholders of record as of the close of business on October 30, 2020.  In light of current economic conditions, management will evaluate any future increases in cash distributions29, 2021.  The total amount to be paid is $989.7 million, which includes $7.8 million for distribution equivalent rights (“DERs”) on a quarterly basis.  phantom unit awards.

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


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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 September 30,
  
For the Nine Months
Ended September 30,
 
 2020  2019  2020  2019  2021  2020  2021  2020 
NGL Pipelines & Services:                        
Sales of NGLs and related products $2,048.4  $2,624.9  $6,401.7  $7,955.5  $3,169.6  $2,048.4  $9,151.0  $6,401.7 
Segment midstream services:                                
Natural gas processing and fractionation  205.4   279.6   575.8   837.3   253.6   205.4   688.5   575.8 
Transportation  254.7   248.2   769.6   767.4   235.0   254.7   745.1   769.6 
Storage and terminals  105.5   99.4   311.3   291.0   158.4   105.5   402.6   311.3 
Total segment midstream services  565.6   627.2   1,656.7   1,895.7   647.0   565.6   1,836.2   1,656.7 
Total NGL Pipelines & Services  2,614.0   3,252.1   8,058.4   9,851.2   3,816.6   2,614.0   10,987.2   8,058.4 
Crude Oil Pipelines & Services:                                
Sales of crude oil  1,216.1   2,130.0   4,059.7   6,990.1   2,890.0   1,216.1   6,868.2   4,059.7 
Segment midstream services:                                
Transportation  189.3   209.1   603.5   598.1   232.9   189.3   691.4   603.5 
Storage and terminals  116.2   139.2   360.5   364.0   111.7   116.2   344.0   360.5 
Total segment midstream services  305.5   348.3   964.0   962.1   344.6   305.5   1,035.4   964.0 
Total Crude Oil Pipelines & Services  1,521.6   2,478.3   5,023.7   7,952.2   3,234.6   1,521.6   7,903.6   5,023.7 
Natural Gas Pipelines & Services:                                
Sales of natural gas  350.7   440.0   1,097.6   1,627.1   732.2   350.7   2,543.1   1,097.6 
Segment midstream services:                                
Transportation  256.2   275.5   765.1   835.2   247.7   256.2   732.7   765.1 
Total segment midstream services  256.2   275.5   765.1   835.2   247.7   256.2   732.7   765.1 
Total Natural Gas Pipelines & Services  606.9   715.5   1,862.7   2,462.3   979.9   606.9   3,275.8   1,862.7 
Petrochemical & Refined Products Services:                                
Sales of petrochemicals and refined products  1,966.2   1,299.0   4,593.7   3,867.3   2,537.8   1,966.2   6,523.6   4,593.7 
Segment midstream services:                                
Fractionation and isomerization  54.6   43.2   129.0   125.5   81.0   54.6   214.6   129.0 
Transportation, including marine logistics  115.2   134.4   365.5   393.2   116.2   115.2   357.1   365.5 
Storage and terminals  43.5   41.6   122.5   132.2   65.2   43.5   174.8   122.5 
Total segment midstream services  213.3   219.2   617.0   650.9   262.4   213.3   746.5   617.0 
Total Petrochemical & Refined Products Services  2,179.5   1,518.2   5,210.7   4,518.2   2,800.2   2,179.5   7,270.1   5,210.7 
Total consolidated revenues $6,922.0  $7,964.1  $20,155.5  $24,783.9  $10,831.3  $6,922.0  $29,436.7  $20,155.5 

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

Unbilled Revenue and Deferred Revenue

The following table provides information regarding our contract assets and contract liabilities at September 30, 2020:2021:

Contract AssetLocation Balance Location Balance 
Unbilled revenue (current amount)Prepaid and other current assets $173.1 Prepaid and other current assets $164.9 
Total  $173.1   $164.9 

Contract LiabilityLocation Balance Location Balance 
Deferred revenue (current amount)Other current liabilities $162.0 Other current liabilities $164.9 
Deferred revenue (noncurrent)Other long-term liabilities  206.4 Other long-term liabilities  238.5 
Total  $368.4   $403.4 

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


The following table presents significant changes in our unbilled revenue and deferred revenue balances for the nine months ended September 30, 2020:2021:

 
Unbilled
Revenue
  
Deferred
Revenue
  
Unbilled
Revenue
  
Deferred
Revenue
 
Balance at December 31, 2019 $17.6  $314.9 
Balance at December 31, 2020 $18.8  $343.5 
Amount included in opening balance transferred to other accounts during period (1)  (17.6)  (101.7)  (18.8)  (134.4)
Amount recorded during period (2)  253.0   486.7   199.9   686.6 
Amounts recorded during period transferred to other accounts (1)  (79.9)  (325.5)  (35.0)  (481.4)
Other changes  0   (6.0)  0   (10.9)
Balance at September 30, 2020 $173.1  $368.4 
Balance at September 30, 2021 $164.9  $403.4 

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

The increase in unbilled revenue since December 31, 2019 is primarily due to the recognition of deficiency fee revenues on our EFS Midstream System that are not billable to the customer until the end of 2020.

Remaining Performance Obligations

The following table presents estimated fixed future consideration from revenue contracts that contain minimum volume commitments, deficiency and similar fees and the term of the contracts exceeds one year.  These amounts represent the revenues we expect to recognize in future periods from these contracts as of September 30, 2020.2021.

Period 
Fixed
Consideration
  
Fixed
Consideration
 
Three Months Ended December 31, 2020 $988.5 
One Year Ended December 31, 2021  3,804.7 
Three Months Ended December 31, 2021 $1,003.5 
One Year Ended December 31, 2022  3,375.9   3,589.2 
One Year Ended December 31, 2023  3,016.8   3,025.5 
One Year Ended December 31, 2024  2,848.3   2,830.8 
Thereafter
  15,315.9 
One Year Ended December 31, 2025  2,476.9 
Thereafter 0
  11,113.3 
Total $29,350.1  $24,039.2 



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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.  Our business segments are generally organized and managed according to the types of services rendered (or technologies employed) and products produced and/or sold.  

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

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

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

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

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

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

Segment Gross Operating Margin

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

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 September 30,
  
For the Nine Months
Ended September 30,
 
 2020  2019  2020  2019  2021  2020  2021  2020 
Operating income $1,382.5  $1,474.2  $4,326.9  $4,660.7  $1,513.1  $1,382.5  $4,700.2  $4,326.9 
Adjustments to reconcile operating income to total segment gross operating margin
(addition or subtraction indicated by sign):
                                
Depreciation, amortization and accretion expense in operating costs and expenses(1)  484.2   467.1   1,461.3   1,380.8   502.7   484.2   1,497.9   1,461.3 
Asset impairment and related charges in operating costs and expenses  77.0   39.4   90.4   51.2 
Net gains attributable to asset sales in operating costs and expenses  (0.6)  (0.1)  (2.1)  (2.6)
Asset impairment charges in operating costs and expenses  29.3   77.0   112.7   90.4 
Net losses (gains) attributable to asset sales and related matters in operating costs
and expenses
  (2.2)  (0.6)  9.0   (2.1)
General and administrative costs  50.3   55.5   162.8   160.2   47.3   50.3   155.1   162.8 
Non-refundable payments received from shippers attributable to make-up rights (1)(2)
  49.3   20.8   79.1   34.3   25.4   49.3   67.0   79.1 
Subsequent recognition of revenues attributable to make-up rights (2)(3)  (9.4)  (5.5)  (25.0)  (18.6)  (35.2)  (9.4)  (113.4)  (25.0)
Total segment gross operating margin $2,033.3  $2,051.4  $6,093.4  $6,266.0  $2,080.4  $2,033.3  $6,428.5  $6,093.4 

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

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

  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2020  2019  2020  2019 
Gross operating margin by segment:            
NGL Pipelines & Services $1,028.1  $1,008.3  $3,038.2  $2,933.8 
Crude Oil Pipelines & Services  481.8   496.2   1,569.1   1,671.7 
Natural Gas Pipelines & Services  208.4   258.5   701.1   824.6 
Petrochemical & Refined Products Services  315.0   288.4   785.0   835.9 
Total segment gross operating margin $2,033.3  $2,051.4  $6,093.4  $6,266.0 

  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2021  2020  2021  2020 
Gross operating margin by segment:            
NGL Pipelines & Services $1,022.9  $1,028.1  $3,206.9  $3,038.2 
Crude Oil Pipelines & Services  422.9   481.8   1,242.0   1,569.1 
Natural Gas Pipelines & Services  223.3   208.4   960.5   701.1 
Petrochemical & Refined Products Services  411.3   315.0   1,019.1   785.0 
Total segment gross operating margin $2,080.4  $2,033.3  $6,428.5  $6,093.4 
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


The following table summarizes the non-cash mark-to-market gains (losses) for the periods indicated:

  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2020  2019  2020  2019 
Mark-to-market gains (losses) in gross operating margin:            
NGL Pipelines & Services $(12.0) $(0.7) $11.4  $(0.1)
Crude Oil Pipelines & Services  10.1   9.8   28.9   95.0 
Natural Gas Pipelines & Services  (14.8)  1.3   10.0   1.3 
Petrochemical & Refined Products Services  (21.0)  (1.3)  3.4   (3.3)
       Total mark-to-market impact on gross operating margin  (37.7)  9.1   53.7   92.9 
Mark-to-market loss in interest expense  0   (94.9)  0   (94.9)
       Total $(37.7) $(85.8) $53.7  $(2.0)

For information regarding our hedging activities, see Note 14.

Summarized Segment Financial Information

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

 Reportable Business Segments        Reportable Business Segments       
 
NGL
Pipelines
& Services
  
Crude Oil
Pipelines
& Services
  
Natural Gas
Pipelines
& Services
  
Petrochemical
& Refined Products Services
  
Adjustments
and
Eliminations
  
Consolidated
Total
  
NGL
Pipelines
& Services
  
Crude Oil
Pipelines
& Services
  
Natural Gas
Pipelines
& Services
  
Petrochemical
& Refined
Products
Services
  
Adjustments
and
Eliminations
  
Consolidated
Total
 
Revenues from third parties:                                    
Three months ended September 30, 2021 $3,814.5  $3,210.0  $975.7  $2,800.2  $0  $10,800.4 
Three months ended September 30, 2020 $2,612.4  $1,518.0  $604.6  $2,179.5  $0  $6,914.5   2,612.4   1,518.0   604.6   2,179.5   0   6,914.5 
Three months ended September 30, 2019  3,250.1   2,467.9   712.3   1,518.2   0   7,948.5 
Nine months ended September 30, 2021  10,979.6   7,867.3   3,265.2   7,270.1   0   29,382.2 
Nine months ended September 30, 2020  8,053.4   5,007.0   1,855.2   5,210.7   0   20,126.3   8,053.4   5,007.0   1,855.2   5,210.7   0   20,126.3 
Nine months ended September 30, 2019  9,843.9   7,916.5   2,451.6   4,518.2   0   24,730.2 
Revenues from related parties:                                                
Three months ended September 30, 2021  2.1   24.6   4.2   0   0   30.9 
Three months ended September 30, 2020  1.6   3.6   2.3   0   0   7.5   1.6   3.6   2.3   0   0   7.5 
Three months ended September 30, 2019  2.0   10.4   3.2   0   0   15.6 
Nine months ended September 30, 2021  7.6   36.3   10.6   0   0   54.5 
Nine months ended September 30, 2020  5.0   16.7   7.5   0   0   29.2   5.0   16.7   7.5   0   0   29.2 
Nine months ended September 30, 2019  7.3   35.7   10.7   0   0   53.7 
Intersegment and intrasegment revenues:                                                
Three months ended September 30, 2021  13,753.5   6,611.2   145.9   6,149.9   (26,660.5)  0 
Three months ended September 30, 2020  7,098.2   6,422.5   117.0   1,297.8   (14,935.5)  0   7,098.2   6,422.5   117.0   1,297.8   (14,935.5)  0 
Three months ended September 30, 2019  4,729.3   9,479.7   141.7   558.1   (14,908.8)  0 
Nine months ended September 30, 2021  37,140.3   21,907.8   441.0   18,979.7   (78,468.8)  0 
Nine months ended September 30, 2020  18,826.6   18,302.7   325.0   2,815.6   (40,269.9)  0   18,826.6   18,302.7   325.0   2,815.6   (40,269.9)  0 
Nine months ended September 30, 2019  14,715.5   26,818.0   500.2   1,890.4   (43,924.1)  0 
Total revenues:                                                
Three months ended September 30, 2021  17,570.1   9,845.8   1,125.8   8,950.1   (26,660.5)  10,831.3 
Three months ended September 30, 2020  9,712.2   7,944.1   723.9   3,477.3   (14,935.5)  6,922.0   9,712.2   7,944.1   723.9   3,477.3   (14,935.5)  6,922.0 
Three months ended September 30, 2019  7,981.4   11,958.0   857.2   2,076.3   (14,908.8)  7,964.1 
Nine months ended September 30, 2021  48,127.5   29,811.4   3,716.8   26,249.8   (78,468.8)  29,436.7 
Nine months ended September 30, 2020  26,885.0   23,326.4   2,187.7   8,026.3   (40,269.9)  20,155.5   26,885.0   23,326.4   2,187.7   8,026.3   (40,269.9)  20,155.5 
Nine months ended September 30, 2019  24,566.7   34,770.2   2,962.5   6,408.6   (43,924.1)  24,783.9 
Equity in income (loss) of unconsolidated affiliates:                                                
Three months ended September 30, 2021  30.5   105.2   1.4   0.5   0   137.6 
Three months ended September 30, 2020  29.3   51.8   1.4   (0.5)  0   82.0   29.3   51.8   1.4   (0.5)  0   82.0 
Three months ended September 30, 2019  25.9   113.2   1.6   (1.4)  0   139.3 
Nine months ended September 30, 2021  87.5   354.2   4.3   1.2   0   447.2 
Nine months ended September 30, 2020  90.8   243.2   4.3   (2.2)  0   336.1   90.8   243.2   4.3   (2.2)  0   336.1 
Nine months ended September 30, 2019  82.7   348.8   4.9   (5.1)  0   431.3 

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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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


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

  Reportable Business Segments       
  
NGL
Pipelines
& Services
  
Crude Oil
Pipelines
& Services
  
Natural Gas
Pipelines
& Services
  
Petrochemical
& Refined
Products
Services
  
Adjustments
and
Eliminations
  
Consolidated
Total
 
Property, plant and equipment, net:
(see Note 4)
                  
At September 30, 2020 $17,309.6  $6,503.6  $8,383.0  $7,695.0  $2,468.9  $42,360.1 
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 September 30, 2020  676.4   1,774.8   29.9   4.3   0   2,485.4 
At December 31, 2019  703.8   1,866.5   27.3   2.6   0   2,600.2 
Intangible assets, net: (see Note 6)
                        
At September 30, 2020  341.2   1,952.4   915.1   139.9   0   3,348.6 
At December 31, 2019  360.2   2,001.9   941.2   145.7   0   3,449.0 
Goodwill: (see Note 6)
                        
At September 30, 2020  2,651.7   1,841.0   296.3   956.2   0   5,745.2 
At December 31, 2019  2,651.7   1,841.0   296.3   956.2   0   5,745.2 
Segment assets:                        
At September 30, 2020  20,978.9   12,071.8   9,624.3   8,795.4   2,468.9   53,939.3 
At December 31, 2019  20,367.8   12,033.8   9,697.3   8,657.7   2,641.2   53,397.8 
  Reportable Business Segments       
  
NGL
Pipelines
& Services
  
Crude Oil
Pipelines
& Services
  
Natural Gas
Pipelines
& Services
  
Petrochemical
& Refined
Products
Services
  
Adjustments
and
Eliminations
  
Consolidated
Total
 
Property, plant and equipment, net:
(see Note 4)
                  
At September 30, 2021 $17,330.0  $6,927.3  $8,280.3  $7,533.6  $2,182.6  $42,253.8 
At December 31, 2020  17,128.3   6,982.6   8,465.8   7,528.4   1,807.7   41,912.8 
Investments in unconsolidated affiliates:
(see Note 5)
                        
At September 30, 2021  656.4   1,742.1   32.1   2.8   0   2,433.4 
At December 31, 2020  671.6   1,723.7   31.4   2.5   0   2,429.2 
Intangible assets, net: (see Note 6)
                        
At September 30, 2021  323.2   1,879.4   859.1   128.3   0   3,190.0 
At December 31, 2020  334.1   1,936.6   905.0   133.4   0   3,309.1 
Goodwill: (see Note 6)
                        
At September 30, 2021  2,651.7   1,841.0   0   956.2   0   5,448.9 
At December 31, 2020  2,651.7   1,841.0   0   956.2   0   5,448.9 
Segment assets:                        
At September 30, 2021  20,961.3   12,389.8   9,171.5   8,620.9   2,182.6   53,326.1 
At December 31, 2020  20,785.7   12,483.9   9,402.2   8,620.5   1,807.7   53,100.0 
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Supplemental Revenue and Expense Information

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

 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
 2020  2019  2020  2019  2021  2020  2021  2020 
Consolidated revenues:                        
NGL Pipelines & Services $2,614.0  $3,252.1  $8,058.4  $9,851.2  $3,816.6  $2,614.0  $10,987.2  $8,058.4 
Crude Oil Pipelines & Services  1,521.6   2,478.3   5,023.7   7,952.2   3,234.6   1,521.6   7,903.6   5,023.7 
Natural Gas Pipelines & Services  606.9   715.5   1,862.7   2,462.3   979.9   606.9   3,275.8   1,862.7 
Petrochemical & Refined Products Services  2,179.5   1,518.2   5,210.7   4,518.2   2,800.2   2,179.5   7,270.1   5,210.7 
Total consolidated revenues $6,922.0  $7,964.1  $20,155.5  $24,783.9  $10,831.3  $6,922.0  $29,436.7  $20,155.5 
                                
Consolidated costs and expenses                                
Operating costs and expenses:                                
Cost of sales $4,313.7  $5,276.5  $12,331.9  $16,721.5  $8,112.8  $4,313.7  $21,215.8  $12,331.9 
Other operating costs and expenses (1)  696.9   790.8   2,120.4   2,243.4   757.3   696.9   2,174.2   2,120.4 
Depreciation, amortization and accretion  484.2   467.1   1,461.3   1,380.8   511.3   484.2   1,516.9   1,461.3 
Asset impairment and related charges  77.0   39.4   90.4   51.2 
Net gains attributable to asset sales
  (0.6)  (0.1)  (2.1)  (2.6)
Asset impairment charges  29.3   77.0   112.7   90.4 
Net losses (gains) attributable to asset sales and related matters
  (2.2)  (0.6)  9.0   (2.1)
General and administrative costs  50.3   55.5   162.8   160.2   47.3   50.3   155.1   162.8 
Total consolidated costs and expenses $5,621.5  $6,629.2  $16,164.7  $20,554.5  $9,455.8  $5,621.5  $25,183.7  $16,164.7 

(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.sales and related matters.

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


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Note 11.  Income Taxes

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

  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2020  2019  2020  2019 
Deferred tax benefit (expense) attributable to OTA $21.3     $158.0    
Texas Margin Tax  (7.2) $(15.5)  (21.9) $(36.5)
Other  5.0   0.1   2.5   (0.9)
Benefit from (provision for) income taxes $19.1  $(15.4) $138.6  $(37.4)

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 nine months ended September 30, 2020 and 2019.

OTA Deferred Tax Liability

On March 5, 2020, the Partnership settled its obligations under the Liquidity Option Agreement (see Note 8) and indirectly assumed OTA’s deferred tax liability, which reflects OTA’s outside basis difference in the limited partner interests it received from the Partnership in October 2014.  Upon settlement of the Liquidity Option, the Liquidity Option liability was effectively replaced by the deferred tax liability of OTA calculated in accordance with ASC 740, Income Taxes.

At March 5, 2020, the Liquidity Option liability amount was $511.9 million.  Since the book value of the Liquidity Option liability exceeded OTA’s estimated deferred tax liability of $439.7 million on that date, we recognized a non-cash benefit in earnings of $72.2 million, which is reflected in the “Benefit from (provision for) income tax” line on our Unaudited Condensed Statement of Consolidated Operations for the nine months ended September 30, 2020.  Subsequent to March 5, 2020 and through September 30, 2020, OTA recognized an additional net, non-cash deferred income tax benefit of $85.8 million due to a decrease in the outside basis difference of its investment in the Partnership, which in turn was driven by a decline in the market price of Partnership common units since March 5, 2020.  In total, earnings for the three and nine months ended September 30, 2020 reflect $21.3 million and $158.0 million, respectively, of net deferred income tax benefit attributable to OTA.

On September 30, 2020, OTA exchanged the Partnership common units it owned for non-publicly traded preferred units having a stated value of $1,000 per unit (see Note 8).  As a result and beginning September 30, 2020, OTA’s deferred tax liability no longer fluctuates due to market price changes in the Partnership’s common units. Our subsidiary OTA is a corporation for U.S. federal income tax purposes, and the exchange of common units for preferred units did not constitute a taxable transaction for OTA.



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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Tabular Disclosures Regarding Income Taxes

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

  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2020  2019  2020  2019 
Current portion of income tax benefit (provision):            
Federal $5.3  $0.4  $3.0  $(0.1)
State  (4.7)  (9.1)  (13.4)  (25.6)
Foreign  0.2   0   0   (0.8)
Total current portion  0.8   (8.7)  (10.4)  (26.5)
Deferred portion of income tax benefit (provision):                
    Federal  18.7   (0.3)  145.1   (0.2)
    State  (0.4)  (6.4)  3.9   (10.9)
Foreign  0   0   0   0.2 
Total deferred portion  18.3   (6.7)  149.0   (10.9)
Total benefit from (provision for) income taxes $19.1  $(15.4) $138.6  $(37.4)

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

  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2020  2019  2020  2019 
Pre-Tax Net Book Income (“NBI”) $1,064.9  $1,060.2  $3,381.2  $3,599.1 
                 
Texas Margin Tax (1)  (7.2)  (15.5)  (21.9)  (36.5)
State income tax benefit (provision), net of federal benefit (2)  1.6   0   9.7   (0.3)
Federal income tax benefit (provision) computed by applying
     the federal statutory rate to NBI of corporate entities
  25.1   0.1   83.4   (0.6)
Federal benefit attributable to settlement of
Liquidity Option (2)
  0   0   67.8   0 
Other differences  (0.4)  0   (0.4)  0 
Benefit from (provision for) income taxes $19.1  $(15.4) $138.6  $(37.4)
                 
Effective income tax rate  1.8%  (1.5)%  4.1%  (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:

  September 30,  December 31, 
  2020  2019 
Deferred tax liabilities:      
Attributable to investment in OTA $353.9    
Attributable to property, plant and equipment  107.9  $100.2 
Attributable to investments in other entities  4.2   3.3 
     Total deferred tax liabilities  466.0   103.5 
Less deferred tax assets:        
Net operating loss carryovers (1)  0.1   0.1 
Temporary differences related to Texas Margin Tax  2.6   3.0 
Total deferred tax assets  2.7   3.1 
Total net deferred tax liabilities $463.3  $100.4 

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


Note 12.11.  Earnings Per Unit

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

 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
 2020  2019  2020  2019  2021  2020  2021  2020 
BASIC EARNINGS PER COMMON UNIT                        
Net income attributable to common unitholders $1,052.6  $1,019.2  $3,437.4  $3,494.4  $1,153.0  $1,052.6  $3,605.7  $3,437.4 
Earnings allocated to phantom unit awards (1)  (7.5)  (6.1)  (24.9)  (21.3)  (9.1)  (7.5)  (29.0)  (24.9)
Net income allocated to common unitholders $1,045.1  $1,013.1  $3,412.5  $3,473.1  $1,143.9  $1,045.1  $3,576.7  $3,412.5 
                                
Basic weighted-average number of common units outstanding  2,185.5   2,189.1   2,186.7   2,188.4   2,184.0   2,185.5   2,184.2   2,186.7 
                                
Basic earnings per common unit $0.48  $0.46  $1.56  $1.59  $0.52  $0.48  $1.64  $1.56 
                                
DILUTED EARNINGS PER COMMON UNIT                                
Net income attributable to common unitholders $1,052.6  $1,019.2  $3,437.4  $3,494.4  $1,153.0  $1,052.6  $3,605.7  $3,437.4 
Net income attributable to preferred units  0.8   0*  2.7   0*
Net income attributable to limited partners $1,153.8  $1,052.6  $3,608.4  $3,437.4 
                                
Diluted weighted-average number of units outstanding:                                
Common units  2,185.5   2,189.1   2,186.7   2,188.4 
Distribution-bearing common units  2,184.0   2,185.5   2,184.2   2,186.7 
Phantom units (2)  15.9   13.2   15.7   13.1   17.5   15.9   17.6   15.7 
Preferred units (2)  0*  0   0*  0   2.5   0*  2.5   0*
Total  2,201.4   2,202.3   2,202.4   2,201.5   2,204.0   2,201.4   2,204.3   2,202.4 
                                
Diluted earnings per common unit $0.48  $0.46  $1.56  $1.59  $0.52  $0.48  $1.64  $1.56 
                
* Amount is negligible                

* Amount is negligible

(1)Phantom units are considered participating securities for purposes of computing basic earnings per unit. See Note 1312 for information regarding the phantom units.
(2)We use the “if-converted method” to determine the potential dilutive effect of the vesting of phantom unitsunit awards and the conversion of preferred units outstanding.  See Note 12 for information regarding phantom unit awards.  See Note 8 for information regarding the preferred units issued on September 30, 2020.  Since the preferred units were issued on the last day of the third quarter of 2020, their weighted-average dilutive impact on earnings per unit for the three and nine months ended September 30, 2020 was negligible.units. 


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Note 13.12.  Equity-Based Awards

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

 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
 2020  2019  2020  2019  2021  2020  2021  2020 
Equity-classified awards:                        
Phantom unit awards $37.3  $34.7  $113.1  $99.6  $35.0  $37.3  $111.0  $113.1 
Profits interest awards  2.2   2.5   7.2   8.1   0.6   2.2   4.7   7.2 
Liability-classified awards  0   0.1   0   0.1   0   0   0.1   0 
Total $39.5  $37.3  $120.3  $107.8  $35.6  $39.5  $115.8  $120.3 

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

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

 
Number of
Units
  
Weighted-
Average Grant
Date Fair Value
per Unit (1)
  
Number of
Units
  
Weighted-
Average Grant
Date Fair Value
per Unit (1)
 
Phantom unit awards at December 31, 2019  12,974,684  $27.21 
Phantom unit awards at December 31, 2020
  15,669,442  $26.76 
Granted (2)  7,403,345  $25.71   7,720,645  $21.30 
Vested  (4,447,460) $26.35   (5,574,695) $27.01 
Forfeited  (130,774) $26.74   (514,907) $24.48 
Phantom unit awards at September 30, 2020  15,799,795  $26.75 
Phantom unit awards at September 30, 2021
  17,300,485  $24.31 

(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 20202021 was $190.4$164.4 million based on a grant date market price of EPDthe Partnership’s common units ranging from $17.24$20.79 to $25.76$22.05 per unit.  An estimated annual forfeiture rate of 2.4%2.0% was applied to these awards.

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

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

 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
 2020  2019  2020  2019  2021  2020  2021  2020 
Cash payments made in connection with DERs $7.1  $5.9  $20.0  $16.4  $7.9  $7.1  $23.1  $20.0 
Total intrinsic value of phantom unit awards that vested during period  2.0   7.2   113.4   108.9   3.5   2.0   122.6   113.4 

For the EPCO group of companies, the unrecognized compensation cost associated with phantom unit awards was $196.6$185.1  million at September 30, 2020,2021, of which our share of such cost is currently estimated to be $165.5$153.0 million.  Due to the graded vesting provisions of these awards, we expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 2.1 2.0 years.

Profits Interest Awards

In 2016 and 2018, EPCO Holdings Inc., a privately held affiliate of EPCO, contributed a portion of the Partnership common units it owned to form 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 the form of a Class B limited partner interest) in an Employee Partnership.

The Class B limited partner interests of two of the four Employee Partnerships outstanding at January 1, 2021, EPD PubCo Unit II L.P. and EPD PrivCo Unit I L.P., vested on June 11, 2021 when the closing market price of the Partnership’s common units exceeded $25.41 per unit.  As a result of these vesting events, we recognized an aggregate $1.9 million of non-cash, compensation expense in the three months ended June 30, 2021.

The Class B limited partner interests of EPD Unit IV L.P. and EPCO Unit II L.P. remain outstanding. At September 30, 2021, our share of the total unrecognized compensation cost related to these two Employee Partnerships was $10.4 million, which we expect to recognize over a weighted-average period of 2.2years.



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Profits Interest Awards

EPCO currently serves as the general partner for each of four limited partnerships (referred to as the “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.

On September 30, 2020, the partners of two such Employee Partnerships, namely EPD PubCo Unit II L.P. (“PubCo II”) and EPD PrivCo Unit I L.P. (“PrivCo I”), amended their respective limited partnership agreements to provide for the vesting of their Class B limited partner interests on the earlier of (i) February 22, 2023, (ii) the first date on or after September 30, 2020 on which the closing market price of the Partnership’s common units is equal to or greater than $25.41 per unit, (iii) a change of control event, or (iv) dissolution of the applicable Employee Partnership.  As a result of these modifications, PubCo II and PrivCo I will recognize incremental compensation cost of $1.2 million and $0.5 million, respectively, through February 22, 2023.

The profits interest in EPD PubCo Unit I L.P. vested in February 2020 and was liquidated.  At September 30, 2020, our share of the total unrecognized compensation cost related to the four remaining Employee Partnerships was $18.0 million, which we expect to recognize over a weighted-average period of 3.1 years.


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

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

Interest Rate Hedging Activities

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

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

Hedged Transaction
Number and Type
of Derivatives
Outstanding
Notional
Amount
Expected
Settlement
Date
Weighted-Average
Fixed Rate
Locked
Accounting
Treatment
Future long-term debt offering1 forward-starting swap$75.04/20212.41%Cash flow hedge
Future long-term debt offering5 forward-starting swaps$500.04/20212.13%Cash flow hedge
Future long-term debt offering2 forward-starting swaps (1)$150.02/20221.72%Cash flow hedge
Future long-term debt offering1 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 during the first quarter of 2020.

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

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

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

As a result of these terminations, we do not have any interest rate derivative instruments outstanding at September 30, 2021.
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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, 2020,2021, our predominant commodity hedging strategies consisted of (i) hedging anticipated future purchases and sales of commodity products associated with transportation, storage and blending activities, (ii) hedging natural gas processing margins and (iii) hedging the fair value of commodity products held in inventory and (iii) hedging natural gas processing margins.inventory.  

The following table summarizes our portfolio of commodity derivative instruments outstanding at September 30, 20202021 (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”))7.4n/aCash flow hedge18.82.6Cash flow hedge
Forecasted sales of NGLs (million barrels (“MMBbls”)) (3)1.1n/aCash flow hedge
Forecasted sales of NGLs (MMBbls)0.60.1Cash flow hedge
Octane enhancement:      
Forecasted purchase of NGLs (MMBbls)0.3n/aCash flow hedge
Forecasted sales of octane enhancement products (MMBbls)1.2n/aCash flow hedge23.02.8Cash flow hedge
Natural gas marketing:      
Natural gas storage inventory management activities (Bcf)5.2n/aFair value hedge2.4n/aFair value hedge
NGL marketing:      
Forecasted purchases of NGLs and related hydrocarbon products (MMBbls)143.35.6Cash flow hedge126.54.7Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products (MMBbls)179.716.6Cash flow hedge142.42.7Cash flow hedge
NGLs inventory management activities (MMBbls)0.80.7Fair value hedge1.8n/aFair value hedge
Refined products marketing:      
Forecasted purchases of refined products (MMBbls)46.88.1Cash flow hedge10.5n/aCash flow hedge
Forecasted sales of refined products (MMBbls)54.011.5Cash flow hedge10.7n/aCash flow hedge
Refined products inventory management activities (MMBbls)0.1n/aFair value hedge
Crude oil marketing:      
Forecasted purchases of crude oil (MMBbls)51.0n/aCash flow hedge4.1n/aCash flow hedge
Forecasted sales of crude oil (MMBbls)65.2n/aCash flow hedge5.90.1Cash flow hedge
Petrochemical marketing:      
Forecasted purchases of petrochemical products (MMBbls)0.5n/aCash flow hedge
Forecasted sales of petrochemical products (MMBbls)0.3n/aCash flow hedge0.9n/aCash flow hedge
Commercial energy:   
Forecasted purchases of power related to asset operations (terawatt hours (“TWh”))0.70.2Cash flow hedge
Derivatives not designated as hedging instruments:      
Natural gas risk management activities (Bcf) (4)37.90.7Mark-to-market
NGL risk management activities (MMBbls) (4)26.410.8Mark-to-market
Refined products risk management activities (MMBbls) (4)4.0n/aMark-to-market
Crude oil risk management activities (MMBbls) (4)19.55.9Mark-to-market
Natural gas risk management activities (Bcf) (3)5.30.2Mark-to-market
NGL risk management activities (MMBbls) (3)42.314.3Mark-to-market
Refined products risk management activities (MMBbls) (3)8.1n/aMark-to-market
Crude oil risk management activities (MMBbls) (3)28.62.4Mark-to-market

(1)Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes.
(2)The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is December 2023, January 2022 December 2021 and December 2022,2023, respectively.
(3)Forecasted NGL sales volumes under natural gas processing exclude 0.3 MMBbls of additional hedges executed under contracts that have been designated as normal sales agreements.
(4)Reflects the use of derivative instruments to manage risks associated with our transportation, processing and storage assets.

The carrying amount of our inventories subject to fair value hedges was $72.4$151.5 million and $31.7$144.0 million at September 30, 20202021 and December 31, 2019,2020, respectively.
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


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

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

Asset Derivatives Liability DerivativesAsset Derivatives Liability Derivatives
September 30, 2020 December 31, 2019 September 30, 2020 December 31, 2019September 30, 2021 December 31, 2020 September 30, 2021 December 31, 2020
Balance
Sheet
Location
Fair
Value
 
Balance
Sheet
Location
Fair
Value
 
Balance
Sheet
Location
Fair
Value
 
Balance
Sheet
Location
Fair
Value
Balance
Sheet
Location
Fair
Value
 
Balance
Sheet
Location
Fair
Value
 
Balance
Sheet
Location
Fair
Value
 
Balance
Sheet
Location
Fair
Value
Derivatives designated as hedging instruments                              
Interest rate derivativesCurrent assets$0 Current assets$0 
Current
liabilities
$160.7 
Current
liabilities
$6.7Current assets$0 Current assets$0 
Current
liabilities
$0 
Current
liabilities
$109.1
Interest rate derivativesOther assets 5.7 Other assets 0 Other liabilities 32.9 Other liabilities 6.8Other assets 0 Other assets 12.4 Other liabilities 0 Other liabilities 11.0
Total interest rate derivatives  5.7   0   193.6   13.5  0   12.4   0   120.1
Commodity derivativesCurrent assets 109.3 Current assets 116.5 
Current
liabilities
 159.4 
Current
liabilities
 107.1Current assets 637.4 Current assets 210.5 
Current
liabilities
 706.0 
Current
liabilities
 234.0
Commodity derivativesOther assets 4.3 Other assets 0 Other liabilities 20.2 Other liabilities 0Other assets 8.4 Other assets 0.4 Other liabilities 12.3 Other liabilities 6.1
Total commodity derivatives  113.6   116.5   179.6   107.1  645.8   210.9   718.3   240.1
Total derivatives designated as hedging instruments $119.3  $116.5  $373.2  $120.6 $645.8  $223.3  $718.3  $360.2
                              
Derivatives not designated as hedging instruments                              
Commodity derivativesCurrent assets$23.6 Current assets$10.7 
Current
liabilities
$9.6 
Current
liabilities
$8.6Current assets$57.5 Current assets$18.1 
Current
liabilities
$64.1 
Current
liabilities
$6.1
Commodity derivativesOther assets 2.2 Other assets 0.6 Other liabilities 1.0 Other liabilities 0.5Other assets 8.4 Other assets 0.2 Other liabilities 7.5 Other liabilities 0.1
Total commodity derivatives  25.8   11.3   10.6   9.1  65.9   18.3   71.6   6.2
Total derivatives not designated as hedging instruments $25.8  $11.3  $10.6  $9.1 $65.9  $18.3  $71.6  $6.2

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

Offsetting of Financial Assets and Derivative Assets Offsetting of Financial Assets and Derivative Assets 
Gross
Amounts of
Recognized
Assets
 
Gross
Amounts
Offset in the
Balance Sheet
 
Amounts
of Assets
Presented
in the
Balance Sheet
 
Gross Amounts Not Offset
in the Balance Sheet
 
Amounts That
Would Have
Been Presented
On Net Basis
 
Gross
Amounts of
Recognized
Assets
 
Gross
Amounts
Offset in the
Balance Sheet
 
Amounts
of Assets
Presented
in the
Balance Sheet
 
Gross Amounts Not Offset
in the Balance Sheet
 
Amounts That
Would Have
Been Presented
On Net Basis
 
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, 2020:                     
As of September 30, 2021:                     
Commodity derivatives $711.7  $0  $711.7  $(711.2) $0  $0  $0.5 
As of December 31, 2020:                            
Interest rate derivatives $5.7  $0  $5.7  $0  $0  $0  $5.7  $12.4  $0  $12.4  $0  $0  $0  $12.4 
Commodity derivatives $139.4  $0  $139.4  $(139.4) $0  $50.4  $50.4   229.2   0   229.2   (228.5)  0   0   0.7 
As of December 31, 2019:                            
Commodity derivatives $127.8  $0  $127.8  $(115.3) $0  $(11.0) $1.5 


Offsetting of Financial Liabilities and Derivative Liabilities Offsetting of Financial Liabilities and Derivative Liabilities 
Gross
Amounts of
Recognized
Liabilities
 
Gross
Amounts
Offset in the
Balance Sheet
 
Amounts
of Liabilities
Presented
in the
Balance Sheet
 
Gross Amounts Not Offset
in the Balance Sheet
 
Amounts That
Would Have
Been Presented
On Net Basis
 
Gross
Amounts of
Recognized
Liabilities
 
Gross
Amounts
Offset in the
Balance Sheet
 
Amounts
of Liabilities
Presented
in the
Balance Sheet
 
Gross Amounts Not Offset
in the Balance Sheet
 
Amounts That
Would Have
Been Presented
On Net Basis
 
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, 2020:                     
As of September 30, 2021:                     
Commodity derivatives $789.9  $0  $789.9  $(711.2) $0  $(77.7) $1.0 
As of December 31, 2020:                            
Interest rate derivatives $193.6  $0  $193.6  $0  $0  $0  $193.6  $120.1  $0  $120.1  $0  $0  $0  $120.1 
Commodity derivatives  190.2   0   190.2   (139.4)  0   0   50.8   246.3   0   246.3   (228.5)  0   (17.3)  0.5 
As of December 31, 2019:                            
Interest rate derivatives $13.5  $0  $13.5  $0  $0  $0  $13.5 
Commodity derivatives  116.2   0   116.2   (115.3)  0   0   0.9 
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


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

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

Derivatives in Fair Value
Hedging Relationships
 
Location
 
Gain (Loss) Recognized in
Income on Derivative
 
 
Location
 
Gain (Loss) Recognized in
Income on Derivative
 
   
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
    
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2020  2019  2020  2019   2021  2020  2021  2020 
Commodity derivativesRevenue $(19.8) $(0.4) $(69.1) $(2.0)Revenue $(49.5) $(19.8) $(236.6) $(69.1)
Total  $(19.8) $(0.4) $(69.1) $(2.0)  $(49.5) $(19.8) $(236.6) $(69.1)

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 September 30,
  
For the Nine Months
Ended September 30,
 
  2020  2019  2020  2019   2021  2020  2021  2020 
Commodity derivativesRevenue $22.4  $2.4   142.6  $8.7 Revenue $21.5  $22.4  $230.0  $142.6 
Total  $22.4  $2.4  $142.6  $8.7   $21.5  $22.4  $230.0  $142.6 

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

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

Derivatives in Cash Flow
Hedging Relationships
 
Change in Value Recognized in
Other Comprehensive Income (Loss) on Derivative
  
Change in Value Recognized in
Other Comprehensive Income (Loss) on Derivative
 
 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
 2020  2019  2020  2019  2021  2020  2021  2020 
Interest rate derivatives $62.6  $(18.6) $(207.7) $(23.8) $0  $62.6  $182.9  $(207.7)
Commodity derivatives – Revenue (1)  2.6   73.5   404.5   71.1   (110.8)  2.6   (843.5)  404.5 
Commodity derivatives – Operating costs and expenses (1)  (6.8)  (1.2)  (11.8)  (12.5)  10.2   (6.8)  (8.7)  (11.8)
Total $58.4  $53.7  $185.0  $34.8  $(100.6) $58.4  $(669.3) $185.0 

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

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 September 30,
  
For the Nine Months
Ended September 30,
 
  2020  2019  2020  2019   2021  2020  2021  2020 
Interest rate derivativesInterest expense $(9.9) $(9.4) $(29.2) $(27.8)Interest expense $(10.3) $(9.9) $(29.1) $(29.2)
Commodity derivativesRevenue  (19.5)  93.6   344.7   161.4 Revenue  (116.8)  (19.5)  (614.9)  344.7 
Commodity derivativesOperating costs and expenses  (10.0)  (2.1)  (9.9)  (9.4)Operating costs and expenses  (0.3)  (10.0)  (18.9)  (9.9)
Total  $(39.4) $82.1  $305.6  $124.2   $(127.4) $(39.4) $(662.9) $305.6 

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Over the next twelve months, we expect to reclassify $40.8$28.2 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 $174.3$283.6 million of gainslosses attributable to commodity derivative instruments from accumulated other comprehensive incomeloss to earnings, $175.5with $294.3 million as an increasea decrease in revenue and $1.2$10.7 million as an increasea decrease in operating costs and expenses.

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

Derivatives Not Designated
as Hedging Instruments
Location 
Gain (Loss) Recognized in
Income on Derivative
 Location 
Gain (Loss) Recognized in
Income on Derivative
 
   
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
    
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2020  2019  2020  2019   2021  2020  2021  2020 
Interest rate derivativesInterest expense $0  $(94.9) $0  $(94.9)
Commodity derivativesRevenue  14.7   21.8   113.4   96.7 Revenue $107.2  $14.7  $143.6  $113.4 
Commodity derivativesOperating costs and expenses  0.1   (1.6)  0.9   (6.3)Operating costs and expenses  1.5   0.1   1.5   0.9 
Total  $14.8  $(74.7) $114.3  $(4.5)  $108.7  $14.8  $145.1  $114.3 

The $114.3$145.1 million gain recognized for the nine months ended September 30, 20202021 (as noted in the preceding table) from derivatives not designated as hedging instruments consists of $59.6$7.3 million of realized gains and $54.7$137.8 million of net unrealized mark-to-market gains attributable to commodity derivatives.

Fair Value Measurements

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

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


  
At September 30, 2021
Fair Value Measurements Using
    
  
Quoted Prices
in Active
Markets for
Identical Assets
and Liabilities
(Level 1)
  
Significant
Other
Observable
Inputs
(Level 2)
  
Significant
Unobservable
Inputs
(Level 3)
  Total 
Financial assets:            
Commodity derivatives:            
Value before application of CME Rule 814 $435.3  $2,344.1  $0.1  $2,779.5 
Impact of CME Rule 814  (435.3)  (1,632.5)  0   (2,067.8)
Total commodity derivatives  0   711.6   0.1   711.7 
Total $0  $711.6  $0.1  $711.7 
                 
Financial liabilities:                
Commodity derivatives:                
Value before application of CME Rule 814 $655.1  $2,594.5  $0.2  $3,249.8 
Impact of CME Rule 814  (655.1)  (1,804.8)  0   (2,459.9)
Total commodity derivatives  0   789.7   0.2   789.9 
Total $0  $789.7  $0.2  $789.9 

  
At September 30, 2020
Fair Value Measurements Using
    
  
Quoted Prices
in Active
Markets for
Identical Assets
and Liabilities
(Level 1)
  
Significant
Other
Observable
Inputs
(Level 2)
  
Significant
Unobservable
Inputs
(Level 3)
  Total 
Financial assets:            
Interest rate derivatives $0  $5.7  $0  $5.7 
Commodity derivatives:                
Value before application of CME Rule 814  442.4   454.1   52.7   949.2 
Impact of CME Rule 814  (417.8)  (352.3)  (39.7)  (809.8)
Total commodity derivatives  24.6   101.8   13.0   139.4 
Total $24.6  $107.5  $13.0  $145.1 
                 
Financial liabilities:                
Interest rate derivatives $0  $193.6  $0  $193.6 
Commodity derivatives:                
Value before application of CME Rule 814  637.9   567.9   100.2   1,306.0 
Impact of CME Rule 814  (613.6)  (433.5)  (68.7)  (1,115.8)
Total commodity derivatives  24.3   134.4   31.5   190.2 
Total $24.3  $328.0  $31.5  $383.8 

 
At December 31, 2019
Fair Value Measurements Using
     
At December 31, 2020
Fair Value Measurements Using
    
 
Quoted Prices
in Active
Markets for
Identical Assets
and Liabilities
(Level 1)
  
Significant
Other
Observable
Inputs
(Level 2)
  
Significant
Unobservable
Inputs
(Level 3)
  Total  
Quoted Prices
in Active
Markets for
Identical Assets
and Liabilities
(Level 1)
  
Significant
Other
Observable
Inputs
(Level 2)
  
Significant
Unobservable
Inputs
(Level 3)
  Total 
Financial assets:                        
Interest rate derivatives $0  $12.4  $0  $12.4 
Commodity derivatives:                            
Value before application of CME Rule 814 $53.4  $343.7  $0.1  $397.2   678.6   878.6   12.9   1,570.1 
Impact of CME Rule 814  (47.0)  (222.4)  0   (269.4)  (678.6)  (650.4)  (11.9)  (1,340.9)
Total commodity derivatives  6.4   121.3   0.1   127.8   0   228.2   1.0   229.2 
Total $6.4  $121.3  $0.1  $127.8  $0  $240.6  $1.0  $241.6 
                                
Financial liabilities:                                
Liquidity Option (see Note 8) $0  $0  $509.6  $509.6 
Interest rate derivatives  0   13.5   0   13.5  $0  $120.1  $0  $120.1 
Commodity derivatives:                                
Value before application of CME Rule 814  88.1   273.6   0.3   362.0   1,065.6   1,047.4   25.9   2,138.9 
Impact of CME Rule 814  (81.9)  (163.9)  0   (245.8)  (1,065.6)  (807.3)  (19.7)  (1,892.6)
Total commodity derivatives  6.2   109.7   0.3   116.2   0   240.1   6.2   246.3 
Total $6.2  $123.2  $509.9  $639.3  $0  $360.2  $6.2  $366.4 

In the aggregate, the fair value of our commodity hedging portfolios at September 30, 20202021 was a net derivative liability of $356.8470.3 million prior to the impact of CME Rule 814.

Financial assets and liabilities recorded on the balance sheet at September 30, 20202021 using significant unobservable inputs (Level 3) are not material to the Unaudited Condensed Consolidated Financial Statements. Refer to

Nonrecurring Fair Value Measurements

We did not have any significant nonrecurring fair value measurements during the nine months ended September 30, 2021 or 2020.

See Note 84 for discussion of the settlement of the Liquidity Option in March 2020 and Note 11 for the income tax impact related to this transaction.information regarding other non-cash asset impairment charges.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Nonrecurring Fair Value Measurements

We did not have any significant nonrecurring fair value measurements at September 30, 2020 or 2019.

See Note 4 for information regarding other non-cash asset impairment charges.

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 $32.80$33.9 billion and $30.37$35.0 billion at September 30, 20202021 and December 31, 2019,2020, respectively.  The aggregate carrying value of these debt obligations was $29.90$29.58 billion and $27.15$29.9 billion at September 30, 20202021 and December 31, 2019,2020, respectively.  These values are primarily based on quoted market prices for such debt or debt of similar terms and maturities (Level 2) and our credit standing.  Changes in market rates of interest affect the fair value of our fixed-rate debt.  The carrying values of our variable-rate long-term debt obligations approximate their fair values since the associated interest rates are market-based.  We do not have any long-term investments in debt or equity securities recorded at fair value.


Note 15.14.  Related Party Transactions

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

 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
 2020  2019  2020  2019  2021  2020  2021  2020 
Revenues – related parties:                        
Unconsolidated affiliates $7.5  $15.6  $29.2  $53.7  $30.9  $7.5  $54.5  $29.2 
Costs and expenses – related parties:                                
EPCO and its privately held affiliates $283.9  $297.8  $847.0  $837.9  $287.1  $283.9  $861.8  $847.0 
Unconsolidated affiliates  33.1   94.7   167.2   313.3   84.2   33.1   201.4   167.2 
Total $317.0  $392.5  $1,014.2  $1,151.2  $371.3  $317.0  $1,063.2  $1,014.2 

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

 
September 30,
2020
  
December 31,
2019
  
September 30,
2021
  
December 31,
2020
 
Accounts receivable - related parties:            
EPCO and its privately held affiliates $2.2  $0  $1.3  $1.9 
Unconsolidated affiliates  1.9   2.5   1.7   3.7 
Total $4.1  $2.5  $3.0  $5.6 
                
Accounts payable - related parties:                
EPCO and its privately held affiliates $113.8  $143.7  $110.1  $139.6 
Unconsolidated affiliates  7.5   18.6   14.6   9.9 
Total $121.3  $162.3  $124.7  $149.5 

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

At September 30, 2020,2021, EPCO and its privately held affiliates (including Dan Duncan LLC and certain Duncan family trusts) beneficially owned the following limited partner interests in us:

 
 
Total Number of Limited Partner Interests Held
Percentage of
Limited Partner
InterestsCommon Units
Outstanding
701,981,017702,152,448 common units32.2%
15,000 preferred units30.0%
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Of the total number of Partnership common units held by EPCO and its privately held affiliates, 97,322,61892,976,464 have been pledged as security under the separate credit facilities of EPCO and its privately held affiliates at September 30, 2020.2021.  These credit facilities contain customary and other events of default, including defaults by us and other affiliates of EPCO.  An event of default, followed by a foreclosure on the pledged collateral, could ultimately result in a change in ownership of these units and affect the market price of EPD’sthe Partnership’s common units.

The Partnership and Enterprise GP are both separate legal entities apart from each other and apart from EPCO and its other affiliates, with assets and liabilities that are also separate from those of EPCO and its other affiliates.  EPCO and its privately held affiliates depend on the cash distributions they receive from us and other investments to fund their other activities and to meet their respective debt obligations.  During the nine months ended September 30, 20202021 and 2019,2020, we paid EPCO and its privately held affiliates cash distributions totaling $908.2$918.1 million and $893.1$908.2 million, respectively.

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

 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
 2020  2019  2020  2019  2021  2020  2021  2020 
Operating costs and expenses $247.8  $259.3  $740.9  $732.0  $253.7  $247.8  $755.5  $740.9 
General and administrative expenses  32.1   34.2   94.6   92.9   33.4   32.1   98.0   94.6 
Total costs and expenses $279.9  $293.5  $835.5  $824.9  $287.1  $279.9  $853.5  $835.5 

We lease office space from privately held affiliates of EPCO at rental rates that approximate market rates. In January 2020, we amended an office space lease with an affiliate of EPCO that extended the term through June 2037.  For the three months ended September 30, 20202021 and 2019,2020, we recognized $3.33.4 million and $3.8$3.3 million, respectively, of related party operating lease expense in connection with these office space leases. For the nine months ended September 30, 20202021 and 2019,2020, we recognized $9.610.1 million and $11.19.6 million, respectively, of related party operating lease expense in connection with these office space leases.


Note 15.  Income Taxes

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

  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2021  2020  2021  2020 
Deferred tax benefit (expense) attributable to
    OTA Holdings, Inc. (“OTA”)
 $(6.8) $21.3  $(20.1) $158.0 
Revised Texas Franchise Tax (“Texas Margin Tax”)  (9.6)  (7.2)  (37.0)  (21.9)
Other  0.3   5.0   (0.2)  2.5 
Benefit from (provision for) income taxes $(16.1) $19.1  $(57.3) $138.6 

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

  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2021  2020  2021  2020 
Current portion of income tax benefit (provision):            
Federal $1.0  $5.3  $1.6  $3.0 
State  (8.2)  (4.7)  (24.8)  (13.4)
Foreign  0.1   0.2   (1.0)  0 
Total current portion  (7.1)  0.8   (24.2)  (10.4)
Deferred portion of income tax benefit (provision):                
    Federal  (7.1)  18.7   (19.3)  145.1 
    State  (1.9)  (0.4)  (13.8)  3.9 
Foreign  0   0   0   0 
Total deferred portion  (9.0)  18.3   (33.1)  149.0 
Total benefit from (provision for) income taxes $(16.1) $19.1  $(57.3) $138.6 

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

  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2021  2020  2021  2020 
Pre-Tax Net Book Income (“NBI”) $1,198.2  $1,064.9  $3,748.0  $3,381.2 
                 
Texas Margin Tax (1)  (9.6)  (7.2)  (37.0)  (21.9)
State income tax benefit (provision), net of federal benefit (2)  (0.1)  1.6   (1.0)  9.7 
Federal income tax benefit (provision) computed by applying
     the federal statutory rate to NBI of corporate entities
  (3.3)  25.1   (9.8)  83.4 
Federal benefit attributable to settlement of
Liquidity Option Agreement (2)
  0   0   0   67.8 
Valuation allowance (3)  (3.1)  0   (9.3)  0 
Other  0   (0.4)  (0.2)  (0.4)
Benefit from (provision for) income taxes $(16.1) $19.1  $(57.3) $138.6 
                 
Effective income tax rate  (1.3)%  1.8%  (1.5)%  4.1%

(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.
(3)Management believes that it is more likely than not that the net deferred tax assets attributable to OTA will not be fully realizable; therefore, we have provided for a valuation allowance.

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

  September 30,  December 31, 
  2021  2020 
Deferred tax liabilities:      
Attributable to investment in OTA $376.7  $356.6 
Attributable to property, plant and equipment  119.8   106.4 
Attributable to investments in other entities  4.4   4.1 
Other  13.5   0 
     Total deferred tax liabilities  514.4   467.1 
Deferred tax assets:        
Net operating loss carryovers (1)  9.4   0.1 
Temporary differences related to Texas Margin Tax  3.0   2.3 
Total deferred tax assets  12.4   2.4 
Valuation allowance  9.3   0 
Total deferred tax assets, net of valuation allowance  3.1   2.4 
Total net deferred tax liabilities $511.3  $464.7 

(1)Of the loss amount presented for September 30, 2021, $0.1 million expires in various years between 2021 and 2037.  The remaining $9.3 million has an indefinite carryover period.  All losses are subject to limitations on their utilization.

OTA Deferred Tax Liability

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

At March 5, 2020, the Liquidity Option liability amount was $511.9 million.  Since the book value of the Liquidity Option liability exceeded OTA’s estimated deferred tax liability of $439.7 million on that date, we recognized a non-cash benefit in earnings of $72.2 million, which is reflected in the “Benefit from (provision for) income taxes” line on our Unaudited Condensed Statement of Consolidated Operations for the nine months ended September 30, 2020.  OTA recognized an additional net, non-cash deferred income tax benefit of $85.8 million at September 30, 2020 primarily due to a decrease in the outside basis difference of its investment in the Partnership attributable to a decline in the market price of the Partnership’s common units subsequent to March 5, 2020 through September 30, 2020.  In total, our earnings for the nine months ended September 30, 2020 reflect $158.0 million of net deferred income tax benefit attributable to OTA.

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Note 16.  Commitments and Contingent Liabilities

Litigation

As part of our normal business activities, we may be named as defendants in legal proceedings, including those arising from regulatory and environmental matters.  Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to fully indemnify us against losses arising from future legal proceedings.  We will vigorously defend the Partnership in litigation matters.
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Our accruals for litigation contingencies were $6.9$0.2 million and $0.2$6.1 million at September 30, 20202021 and December 31, 2019, respectively, and recorded2020, respectively.  We have classified our accruals for litigation contingencies in our Unaudited Condensed Consolidated Balance Sheets as a component of “Other current liabilities.”liabilities” or “Other long-term liabilities” based on management’s estimate regarding the timing of settlement.  

Energy Transfer Matter
As reported in our 2019 Form 10-K, we prevailed on our appeal on January 31, 2020 when the Supreme Court of Texas unanimously affirmed the opinion of the Dallas Court of Appeals.  On March 6, 2020, the Supreme Court of Texas issued its mandate to the Dallas County Civil District Court, bringing this lawsuit and the resulting appeal to a close.

PDH 1 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 initialfirst propane dehydrogenation facility (“PDH 1”) facility..  In November 2014, Foster Wheeler was acquired by an affiliate of AMEC plc to form Amec Foster Wheeler plc, and Foster Wheeler is now known as Amec Foster Wheeler USA Corporation (“AFW”).  In December 2015, Enterprise and AFW entered into a transition services agreement under which AFW was partially terminated from the PDH 1 project.  In December 2015, Enterprise engaged a second contractor, Optimized Process Designs LLC, to complete the construction and installation of PDH 1.

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

Contractual Obligations

Scheduled Maturities of Debt
We have long-term and short-term payment obligations under debt agreements.  In total, the principal amount of our consolidated debt obligations were $30.15$29.82 billion and $27.88$30.15 billion at September 30, 20202021 and December 31, 2019,2020, respectively.  The year-to-date reduction in debt principal amount outstanding is due to EPO’s repayment of Senior Notes TT and RR, partially offset by EPO’s issuance of Senior Notes EEE. See Note 7 for additional information regarding our scheduled future maturities of debt principal.

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

The following table presents information regarding operating leases where we are the lessee at September 30, 2020:2021:

Asset Category
ROU
Asset
Carrying
Value (1)
 
Lease
Liability
Carrying
    Value (2)
 
Weighted-
Average
Remaining
Term
 
Weighted-
Average
Discount
Rate (3)
ROU
Asset
Carrying
Value (1)
 
Lease
Liability
Carrying
    Value (2)
 
Weighted-
Average
Remaining
Term
 
Weighted-
Average
Discount
Rate (3)
Storage and pipeline facilities$131.0 $131.5 16 years 4.3%$164.0 $164.5 12 years 3.6%
Transportation equipment 
            37.4
              39.7 3 years 3.5% 
            22.6
              24.4 2 years 2.6%
Office and warehouse space 
            172.7
              183.0 16 years 3.2% 
            166.3
              190.2 15 years 3.2%
Total$ 341.1 $354.2    $ 352.9 $379.1    

(1)Right-of-use (“ROU”) asset amounts are a component of “Other assets” on our Unaudited Condensed Consolidated Balance Sheet.
(2)At September 30, 2020,2021, lease liabilities of $28.6$35.5 million and $325.6$343.6 million were included within “Other current liabilities” and “Other long-term 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, Leases.

InThe following table disaggregates our total our ROU asset andoperating lease liability carrying values increased $130.9expense for the periods indicated:

  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2021  2020  2021  2020 
Long-term operating leases:            
   Fixed lease expense:            
      Non-cash lease expense (amortization of ROU assets) $10.9  $9.8  $29.5  $29.6 
      Related accretion expense on lease liability balances  3.2   3.1   9.3   9.8 
      Total fixed lease expense  14.1   12.9   38.8   39.4 
   Variable lease expense  0.2   0.1   0.8   0.4 
Subtotal operating lease expense  14.3   13.0   39.6   39.8 
Short-term operating leases  15.0   12.3   41.4   37.3 
Total operating lease expense $29.3  $25.3  $81.0  $77.1 

Cash payments attributable to operating lease liabilities were $10.8 million and $142.2$9.8 million respectively, sincefor the three months ended September 30, 2021 and 2020, respectively.  For the nine months ended September 30, 2021 and 2020, cash paid for operating lease liabilities was $29.2 million and $28.1 million, respectively.

Operating lease income for the three months ended September 30, 2021 and 2020 was $3.1 million and $2.3 million, respectively.  For the nine months ended September 30, 2021 and 2020, operating lease income was $9.2 and $8.4 million, respectively.

Purchase Obligations
We have contractual future product purchase commitments for natural gas, NGLs, crude oil, petrochemicals and refined products representing enforceable and legally binding agreements as of the reporting date. Our product purchase commitments increased from $14.8 billion at December 31, 20192020 to $22.1 billion at September 30, 2021 primarily due to an increase in crude oil and NGL prices between the modification of an office space lease with an affiliate of EPCO.two reporting dates.


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

  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2020  2019  2020  2019 
Long-term operating leases:            
   Fixed lease expense:            
      Non-cash lease expense (amortization of ROU assets) $9.8  $10.7  $29.6  $32.4 
      Related accretion expense on lease liability balances  3.1   2.1   9.8   6.9 
      Total fixed lease expense  12.9   12.8   39.4   39.3 
   Variable lease expense  0.1   1.6   0.4   4.5 
Subtotal operating lease expense  13.0   14.4   39.8   43.8 
Short-term operating leases  12.3   12.4   37.3   35.9 
Total operating lease expense $25.3  $26.8  $77.1  $79.7 

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 $9.8 million and $13.0 million for the three months ended September 30, 2020 and 2019, respectively.  For the nine months ended September 30, 2020 and 2019 cash paid for operating lease liabilities was $28.1 million and $39.4 million, respectively.

We do not have any significant operating or direct financing leases where we are the lessor.  Our operating lease income for the three months ended September 30, 2020 and 2019 was $2.3 million and $3.5 million, respectively.  For the nine months ended September 30, 2020 and 2019 operating lease income was $8.4 million and $10.7 million, respectively.  We do not have any sales-type leases.

Including the impact of the modification of the related party office space lease, our total operating lease commitments increased from $271.2 million at December 31, 2019 to approximately $469.2 million at September 30, 2020.

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 September 30, 2020 declined by an estimated $6.3 billion when compared to those reported in our 2019 Form 10-K primarily due to lower NGL and crude oil prices in the nine months ended September 30, 2020.  At September 30, 2020, our estimated long-term product purchase obligations totaled $14.27 billion after reflecting the decline in commodity prices, agreements added during the nine months ended September 30, 2020 and those commitments that expired during the year.  At December 31, 2019, our estimated long-term product purchase obligations totaled $20.57 billion.

Settlement of Liquidity Option

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


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Note 17.  Supplemental Cash Flow Information

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

 
For the Nine Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
 2020  2019  2021  2020 
Decrease (increase) in:            
Accounts receivable – trade $1,119.5  $(578.0) $(1,541.0) $1,119.5 
Accounts receivable – related parties  1.0   1.6   2.0   1.0 
Inventories  (1,063.2)  (44.2)  520.2   (1,063.2)
Prepaid and other current assets  288.2   (305.3)  409.7   288.2 
Other assets  (27.7)  (18.3)  104.0   (27.7)
Increase (decrease) in:                
Accounts payable – trade  147.0   (55.4)  35.6   147.0 
Accounts payable – related parties  (41.0)  31.0   (24.8)  (41.0)
Accrued product payables  (621.9)  666.6   2,501.8   (621.9)
Accrued interest  (196.6)  (158.4)  (230.4)  (196.6)
Other current liabilities  (212.3)  133.6   (696.3)  (212.3)
Other liabilities  (85.0)  (82.2)  (33.7)  (85.0)
Net effect of changes in operating accounts $(692.0) $(409.0) $1,047.1  $(692.0)
                
Cash payments for interest, net of $96.9 and $102.9 capitalized during the
nine months ended September 30, 2020 and 2019, respectively
 $1,107.4  $996.1 
Cash payments for interest, net of $63.8 and $96.9 capitalized during the
nine months ended September 30, 2021 and 2020, respectively
 $1,143.5  $1,107.4 
                
Cash payments for federal and state income taxes $24.9  $24.7  $17.0  $24.9 

We incurred liabilities for construction in progress that had not been paid at September 30, 20202021 and December 31, 20192020 of $272.1$194.6 million and $432.0$236.1 million, respectively.  Such amounts are not included under the caption “Capital expenditures” on the Unaudited Condensed Statements of Consolidated Cash Flows.

We recognized non-cash charges totaling $11.3 million for involuntary conversions during the nine months ended September 30, 2021 that are a component of net losses attributable to asset sales and related matters.



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Note 18.  Condensed Consolidating Financial Information

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

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

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


Enterprise Products Partners L.P.
Unaudited Condensed Consolidating Balance Sheet
September 30, 2020

  EPO and Subsidiaries          
  
Subsidiary
Issuer
(EPO)
  
Other
Subsidiaries
(Non-
guarantor)
  
EPO and
Subsidiaries
Eliminations
and
Adjustments
  
Consolidated
EPO and
Subsidiaries
  
EPD
(Guarantor)
  
Eliminations
and
Adjustments
  
Consolidated
Total
 
ASSETS                     
Current assets:                     
Cash and cash equivalents and restricted cash $863.2  $292.5  $(24.7) $1,131.0  $0.1  $0  $1,131.1 
Accounts receivable – trade, net  1,155.1   2,621.9   (0.8)  3,776.2   0   0   3,776.2 
Accounts receivable – related parties  145.8   782.0   (915.0)  12.8   0   (8.7)  4.1 
Inventories  2,447.6   745.3   (0.3)  3,192.6   0   0   3,192.6 
Derivative assets  101.6   31.3   0   132.9   0   0   132.9 
Prepaid and other current assets  269.8   445.5   (159.7)  555.6   0.2   0.6   556.4 
Total current assets  4,983.1   4,918.5   (1,100.5)  8,801.1   0.3   (8.1)  8,793.3 
Property, plant and equipment, net  6,685.4   35,715.0   (40.3)  42,360.1   0   0   42,360.1 
Investments in unconsolidated affiliates  46,284.9   4,840.8   (48,640.3)  2,485.4   25,092.9   (25,092.9)  2,485.4 
Intangible assets, net  624.3   2,741.0   (16.7)  3,348.6   0   0   3,348.6 
Goodwill  459.5   5,285.7   0   5,745.2   0   0   5,745.2 
Other assets  907.0   335.0   (239.4)  1,002.6   1.0   0   1,003.6 
Total assets $59,944.2  $53,836.0  $(50,037.2) $63,743.0  $25,094.2  $(25,101.0) $63,736.2 
                             
LIABILITIES AND EQUITY                            
Current liabilities:                            
Current maturities of debt $1,325.0  $0  $0  $1,325.0  $0  $0  $1,325.0 
Accounts payable – trade  288.3   631.4   (24.7)  895.0   1.0   0   896.0 
Accounts payable – related parties  891.1   158.1   (927.9)  121.3   8.7   (8.7)  121.3 
Accrued product payables  1,879.1   2,439.0   (1.0)  4,317.1   0   0   4,317.1 
Accrued interest  235.0   3.2   (3.1)  235.1   0   0   235.1 
Derivative liabilities  329.3   0.4   0   329.7   0   0   329.7 
Other current liabilities  201.8   579.1   (158.2)  622.7   0   0   622.7 
Total current liabilities  5,149.6   3,811.2   (1,114.9)  7,845.9   9.7   (8.7)  7,846.9 
Long-term debt  28,522.4   14.6   0   28,537.0   0   0   28,537.0 
Deferred tax liabilities  25.5   434.2   (0.5)  459.2   0   4.1   463.3 
Other long-term liabilities  370.0   607.3   (242.1)  735.2   0   0   735.2 
Commitments and contingent liabilities                     
Redeemable preferred limited partner interests  0   0   0   0   49.2   (0.1)  49.1 
Equity:                            
Partners’ and other owners’ equity  25,876.7   48,905.3   (49,724.5)  25,057.5   25,035.3   (25,057.5)  25,035.3 
Noncontrolling interests in consolidated subsidiairies  0   63.4   1,044.8   1,108.2   0   (38.8)  1,069.4 
Total equity  25,876.7   48,968.7   (48,679.7)  26,165.7   25,035.3   (25,096.3)  26,104.7 
Total liabilities, preferred units, and equity $59,944.2  $53,836.0  $(50,037.2) $63,743.0  $25,094.2  $(25,101.0) $63,736.2 

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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, 2019

  EPO and Subsidiaries          
  
Subsidiary
Issuer
(EPO)
  
Other
Subsidiaries
(Non-
guarantor)
  
EPO and
Subsidiaries
Eliminations
and
Adjustments
  
Consolidated
EPO and
Subsidiaries
  
EPD
(Guarantor)
  
Eliminations
and
Adjustments
  
Consolidated
Total
 
ASSETS                     
Current assets:                     
Cash and cash equivalents and restricted cash $109.2  $315.8  $(15.1) $409.9  $0.1  $0  $410.0 
Accounts receivable – trade, net  1,471.1   3,403.8   (1.3)  4,873.6   0   0   4,873.6 
Accounts receivable – related parties  233.1   799.9   (1,023.6)  9.4   0   (6.9)  2.5 
Inventories  1,351.3   740.4   (0.3)  2,091.4   0   0   2,091.4 
Derivative assets  115.2   12.0   0   127.2   0   0   127.2 
Prepaid and other current assets  221.0   183.5   (46.3)  358.2   0   0   358.2 
Total current assets  3,500.9   5,455.4   (1,086.6)  7,869.7   0.1   (6.9)  7,862.9 
Property, plant and equipment, net  6,413.3   35,233.6   (43.5)  41,603.4   0   0   41,603.4 
Investments in unconsolidated affiliates  45,514.0   4,165.7   (47,079.5)  2,600.2   25,279.3   (25,279.3)  2,600.2 
Intangible assets, net  636.7   2,852.3   (40.0)  3,449.0   0   0   3,449.0 
Goodwill  459.5   5,285.7   0   5,745.2   0   0   5,745.2 
Other assets  404.9   288.5   (221.9)  471.5   1.0   0   472.5 
Total assets $56,929.3  $53,281.2  $(48,471.5) $61,739.0  $25,280.4  $(25,286.2) $61,733.2 
                             
LIABILITIES AND EQUITY                            
Current liabilities:                            
Current maturities of debt $1,981.9  $0  $0  $1,981.9  $0  $0  $1,981.9 
Accounts payable – trade  301.4   717.7   (14.6)  1,004.5   0   0   1,004.5 
Accounts payable – related parties  977.5   222.3   (1,037.5)  162.3   6.9   (6.9)  162.3 
Accrued product payables  1,895.4   3,021.9   (1.6)  4,915.7   0   0   4,915.7 
Accrued interest  431.6   0.9   (0.8)  431.7   0   0   431.7 
Derivative liabilities  114.2   8.2   0   122.4   0   0   122.4 
Other current liabilities  120.5   438.2   (47.3)  511.4   0   (0.2)  511.2 
Total current liabilities  5,822.5   4,409.2   (1,101.8)  9,129.9   6.9   (7.1)  9,129.7 
Long-term debt  25,628.6   14.6   0   25,643.2   0   0   25,643.2 
Deferred tax liabilities  22.2   75.6   (0.8)  97.0   0   3.4   100.4 
Other long-term liabilities  161.2   608.9   (247.2)  522.9   509.5   0   1,032.4 
Commitments and contingent liabilities                     
Equity:                            
Partners’ and other owners’ equity  25,294.8   48,107.6   (48,155.3)  25,247.1   24,764.0   (25,247.1)  24,764.0 
Noncontrolling interests in consolidated subsidiairies  0   65.3   1,033.6   1,098.9   0   (35.4)  1,063.5 
Total equity  25,294.8   48,172.9   (47,121.7)  26,346.0   24,764.0   (25,282.5)  25,827.5 
Total liabilities and equity $56,929.3  $53,281.2  $(48,471.5) $61,739.0  $25,280.4  $(25,286.2) $61,733.2 

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


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

 EPO and Subsidiaries          
  
Subsidiary
Issuer
(EPO)
  
Other
Subsidiaries
(Non-
guarantor)
  
EPO and
Subsidiaries
Eliminations
and
Adjustments
  
Consolidated
EPO and
Subsidiaries
  
EPD
(Guarantor)
  
Eliminations
and
Adjustments
  
Consolidated
Total
 
Revenues $11,392.7  $4,135.4  $(8,606.1) $6,922.0  $0  $0  $6,922.0 
Costs and expenses:                            
Operating costs and expenses  11,053.8   3,124.1   (8,606.7)  5,571.2   0   0   5,571.2 
General and administrative costs  8.1   41.2   0.7   50.0   0.3   0   50.3 
Total costs and expenses  11,061.9   3,165.3   (8,606.0)  5,621.2   0.3   0   5,621.5 
Equity in income of unconsolidated affiliates  923.7   114.3   (956.0)  82.0   1,053.0   (1,053.0)  82.0 
Operating income  1,254.5   1,084.4   (956.1)  1,382.8   1,052.7   (1,053.0)  1,382.5 
Other income (expense):                            
Interest expense  (320.8)  (2.5)  2.8   (320.5)  0   0   (320.5)
Other, net  4.4   (114.1)  112.6   2.9   0   0   2.9 
Total other expense, net  (316.4)  (116.6)  115.4   (317.6)  0   0   (317.6)
Income before income taxes  938.1   967.8   (840.7)  1,065.2   1,052.7   (1,053.0)  1,064.9 
Benefit from (provision for) income taxes  (1.7)  21.3   (0.1)  19.5   0.1   (0.5)  19.1 
Net income  936.4   989.1   (840.8)  1,084.7   1,052.8   (1,053.5)  1,084.0 
Net income attributable to noncontrolling interests  0   (1.8)  (31.3)  (33.1)  0   1.7   (31.4)
Net income attributable to preferred units  0   0   0   0   (0.2)  0.2   0 
Net income attributable to entity $936.4  $987.3  $(872.1) $1,051.6  $1,052.6  $(1,051.6) $1,052.6 


Enterprise Products Partners L.P.
Unaudited Condensed Consolidating Statement of Operations
For the Three 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
 
Revenues $8,268.7  $5,238.9  $(5,543.5) $7,964.1  $0  $0  $7,964.1 
Costs and expenses:                            
Operating costs and expenses  7,950.9   4,166.6   (5,543.8)  6,573.7   0   0   6,573.7 
General and administrative costs  9.4   45.4   0.4   55.2   0.3   0   55.5 
Total costs and expenses  7,960.3   4,212.0   (5,543.4)  6,628.9   0.3   0   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)  0   0   (382.9)
Other, net  8.7   1.8   (2.9)  7.6   (38.7)  0   (31.1)
Total other expense, net  (374.5)  (0.8)  0   (375.3)  (38.7)  0   (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)  0   (15.1)  0   (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  0   (1.5)  (25.4)  (26.9)  0   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 

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


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

 EPO and Subsidiaries          
  
Subsidiary
Issuer
(EPO)
  
Other
Subsidiaries
(Non-
guarantor)
  
EPO and
Subsidiaries
Eliminations
and
Adjustments
  
Consolidated
EPO and
Subsidiaries
  
EPD
(Guarantor)
  
Eliminations
and
Adjustments
  
Consolidated
Total
 
Revenues $29,836.7  $12,609.5  $(22,290.7) $20,155.5  $0  $0  $20,155.5 
Costs and expenses:                            
Operating costs and expenses  28,856.1   9,438.6   (22,292.8)  16,001.9   0   0   16,001.9 
General and administrative costs  28.5   130.6   2.1   161.2   1.6   0   162.8 
Total costs and expenses  28,884.6   9,569.2   (22,290.7)  16,163.1   1.6   0   16,164.7 
Equity in income of unconsolidated affiliates  2,972.6   422.3   (3,058.8)  336.1   3,368.9   (3,368.9)  336.1 
Operating income  3,924.7   3,462.6   (3,058.8)  4,328.5   3,367.3   (3,368.9)  4,326.9 
Other income (expense):                            
Interest expense  (959.0)  (7.6)  8.4   (958.2)  0   0   (958.2)
Other, net  17.4   (386.9)  384.0   14.5   (2.0)  0   12.5 
Total other expense, net  (941.6)  (394.5)  392.4   (943.7)  (2.0)  0   (945.7)
Income before income taxes  2,983.1   3,068.1   (2,666.4)  3,384.8   3,365.3   (3,368.9)  3,381.2 
Benefit from (provision for) income taxes  (10.5)  78.3   (0.4)  67.4   72.3   (1.1)  138.6 
Net income  2,972.6   3,146.4   (2,666.8)  3,452.2   3,437.6   (3,370.0)  3,519.8 
Net income attributable to noncontrolling interests  0   (4.6)  (82.5)  (87.1)  0   4.7   (82.4)
Net income attributable to preferred units  0   0   0   0   (0.2)  0.2   0 
Net income attributable to entity $2,972.6  $3,141.8  $(2,749.3) $3,365.1  $3,437.4  $(3,365.1) $3,437.4 


Enterprise Products Partners L.P.
Unaudited Condensed Consolidating Statement of Operations
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
 
Revenues $25,664.8  $16,618.5  $(17,499.4) $24,783.9  $0  $0  $24,783.9 
Costs and expenses:                            
Operating costs and expenses  24,670.6   13,216.2   (17,492.5)  20,394.3   0   0   20,394.3 
General and administrative costs  22.6   133.4   2.3   158.3   1.9   0   160.2 
Total costs and expenses  24,693.2   13,349.6   (17,490.2)  20,552.6   1.9   0   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)  0   0   (950.2)
Other, net  16.0   4.2   (8.5)  11.7   (123.1)  0   (111.4)
Total other expense, net  (934.9)  (3.6)  0   (938.5)  (123.1)  0   (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)  0   (36.5)  0   (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  0   (4.9)  (66.5)  (71.4)  0   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 


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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, 2020

 EPO and Subsidiaries          
  
Subsidiary
Issuer
(EPO)
  
Other
Subsidiaries
(Non-
guarantor)
  
EPO and
Subsidiaries
Eliminations
and
Adjustments
  
Consolidated
EPO and
Subsidiaries
  
EPD
(Guarantor)
  
Eliminations
and
Adjustments
  
Consolidated
Total
 
Comprehensive income $1,083.0  $940.4  $(840.8) $1,182.6  $1,150.4  $(1,151.2) $1,181.8 
Comprehensive income attributable to noncontrolling interests  0   (1.8)  (31.3)  (33.1)  0   1.7   (31.4)
Comprehensive income attributable to  preferred units  0   0   0   0   (0.2)  0.2   0 
Comprehensive income attributable to entity $1,083.0  $938.6  $(872.1) $1,149.5  $1,150.2  $(1,149.3) $1,150.4 

Unaudited Condensed Consolidating Statement of Comprehensive Income
For the Three 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 $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  0   (1.5)  (25.4)  (26.9)  0   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 Nine Months Ended September 30, 2020

  EPO and Subsidiaries          
  
Subsidiary
Issuer
(EPO)
  
Other
Subsidiaries
(Non-
guarantor)
  
EPO and
Subsidiaries
Eliminations
and
Adjustments
  
Consolidated
EPO and
Subsidiaries
  
EPD
(Guarantor)
  
Eliminations
and
Adjustments
  
Consolidated
Total
 
Comprehensive income $2,767.1  $3,231.4  $(2,666.8) $3,331.7  $3,316.7  $(3,249.3) $3,399.1 
Comprehensive income attributable to noncontrolling interests
  0   (4.6)  (82.5)  (87.1)  0   4.7   (82.4)
Comprehensive income attributable to  preferred units  0   0   0   0   (0.2)  0.2   0 
Comprehensive income attributable to entity $2,767.1  $3,226.8  $(2,749.3) $3,244.6  $3,316.5  $(3,244.4) $3,316.7 

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  0   (4.9)  (66.5)  (71.4)  0   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 

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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 Nine Months Ended September 30, 2020

 EPO and Subsidiaries          
  
Subsidiary
Issuer
(EPO)
  
Other
Subsidiaries
(Non-
guarantor)
  
EPO and
Subsidiaries
Eliminations
and
Adjustments
  
Consolidated
EPO and
Subsidiaries
  
EPD
(Guarantor)
  
Eliminations
and
Adjustments
  
Consolidated
Total
 
Operating activities:                     
Net income $2,972.6  $3,146.4  $(2,666.8) $3,452.2  $3,437.6  $(3,370.0) $3,519.8 
Reconciliation of net income to net cash flows provided by operating activities:                            
Depreciation, amortization and accretion  260.8   1,286.9   (2.6)  1,545.1   0   0   1,545.1 
Equity in income of unconsolidated affiliates  (2,972.6)  (422.3)  3,058.8   (336.1)  (3,368.9)  3,368.9   (336.1)
Distributions received from unconsolidated affiliates attributable to earnings  1,071.3   157.4   (891.3)  337.4   3,164.4   (3,164.4)  337.4 
Net effect of changes in operating accounts and other operating activities  1,997.2   (2,254.3)  (449.2)  (706.3)  (68.7)  0.4   (774.6)
Net cash flows provided by operating activities  3,329.3   1,914.1   (951.1)  4,292.3   3,164.4   (3,165.1)  4,291.6 
Investing activities:                            
Capital expenditures  (533.9)  (2,139.1)  1.4   (2,671.6)  0   0   (2,671.6)
Proceeds from asset sales  1.2   7.2   0   8.4   0   0   8.4 
Other investing activities  (1,106.8)  30.4   1,175.4   99.0   0   0   99.0 
Cash used in investing activities  (1,639.5)  (2,101.5)  1,176.8   (2,564.2)  0   0   (2,564.2)
Financing activities:                            
Borrowings under debt agreements  6,672.1   0   0   6,672.1   0   0   6,672.1 
Repayments of debt  (4,406.6)  0   0   (4,406.6)  0   0   (4,406.6)
Cash distributions paid to owners  (3,164.4)  (1,104.7)  1,153.5   (3,115.6)  (2,968.4)  3,164.4   (2,919.6)
Cash payments made in connection with DERs  0   0   0   0   (20.0)  0   (20.0)
Cash distributions paid to noncontrolling interests  0   (6.6)  (91.9)  (98.5)  0   0.7   (97.8)
Cash contributions from noncontrolling interests  0   0   21.2   21.2   0   0   21.2 
Repurchase of common units under 2019 Buyback Program  0   0   0   0   (173.8)  0   (173.8)
Net cash proceeds from the issuance of preferred unit  0   0   0   0   32.5   0   32.5 
Cash contributions from owners  0   1,275.4   (1,275.4)  0   0   0   0 
Other financing activities  (36.9)  0   (42.7)  (79.6)  (34.7)  0   (114.3)
Cash provided by (used in) financing activities  (935.8)  164.1   (235.3)  (1,007.0)  (3,164.4)  3,165.1   (1,006.3)
Net change in cash and cash equivalents,
   including restricted cash
  754.0   (23.3)  (9.6)  721.1   0   0   721.1 
Cash and cash equivalents, including
   restricted cash, at beginning of period
  109.2   315.8   (15.1)  409.9   0.1   0   410.0 
Cash and cash equivalents, including
   restricted cash, at end of period
 $863.2  $292.5  $(24.7) $1,131.0  $0.1  $0  $1,131.1 

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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 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
 
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 
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   0   0   1,456.7 
Equity in income of unconsolidated affiliates  (3,606.9)  (496.8)  3,672.4   (431.3)  (3,619.4)  3,619.4   (431.3)
Distributions received from unconsolidated affiliates attributable to earnings  1,170.9   243.0   (982.7)  431.2   3,028.9   (3,028.9)  431.2 
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)
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 
Investing activities:                            
Capital expenditures  (503.8)  (2,791.2)  (7.1)  (3,302.1)  0   0   (3,302.1)
Proceeds from asset sales  0.9   15.9   0   16.8   0   0   16.8 
Other investing activities  (1,349.5)  (28.8)  1,290.8   (87.5)  (119.3)  119.3   (87.5)
Cash used in investing activities  (1,852.4)  (2,804.1)  1,283.7   (3,372.8)  (119.3)  119.3   (3,372.8)
Financing activities:                            
Borrowings under debt agreements  44,629.6   0   0   44,629.6   0   0   44,629.6 
Repayments of debt  (42,855.2)  (0.1)  0   (42,855.3)  0   0   (42,855.3)
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)
Cash payments made in connection with DERs  0   0   0   0   (16.4)  0   (16.4)
Cash distributions paid to noncontrolling interests  0   (7.0)  (63.4)  (70.4)  0   0.7   (69.7)
Cash contributions from noncontrolling interests  0   0   590.8   590.8   0   0   590.8 
Net cash proceeds from issuance of common units  0   0   0   0   82.2   0   82.2 
Repurchase of common units under 2019 Buyback Program  0   0   0   0   (81.1)  0   (81.1)
Cash contributions from owners  119.3   2,320.3   (2,320.3)  119.3   0   (119.3)  0 
Other financing activities  (26.3)  (5.6)  0   (31.9)  (32.8)  0   (64.7)
Cash provided by (used in) financing activities  (1,161.5)  822.8   (308.1)  (646.8)  (2,919.2)  2,910.3   (655.7)
Net change in cash and cash equivalents,
   including restricted cash
  610.8   185.4   1.5   797.7   0   0   797.7 
Cash and cash equivalents, including
   restricted cash, at beginning of period
  393.4   50.3   (33.6)  410.1   0   0   410.1 
Cash and cash equivalents, including
   restricted cash, at end of period
 $1,004.2  $235.7  $(32.1) $1,207.8  $0  $0  $1,207.8 




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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, 20202021 and 20192020

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, 20192020 (the “2019“2020 Form 10-K”), as filed on February 28, 2020March 1, 2021 with the U.S. Securities and Exchange Commission (“SEC”).  Our financial statements have been prepared in accordance with generally accepted accounting principles (“GAAP”) in the United States (“U.S.”).

Key References Used in this Management’s Discussion and Analysis

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

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

References to “EPCO” mean Enterprise Products Company, a privately held Texas corporation, and its privately held affiliates.  A majority of the outstanding voting capital stock of EPCO is owned by a voting trust, the current trustees (“EPCO Trustees”) of which are:  (i) Ms. Duncan Williams, who serves as Chairman of EPCO; (ii) Dr. Cunningham, who serves as Vice Chairman of EPCO; and (iii) Mr. Bachmann, who serves as the President and Chief Executive Officer of EPCO.  Ms. Duncan Williams and Mr. Bachmann also currently serve as directors of EPCO along with Mr. Fowler, who is also the Executive Vice President and Chief Financial Officer of EPCO. EPCO, together with its privately held affiliates, owned approximately 32.2% of EPD’s common units outstanding and 30% of its Series A Cumulative Convertible Preferred Units (“preferred units”) outstanding at September 30, 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 third quarter of 2020 compared to the third quarter of 2019.  Likewise, the phrase “period-to-period” means the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019.
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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATIONCautionary Statement Regarding Forward-Looking Information

This quarterly report on Form 10-Q for the nine months ended September 30, 2021 (our “quarterly report”) contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us.  When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “seek,” “goal,” “estimate,” “forecast,” “intend,” “could,” “should,” “would,” “will,” “believe,” “may,” “scheduled,” “potential” and similar expressions and statements regarding our plans and objectives for future operations are intended to identify forward-looking statements.  Although we and our general partner believe that our expectations reflected in such forward-looking statements (including theany forward-looking statements/expectations of third parties referenced in this quarterly report) are reasonable, neither we nor our general partner can give any assurances that such expectations will prove to be correct.  

Forward-looking statements are subject to a variety of risks (including those attributable to the Coronavirus disease 2019 (“COVID-19”) pandemic), uncertainties and assumptions as described in more detail under Part I, Item 1A of our 20192020 Form 10-K and within Part II, Item 1A of this quarterly report.  These risks include recent impacts of the coronavirus disease 2019 (“COVID-19”) and decreases in certain commodity prices resulting from demand weakness and oversupply, which are discussed in Part II, Item 1A “Risk Factors” of this quarterly report, and this Part I, Item 2.10-K.  If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected.  You should not put undue reliance on any forward-looking statements.  The forward-looking statements in this quarterly report speak only as of the date hereof.  Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason.

OverviewKey References Used in this Management’s Discussion and Analysis

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

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

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

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

References to “EPCO” mean Enterprise Products Company, a privately held Texas corporation, and its privately held affiliates.  The outstanding voting capital stock of EPCO is owned by a voting trust, the current trustees (“EPCO Trustees”) of which are:  (i) Ms. Duncan Williams, who serves as Chairman of EPCO; (ii) Mr. Bachmann, who serves as the President and Chief Executive Officer of EPCO; and (iii) Mr. Fowler, who serves as an Executive Vice President and the Chief Financial Officer of EPCO.  Ms. Duncan Williams and Messrs. Bachmann and Fowler also currently serve as directors of EPCO.
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We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates under the collective common control of the DD LLC Trustees and the EPCO Trustees.  EPCO, together with its privately held affiliates, owned approximately 32.2% of the Partnership’s common units outstanding at September 30, 2021.  In March 2021, a privately held affiliate of EPCO sold its entire ownership interest in the Partnership’s Series A Cumulative Convertible Preferred Units (“preferred units”) to third parties.

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

/d=per dayMMBPD=million barrels per day
BBtus=billion British thermal unitsMMBtus=million British thermal units
Bcf=billion cubic feetMMcf=million cubic feet
BPD=barrels per dayMWac=megawatts, alternating current
MBPD=thousand barrels per dayMWdc=megawatts, direct current
MMBbls=million barrelsTBtus=trillion British thermal units

As used in this quarterly report, the phrase “quarter-to-quarter” means the third quarter of 2021 compared to the third quarter of 2020.  Likewise, the phrase “period-to-period” means the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020.

Business Summary

We are a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.”  The Partnership’sOur preferred units are not publicly traded.  We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO and are a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, petrochemicals and refined products. 

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.   

The Partnership isWe are owned by itsour limited partners (preferred and common unitholders) from an economic perspective.   Enterprise GP, which owns a non-economic general partner interest in the Partnership,us, manages our operations. The Partnership conductsPartnership.  We conduct substantially all of our business operations through EPO and its business through EPO.  We, Enterprise GP, EPCOconsolidated subsidiaries.

Our fully integrated, midstream energy asset network (or “value chain”) links producers of natural gas, NGLs and Dan Duncan LLC are affiliates under the collective common controlcrude oil from some of the DD LLC Trusteeslargest supply basins in the United States (“U.S.”), Canada and the EPCO Trustees.  Gulf of Mexico with domestic consumers and international markets.  Our midstream energy operations include:

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

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

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

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

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

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

The safe operation of our assets is a top priority.  We are committed to protecting the environment and the health and safety of the public and those working on our behalf by conducting our business activities in a safe and environmentally responsible manner.  For additional information, see “Environmental, Safety and Conservation” within the Regulatory Matters section of Part I, Items 1 and 2 of the 2020 Form 10-K.

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.
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Our financial position, results of operations and cash flows are reportedsubject to certain risks. For information regarding such risks, see “Risk Factors” included 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 toPart I, Item 1A of the types of services rendered (or technologies employed) and products produced and/or sold.2020 Form 10-K.

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


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Current Outlook

As noted previously under “Cautionary Statement Regarding Forward-Looking Information” within this Part I, Item 2, this quarterly report on Form 10-Q, including this update to our outlook on business conditions, contains forward-looking statements that are based on our beliefs and those of our general partner, as well asEnterprise GP.  In addition, it reflects assumptions made by us and information currently available to us, which includes forecast information published by third parties. See “Cautionary Statement Regarding Forward-Looking Information” within this Part I, Item 2All references to U.S. Energy Information Administration (“EIA”) forecasts and “Risk Factors” in Part II, Item 1A, for additional information.  expectations are derived from its October 2021 Short-Term Energy Outlook (“October 2021 STEO”), which was published on October 13, 2021. The following update to our Current Outlook replaces the general outlook provided in our 2019 Form 10-K under Part II, Item 7forecasts and presents our current views on key midstream energy supply and demand fundamentals for the remainder of 2020 and extending, where appropriate, into 2021. The third-party supply and demand forecastsother forward-looking information cited in the following discussion including our internal forecasts based on such information, remain subject to significant uncertainty becausesince global mitigation efforts and reopening effortsmedical developments related to COVID-19 and the introduction of approved vaccines or proven therapeutics continue to evolve.

As describedThe outlook on business conditions in our 20192020 Form 10-K changes in the supply of and demand for hydrocarbon products impacts both the volume of productsaddressed observations that we sell and the level of services that we provide to customers, which in turn has a direct impact on our financial position, results of operations and cash flows.  The global effects of the COVID-19 pandemic, which began in the first quarter of 2020 and include the consequences of international COVID-19 containment measures (e.g., quarantines, travel restrictions, temporary business closures and similar protective actions), reduced near-term demand for hydrocarbon products by record amounts and created a significant oversupply situation.  Also, in the early stages of the pandemic, disputes between members ofproduction cuts within the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (collectively, the “OPEC+” group) over crude oil production levels led to unprecedented volatility in global energy markets and a historic collapse in crude oil prices in April 2020.  Although the OPEC+ group and other producers subsequently reached agreements to gradually reduce the oversupply of crude oil through production cuts, the downturn in the energy industry caused by lower demand and prices negatively impacted us, the producers we work with and our other customers to varying degrees.

Demand Side Observations

Across the globe, downstream demand for petroleum products such as gasoline and jet fuel has recovered from the lows of the second quarter of 2020, but remains depressed due to the effects of the pandemic and refiners have reduced their utilization rates in response.  Many countries have begun to ease their COVID-19 containment measures and central banks and governments have instituted fiscal measures in an effort to stimulate economic activity. As a result, hydrocarbon demand has started to recover; however, a continuation of this trend remains dependent on successful containment of the disease and the development of approved vaccines and proven therapeutics. In its October 2020 Short-Term Energy Outlook dated October 6, 2020 (the “October 2020 STEO”), the U.S. Energy Information Administration (“EIA”) forecast that global demand for petroleum and related liquids would average 92.8 MMBPD in 2020 and 99.1 MMBPD in 2021.  By contrast, the EIA estimates that global crude oil demand for 2019 (pre-pandemic) averaged 101.5 MMBPD.

The decrease in hydrocarbon demand attributable to COVID-19 and the resulting oversupply situation caused a significant decrease in crude oil prices.  Prior to the pandemic, crude oil prices for West Texas Intermediate (“WTI”) at Cushing, Oklahoma (as reported by the NYMEX) closed at $61.06 per barrel on December 31, 2019. By March 31, 2020, WTI prices closed at $20.48 per barrel and, notwithstanding the announced OPEC+ production cuts, closed at a record low of a negative $37.63 per barrel on April 20, 2020.  As demand began to recover starting in the second quarter of 2020, WTI prices rebounded from the April lows and closed at $39.27 per barrel on June 30, 2020.  At September 30, 2020, WTI prices closed at $40.22 per barrel.

Supply Side Observations

Production cuts within the OPEC+ group, along with market-driven cuts in U.S., Brazilian and Canadian supplies, due to lower crude oil prices, continue to providewere providing much-needed support for international energy markets in coping with the ongoing weakness in hydrocarbon demand attributable to the COVID-19 pandemic.  We also discussed downstream demand beginning to recover from the lows of 2020, but remaining depressed due to the continued effects of the pandemic.

Throughout the first half of 2021, we highlighted the positive impact that the widespread implementation of vaccination programs and the related easing of COVID-19 mobility restrictions have had on global hydrocarbon demand and stated our belief that energy fundamentals (and global economic conditions in general) remained highly dependent on the successful containment of COVID-19, especially its more contagious emerging variants (e.g., the “Delta” variant), through the distribution, acceptance and administration of proven vaccines and therapeutics for the disease. 

While we maintain our view that the successful containment of COVID-19 is crucial to sustained improvements in energy markets, we believe that production cuts are no longer necessary to support international energy markets and that global downstream demand, while stronger, has not fully recovered. 

The OPEC+ group resolved their production disputeglobal economy, including the U.S., experienced robust growth during 2021, mainly due to restocking inventories and efforts to satisfy consumer demand suppressed by agreeingthe pandemic.  According to reduce their combinedthe EIA, U.S. gross domestic product (“GDP”) is forecast to increase 5.7% in 2021 and 4.5% in 2022, following a decline of 3.4% in 2020.  During this time, we have observed a steady transition from near record levels of crude oil production by 9.7 MMBPDinventories in Maythe U.S. to a more normalized level today as U.S. consumption has outpaced U.S. supply.  We are now seeing temporary shortfalls in global natural gas and June 2020, 9.6 MMBPDcoal supplies as reports from some countries, particularly in July 2020, 7.7 MMBPD from August through December 2020Europe and 5.8 MMBPD from January 2021Asia, have revealed a rationing of energy supplies and curtailments of industrial production.  Some reports have referred to April 2022.  The OPEC+ agreement is scheduled to be reevaluated in December 2021.  In the meantime, globalcurrent situation as an “energy crisis,” which could become even more severe if the world experiences a colder than normal winter.  We believe that U.S. supply and demand fundamentals are continually evaluatedhave become more balanced, but anticipate a slight supply shortfall going into 2022.  The EIA estimates that U.S. production of petroleum and related liquids will average 18.6 MMBPD in 2021 and 20.0 MMBPD in 2022, while U.S. demand for petroleum and related liquids will average 19.7 MMBPD in 2021 and 20.4 MMBPD in 2022.

Throughout this period, prices have increased considerably as evidenced by the OPEC+ Joint Ministerial Monitoring Committee.  The durationprice of market-driven production cuts by non-OPEC countries such as U.S., Brazil and Canada will depend on supply and demand fundamentals.  According to the October 2020 STEO, the EIA expects globalWest Texas Intermediate (“WTI”) crude oil production to average 94.6 MMBPDat Cushing, Oklahoma (as reported by the New York Mercantile Exchange, or “NYMEX”).  It reached six-year highs in 2020, which represents a decline of October 2021 and averaged $71.546.1 MMBPD whenper barrel in September 2021 compared to 2019,$52.10 per barrel in January 2021 and an average of $39.34 per barrel in 2020.  The price of natural gas at Henry Hub, Louisiana (as reported by NYMEX) reached twelve-year highs in October 2021 and averaged $5.11 per MMBtu in September 2021 compared to $2.65 per MMBtu in January 2021 and an average 98.8 MMBPDof $2.13 per MMBtu in 2021.2020.

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As a resultSignificant uncertainty exists with respect to the capabilities and willingness of the current business environment, mostOPEC+ to increase production enough to alleviate high crude oil prices and whether hydrocarbon demand will remain resilient as prices continue to rise.  Despite ongoing pressures faced by many producers in North America have reducedthe U.S. to preserve cash, return capital to their drillinginvestors and completion of new wells.  Baker Hughes reported that the total number of drilling rigs working in the continental U.S. (combinedreduce crude oil and natural gas rigs) declinedproduction activities altogether, potential cash flows from 805 at December 31, 2019these high price levels may eventually become too attractive for U.S. energy investors to 728 at March 31, 2020 and further to 265 at June 30, 2020.forego.  The U.S. drilling rig count stood at 266 on October 2, 2020.  In its October 2020 STEO, the EIA forecasts that U.S. crude oil production will average 11.5 MMBPD in 2020, which is downincrease from 12.3 MMBPD in 2019. Furthermore, the EIA expects U.S. crude oil production to average 11.1 MMBPD in 2021.   According to the October 2020 STEO, the EIA expects U.S. crude oil production to decline to an average of 11.0 MMBPD in the second quarter of 2021 since near-term drilling and completion activity will not generate enough production to offset declines from existing wells. The EIA expects drilling activity to rise later in 2021, contributing to U.S. crude oil production returning to 11.211.7 MMBPD in the fourth quarter of 2021.

Enterprise Outlook

Given the combination of2022; however, these levels still lag behind the record retrenchmentlevel of 12.3 MMBPD in drilling and completion activities by2019.  As U.S. producers in 2020, along with steep decline curves in shale basins that result in lower near-term production through mid-2021, and the expected continuing recovery of global hydrocarbon demand following the pandemic, we believe that crude oil prices could begin to increase as early as the second half of 2021.  However, in the interim, we believe the midstream industry will be challenged in its producer-facing businesses and that the challenges and opportunities will be different for each producing basin.

Although the current industry and business outlooks remain challenging,rises, we believe that our integrated, diversified and fee-based business model, will enable ushave additional opportunities to successfully traverse this difficult period. The Partnershipprovide midstream services to our producers and its consolidated operations remain in a strong position, with our financial strength and operational flexibility demonstrated by the following:customers.

•
At September 30, 2020, we had $6.03 billion of consolidated liquidity, which was comprised of $5.0 billion of available borrowing capacity under EPO’s revolving credit facilities and $1.03 billion of unrestricted cash on hand.  Our liquidity is supported by investment grade credit ratings on EPO’s long-term senior unsecured debt of BBB+, Baa1 and BBB+ from Standard & Poors, Moody’s and Fitch, respectively.
Recent Developments

Enterprise and Chevron Explore Carbon Storage Business Opportunities

In September 2021, we and Chevron U.S.A. Inc. (“Chevron”) jointly announced a framework to study and evaluate opportunities for carbon dioxide capture, utilization and storage from our respective business operations in the U.S. Midcontinent and Gulf Coast. Projects resulting from this evaluation would seek to combine our extensive midstream pipeline and storage network with Chevron’s sub-surface expertise to create opportunities to capture, aggregate, transport and sequester carbon dioxide in support of the evolving energy landscape. The initial phase of the study in which we will evaluate specific business opportunities is expected to last about six months.

Issuance of $1.0 Billion of Senior Notes in September 2021

In September 2021, EPO successfully issued $4.25$1.0 billion in principal amount of senior notes indue February 2053 (“Senior Notes EEE”).   Net proceeds from this offering will be used for general company purposes, including for growth capital investments, and the first nine monthsrepayment of 2020.  Based on current conditions, we believe that we will have sufficient liquidity and/or access to debt capital markets to fund(including the remainingrepayment of a portion of our $750.0 million in principal amount of 3.50% Senior Notes VV and/or a portion of our $650.0 million in principal amount of 4.05% Senior Notes CC, in each case at their maturity in February 2022).

Senior Notes EEE were issued at 99.170% of their principal amount and have a fixed rate of interest of 3.30% per year.  The Partnership guaranteed these senior notes maturing through 2021.an unconditional guarantee on an unsecured and unsubordinated basis.

•
In light of the current downturn in the domestic energy industry, we reevaluated our planned capital investments.  Based on information currently available, we now expect our total capital investments for 2020, net of contributions from joint venture partners, to approximate $3.2 billion (originally forecast in our 2019 Form 10-K at $3.4 billion to $4.4 billion), which reflects growth capital investments of $2.9 billion and approximately $300 million for sustaining capital expenditures.  In addition, we currently expect our growth capital investments in 2021 and 2022 for sanctioned projects to approximate $1.6 billion and $800 million, respectively. These amounts do not include capital investments associated with our proposed deepwater offshore crude oil terminal (the Sea Port Oil Terminal or “SPOT”), which remains subject to governmental approvals.  We do not expect to receive the approvals for SPOT in 2020.
Enterprise and Magellan Team Up With Intercontinental Exchange for New Houston Crude Oil Futures Contract

•
We continue to optimize our assets to provide incremental services to customers and to respond to market opportunities. In June 2021, we, Magellan Midstream Partners, L.P (“Magellan”) and Intercontinental Exchange, Inc. (“ICE”) announced the establishment of a new futures contract for the physical delivery of crude oil in the Houston, Texas area in response to market interest for a Houston-based index with greater scale, flow assurance and price transparency. It will utilize the capabilities and global reach of ICE’s industry-recognized, state-of-the-art trading platform and is due to be launched by ICE by early 2022, subject to regulatory approval.As prices for certain NGLs, crude oil and refined products fell in 2020 due to collapsing demand for refined products as a result of the pandemic, our storage services provided valuable flexibility for our customers. In addition, our earnings from marketing activities for the nine months ended September 30, 2020 benefited from using uncontracted storage capacity to capture contango opportunities in NGLs, crude oil and refined products.

The quality specifications of the new futures contract will be consistent with WTI originating from the Permian Basin with common delivery options at either our ECHO terminal in Houston or Magellan’s East Houston terminal. In support of this new futures contract, we and Magellan expect to discontinue provisions for delivery services under legacy futures contracts that are deliverable at each terminal once the new futures contract is finalized and receives regulatory approval.
Across all
Enterprise to Increase Its Use of Power from Renewable Resources

In March 2021, we announced the execution of a power purchase agreement with EDF Renewables North America that will increase our use of electricity from solar power by 100 MWac/132 MWdc.  We are committed to being a responsible steward of the environment, including using energy sustainably across our footprint.  We estimate that by 2025, approximately 25% of our assets, we have contracted with a large number of quality customers in order to achieve customer diversification. In 2019, our top 200 largest customers represented 96% of consolidated revenues.  Based on their respective year-end 2019 debt ratings, 81% of our top 200 customers were either investment grade rated or backed by letters of credit.  Additionally, only 6% of our top 200 customer revenues were attributable to sub-investment grade or non-rated upstream producers. Given the current market environment, the rating agencies have taken numerous rating actions, including downgrades, across the energy industry.  After adjusting for all ratings actions through April 23, 2020, we estimate that 78% of our top 200 customers remain investment grade rated or are backed by letters of credit.power will be from renewable resources.


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In light of current events, we are closely monitoring the recoverability of our long-lived assets for potential impairment. We recognized $77.0 million and $90.4 million of non-cash asset impairment charges during the three and nine months ended September 30, 2020, respectively. If the adverse economic impacts of the pandemic persist for longer periods than currently expected, these developments could result in our recognition of additional non-cash impairment charges in the future.

Significant Recent Commercial Developments

Expansion of Midland-to-ECHO System Enters Service

In July 2019, we announced an expansion of our Midland-to-ECHO System comprised of a 36-inch pipeline extending from Midland, Texas to our Enterprise Crude Houston (“ECHO”) terminal, and further from ECHO to a third-party terminal in Webster, Texas (collectively, the “Midland-to-Webster pipeline”).  In October 2020, we announced that the Midland-to-ECHO segment was placed into service.   We expect the ECHO-to-Webster segment to enter service in the fourth quarter of 2020.  Once all facilities are placed into full commercial service, our transportation capacity on the pipeline is expected to be approximately 450 MBPD.  We proportionately consolidate a 29% undivided interest in the Midland-to-Webster pipeline, which we refer to as the “Midland-to-ECHO 3” pipeline.

Amendments to Crude Oil Transportation Agreements; Cancellation of Midland-to-ECHO 4 Pipeline

In September 2020, we announced the amendment of certain crude oil transportation agreements and the related cancellation of the Midland-to-ECHO 4 pipeline. In general, the amendments provide for the reduction of near-term pipeline volume commitments in exchange for extending the term of the related transportation agreements and using existing pipeline infrastructure. Cancellation of the Midland-to-ECHO 4 pipeline reduced our growth capital investments by an aggregate $800 million over the years 2020 through 2022.  As a result of the cancellation, we recorded an impairment charge of $42.0 million during the third quarter of 2020.

Enterprise Co-Loads Export Vessels at Houston Ship Channel Terminals

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

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

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

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

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

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

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

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)
2019 by quarter:        
2020 by quarter:        
1st Quarter$3.15$0.30$0.67$0.82$0.85$1.16$0.38$0.24$0.31$1.95$0.14$0.37$0.57$0.63$0.93$0.31$0.18$0.19
2nd Quarter$2.64$0.21$0.55$0.63$0.65$1.21$0.37$0.24$0.25$1.71$0.19$0.41$0.43$0.44$0.41$0.26$0.11$0.17
3rd Quarter$2.23$0.17$0.44$0.51$0.66$1.06$0.38$0.23$0.21$1.98$0.22$0.50$0.58$0.60$0.80$0.35$0.17$0.25
4th Quarter$2.50$0.19$0.50$0.68$0.82$1.20$0.35$0.21$0.25$2.67$0.21$0.57$0.76$0.68$0.92$0.41$0.24$0.22
2019 Averages$2.63$0.22$0.54$0.66$0.75$1.16$0.37$0.23$0.26
2020 Averages$2.08$0.19$0.46$0.59$0.77$0.33$0.18$0.21
                
2020 by quarter:        
2021 by quarter:        
1st Quarter$1.95$0.14$0.37$0.57$0.63$0.93$0.31$0.18$0.19$2.71$0.24$0.89$0.94$0.93$1.33$0.73$0.44$0.38
2nd Quarter$1.71$0.19$0.41$0.43$0.44$0.41$0.26$0.11$0.17$2.83$0.26$0.87$0.97$0.98$1.46$0.67$0.27$0.41
3rd Quarter$1.98$0.22$0.50$0.58$0.60$0.80$0.35$0.17$0.25$4.02$0.35$1.16$1.34$1.62$0.82$0.36$0.51
2020 Averages$1.88$0.18$0.43$0.53$0.56$0.71$0.31$0.15$0.20
2021 Averages$3.19$0.28$0.98$1.09$1.08$1.47$0.74$0.36$0.43

(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,S&P Global, 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.Service (“OPIS”) by IHS Markit (“IHS”).
(3)Polymer grade propylene prices represent average contract pricing for such product as reported by IHS Chemical, a division of IHS Inc. (“IHS Chemical”).IHS.  Refinery grade propylene (“RGP”) prices represent weighted-average spot prices for such product as reported by IHS Chemical.IHS.
(4)The “Indicative Gas Processing Gross Spread” represents aour generic estimate of the gross economic benefit from extracting NGLs from natural gas production based on certain pricing assumptions.  Specifically, it is the amount by which the assumed economic value of a composite gallon of NGLs at Mont Belvieu, Texas exceeds the value of the equivalent amount of energy in natural gas at Henry Hub, Louisiana (as presented inLouisiana. Our estimate of the table above). The indicative spread does not consider the operating costs incurred by a natural gas processing facility to extract the NGLs nor the transportation and fractionation costs to deliver the NGLs to market.   In addition, the actual gas processing spread earned at each plant is determinedfurther influenced by regional pricing and extraction dynamics.   As presented in the table above, the indicative spread assumes that a gallon of NGLs is comprised of 47% ethane, 28% propane, 9% normal butane, 6% isobutane and 10% natural gasoline.  The value of an equivalent amount of energy in natural gas to one gallon of NGLs is assumed to be 8.4% of the price of a MMBtu of natural gas at Henry Hub.

The weighted-average indicative market price for NGLs was $0.41 $0.84 per gallon in the third quarter of 20202021 versus $0.39$0.41 per gallon duringin the third quarter of 2019.  2020.  Likewise, the weighted-average indicative market price for NGLs was $0.360.70 per gallon during the nine months ended September 30, 20202021 compared to $0.48$0.36 per gallon during the same period in 2019.2020.









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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)
2019 by quarter: 
1st Quarter$54.90$53.70$61.19$62.35
2nd Quarter$59.81$57.62$66.47$67.07
3rd Quarter$56.45$56.12$59.75$60.64
4th Quarter$56.96$57.80$60.04 $60.76
2019 Averages$57.03$56.31$61.86$62.71
 (1)(2)(3)
2020 by quarter:  
1st Quarter$46.17$45.51$47.81$48.15$46.17$45.51$47.81$48.15
2nd Quarter$27.85$28.22$29.68$30.12$27.85$28.22$29.68$30.12
3rd Quarter$40.93$41.05$41.77 $42.47$40.93$41.05$41.77 $42.47
4th Quarter$42.66$43.07$43.63 $44.08
2020 Averages$38.32$38.26$39.75$40.25$39.40$39.46$40.72$41.21
 
2021 by quarter: 
1st Quarter$57.84$59.00$59.51 $59.99
2nd Quarter$66.07$66.41$66.90 $67.95
3rd Quarter$70.56$70.74$71.17$71.51
2021 Averages$64.82$65.38$65.86$66.48

(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
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Table of 2020 is attributable to the ongoing effects of the COVID-19 pandemic and, with respect to crude oil, the production dispute between Saudi Arabia and Russia.  See “Current Outlook” within this Part I, Item 2 for information regarding these events.Contents

Fluctuations in our consolidated revenues and cost of sales amounts are explained in large part by changes in energy commodity prices. A decreaseAn increase in our consolidated marketing revenues due to lowerhigher energy commodity sales prices may not result in a decreasean increase in gross operating margin or cash available for distribution, since our consolidated cost of sales amounts would also decreasebe expected to increase due to comparable decreasesincreases in the purchase prices of the underlying energy commodities.  The same type of correlationrelationship would be true in the case of higherlower energy commodity sales prices and purchase costs.

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



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Income Statement Highlights

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

 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
 2020  2019  2020  2019  2021  2020  2021  2020 
Revenues $6,922.0  $7,964.1  $20,155.5  $24,783.9  $10,831.3  $6,922.0  $29,436.7  $20,155.5 
Costs and expenses:                                
Operating costs and expenses:                                
Cost of sales  4,313.7   5,276.5   12,331.9   16,721.5   8,112.8   4,313.7   21,215.8   12,331.9 
Other operating costs and expenses  696.9   790.8   2,120.4   2,243.4   757.3   696.9   2,174.2   2,120.4 
Depreciation, amortization and accretion expenses  484.2   467.1   1,461.3   1,380.8   511.3   484.2   1,516.9   1,461.3 
Net gains attributable to asset sales  (0.6)  (0.1)  (2.1)  (2.6)
Asset impairment and related charges  77.0   39.4   90.4   51.2 
Asset impairment charges  29.3   77.0   112.7   90.4 
Net losses (gains) attributable to asset sales and related matters  (2.2)  (0.6)  9.0   (2.1)
Total operating costs and expenses  5,571.2   6,573.7   16,001.9   20,394.3   9,408.5   5,571.2   25,028.6   16,001.9 
General and administrative costs  50.3   55.5   162.8   160.2   47.3   50.3   155.1   162.8 
Total costs and expenses  5,621.5   6,629.2   16,164.7   20,554.5   9,455.8   5,621.5   25,183.7   16,164.7 
Equity in income of unconsolidated affiliates  82.0   139.3   336.1   431.3   137.6   82.0   447.2   336.1 
Operating income  1,382.5   1,474.2   4,326.9   4,660.7   1,513.1   1,382.5   4,700.2   4,326.9 
Other income (expense):                
Interest expense  (320.5)  (382.9)  (958.2)  (950.2)  (315.9)  (320.5)  (954.8)  (958.2)
Change in fair value of Liquidity Option  –   (38.7)  (2.3)  (123.1)
Other, net  2.9   7.6   14.8   11.7   1.0   2.9   2.6   12.5 
Total other expense, net  (314.9)  (317.6)  (952.2)  (945.7)
Income before income taxes  1,198.2   1,064.9   3,748.0   3,381.2 
Benefit from (provision for) income taxes  19.1   (15.4)  138.6   (37.4)  (16.1)  19.1   (57.3)  138.6 
Net income  1,084.0   1,044.8   3,519.8   3,561.7   1,182.1   1,084.0   3,690.7   3,519.8 
Net income attributable to noncontrolling interests  (31.4)  (25.6)  (82.4)  (67.3)  (28.3)  (31.4)  (82.3)  (82.4)
Net income attributable to preferred units  *   –   *   –   (0.8)  *   (2.7)  * 
Net income attributable to common unitholders $1,052.6  $1,019.2  $3,437.4  $3,494.4  $1,153.0  $1,052.6  $3,605.7  $3,437.4 
                                
* Amount is negligible                                









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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,
 
  2020  2019  2020  2019 
NGL Pipelines & Services:            
Sales of NGLs and related products $2,048.4  $2,624.9  $6,401.7  $7,955.5 
Midstream services  565.6   627.2   1,656.7   1,895.7 
Total  2,614.0   3,252.1   8,058.4   9,851.2 
Crude Oil Pipelines & Services:                
    Sales of crude oil  1,216.1   2,130.0   4,059.7   6,990.1 
    Midstream services  305.5   348.3   964.0   962.1 
        Total  1,521.6   2,478.3   5,023.7   7,952.2 
Natural Gas Pipelines & Services:                
    Sales of natural gas  350.7   440.0   1,097.6   1,627.1 
    Midstream services  256.2   275.5   765.1   835.2 
       Total  606.9   715.5   1,862.7   2,462.3 
Petrochemical & Refined Products Services:                
    Sales of petrochemicals and refined products  1,966.2   1,299.0   4,593.7   3,867.3 
    Midstream services  213.3   219.2   617.0   650.9 
       Total  2,179.5   1,518.2   5,210.7   4,518.2 
Total consolidated revenues $6,922.0  $7,964.1  $20,155.5  $24,783.9 

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For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2021  2020  2021  2020 
NGL Pipelines & Services:            
Sales of NGLs and related products $3,169.6  $2,048.4  $9,151.0  $6,401.7 
Midstream services  647.0   565.6   1,836.2   1,656.7 
Total  3,816.6   2,614.0   10,987.2   8,058.4 
Crude Oil Pipelines & Services:                
    Sales of crude oil  2,890.0   1,216.1   6,868.2   4,059.7 
    Midstream services  344.6   305.5   1,035.4   964.0 
        Total  3,234.6   1,521.6   7,903.6   5,023.7 
Natural Gas Pipelines & Services:                
    Sales of natural gas  732.2   350.7   2,543.1   1,097.6 
    Midstream services  247.7   256.2   732.7   765.1 
       Total  979.9   606.9   3,275.8   1,862.7 
Petrochemical & Refined Products Services:                
    Sales of petrochemicals and refined products  2,537.8   1,966.2   6,523.6   4,593.7 
    Midstream services  262.4   213.3   746.5   617.0 
       Total  2,800.2   2,179.5   7,270.1   5,210.7 
Total consolidated revenues $10,831.3  $6,922.0  $29,436.7  $20,155.5 

Third Quarter of 20202021 Compared to Third Quarter of 20192020.  Total revenues for the third quarter of 2020 decreased $1.042021 increased $3.91 billion when compared to the third quarter of 20192020 primarily due to a net $912.5 million decrease$3.75 billion increase in marketing revenues.  Revenues from the marketing of NGLs and crude oil and natural gas decreased $1.0increased a combined $2.8 billion quarter-to-quarter primarily due to lowerhigher average sales prices, which accounted for a $935.0 million decrease,$2.16 billion increase, and lowerhigher sales volumes, which accounted for an additional $68.2$636.9 million decrease.increase.  Revenues from the marketing of NGLs decreased $576.5natural gas, petrochemicals and refined products increased a combined net $953.2 million quarter-to-quarter primarily due to lowerhigher average sales prices, which accounted for a $504.8 million decrease, and$2.13 billion increase, partially offset by lower sales volumes, which resulted in an additional $71.7 million decrease.  Revenues from the marketing of petrochemicals and refined products increased a net $667.2 million quarter-to-quarter primarily due to higher sales volumes, which accounted for a $982.3 million increase, partially offset by lower average sales prices, which resulted in a $315.1 million$1.18 billion decrease.

Revenues from midstream services for the third quarter of 2020 decreased2021 increased $161.1129.6 million when compared to the third quarter of 2019.2020.  Revenues from our terminal facilities increased $58.2 million quarter-to-quarter primarily due to higher deficiency fee revenue.  Revenues from our natural gas processing facilities decreased $54.8increased $46.2 million quarter-to-quarter primarily due to lower market values for the equity NGLs we receive as non-cash consideration for processing services.  Revenues from our pipeline assets decreased $43.7 million quarter-to-quarter primarily due to lower demand for crude oil, natural gas and refined products transportation services.  Lastly, third-party revenues from our Mont Belvieu NGL fractionation complex decreased $19.5 million quarter-to-quarter primarily due to lower fractionation fees.

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019.  Total revenues for the nine months ended September 30, 2020 decreased $4.63 billion when compared to the nine months ended September 30, 2019 primarily due to a net $4.29 billion decrease in marketing revenues.  Revenues from the marketing of crude oil and natural gas decreased $3.46 billion period-to-period primarily due to lower average sales prices, which accounted for a $2.73 billion decrease, and lower sales volumes, which accounted for an additional $728.5 million decrease.  Revenues from the marketing of NGLs decreased a net $1.55 billion period-to-period primarily due to lower average sales prices, which accounted for a $2.56 billion decrease, partially offset by the effects of higher sales volumes, which resulted in a $1.0 billion increase.  Revenues from the marketing of petrochemicals and refined products increased a net $726.4 million period-to-period primarily due to higher sales volumes, which accounted for a $1.69 billion increase, partially offset by lower average sales prices, which resulted in a $965.8 million decrease.

Revenues from midstream services for the nine months ended September 30, 2020 decreased $341.1 million when compared to the nine months ended September 30, 2019.  Revenues from our natural gas processing facilities decreased $176.9 million period-to-period primarily due to lower market values for the equity NGLs we receive as non-cash consideration for processing services.  Revenues from our Midland-to-ECHO 2crude oil pipeline which commenced limited service in February 2019 and full service in April 2019,assets increased $17.8$43.6 million period-to-period.quarter-to-quarter, primarily due to higher demand for crude oil transportation services.  Revenues from our other pipeline assets decreased $107.3propylene production facilities increased $22.0 million period-to-periodquarter-to-quarter primarily due to higher processing fees.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020.  Total revenues for the nine months ended September 30, 2021 increased $9.28 billion when compared to the nine months ended September 30, 2020 primarily due to an $8.93 billion increase in marketing revenues.  Revenues from the marketing of NGLs, natural gas, petrochemicals and refined products increased a combined net $6.12 billion period-to-period primarily due to higher average sales prices, which accounted for a $7.85 billion increase, partially offset by lower demandsales volumes, which accounted for a $1.73 billion decrease.  Revenues from the marketing of crude oil natural gasincreased $2.81 billion period-to-period primarily due to higher average sales prices, which accounted for a $1.8 billion increase, and refined products.  Lastly, third party revenueshigher sales volumes, which accounted for an additional $1.01 billion increase.

Revenues from midstream services for the nine months ended September 30, 2021 increased $348.0 million when compared to the nine months ended September 30, 2020.  Revenues from our Mont Belvieu NGL fractionation complex decreased $84.1terminal facilities increased $110.8 million period-to-period primarily due to lower fractionationhigher deficiency fee revenue.  Revenues from our natural gas processing facilities increased $104.5 million period-to-period primarily due to higher market values for the equity NGLs we receive as non-cash consideration for processing services.  Revenues from our crude oil pipeline assets increased $87.9 million period-to-period, primarily due to higher demand for crude oil transportation services.  Revenues from our propylene production facilities increased $73.9 million period-to-period primarily due to higher processing fees.
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Operating costs and expenses

Third Quarter of 2020 Compared to Third Quarter of 2019.  Total operating costs and expenses for the three and nine months ended September 30, 2021 increased $3.84 billion and $9.03 billion, respectively, when compared to the same periods in 2020.

Cost of sales
Third Quarter of 2021 Compared to Third Quarter of 2020.  Cost of sales for the third quarter of 2020 decreased $1.0 2021 increased $3.8 billion when compared to the third quarter of 20192020. The cost of sales associated with our marketing of NGLs and crude oil increased a combined $3.19 billion quarter-to-quarter primarily due to lowerhigher average purchase prices, which accounted for a $2.6 billion increase, and higher sales volumes, which accounted for an additional $586.0 million increase.  The cost of sales.sales associated with our marketing of natural gas, petrochemicals and refined products increased a combined net $611.1 million quarter-to-quarter primarily due to higher average purchase prices, which accounted for a $1.74 billion increase, partially offset by lower sales volumes, which accounted for a $1.13 billion decrease.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020.  Cost of sales for the nine months ended September 30, 2021 increased $8.88billion when compared to the nine months ended September 30, 2020.  The cost of sales associated with our marketing of NGLs, natural gas, petrochemicals and refined products increased a combined net $5.58 billion period-to-period primarily due to higher average purchase prices, which accounted for a $7.0 billion increase, partially offset by lower sales volumes, which accounted for a $1.42 billion decrease.  The cost of sales associated with our marketing of crude oil and natural gas decreased a combined $986.2 million quarter-to-quarterincreased $3.3 billion period-to-period primarily due to lowerhigher average purchase prices, which accounted for a $942.1 million decrease,$2.37 billion increase, and lowerhigher sales volumes, which accounted for an additional $44.1$930.5 million decrease.  The cost of sales associated with our marketing of NGLs decreased $564.4 million quarter-to-quarter primarily due to lower average purchase prices, which accounted for a $505.0 million decrease,increase.

Other operating costs and lower sales volumes, which accounted for an additional $59.4 million decrease.  The cost of sales associated with our marketing of petrochemicals and refined products increased a net $587.8 million quarter-to-quarter primarily due to higher sales volumes, which accounted for an $897.8 million increase, partially offset by lower average purchase prices, which accounted for a $310.0 million decrease.

expenses
Other operating costs and expenses for the third quarter of 2020 decreased $93.92021 increased $60.4 million quarter-to-quarterwhen compared to the third quarter of 2020 primarily due to lowerhigher maintenance chemical and power-related expenses.  utility costs, ad valorem taxes, and costs attributable to new assets placed into service during or since the respective quarter in 2020.  Other operating costs and expenses for the nine months ended September 30, 2021 increased $53.8 million when compared to the nine months ended September 30, 2020 primarily due to higher maintenance and employee compensation costs, ad valorem taxes, and costs attributable to new assets placed into service during or since the respective period in 2020.

Depreciation, amortization and accretion expenses
Depreciation, amortization and accretion expense for the three and nine months ended September 30, 2021 increased $17.1a combined $27.1 million and $55.6 million, respectively, when compared to the same periods in 2020.  The quarter-to-quarter and period-to-period increases are primarily due to assets placed into full or limited service since the third quarter of 2019 (e.g., the isobutane dehydrogenation (“iBDH”) plant, Mentone facility, Mont BelvieuChambers County Frac X and XI, and the Enterprise Navigator ethylene terminal).  Midland-to-ECHO 3 pipeline) since the end of the respective periods in 2020 and major maintenance activities accounted for under the deferral method.

Under the deferral method, major maintenance costs are capitalized and amortized over the period until the next major overhaul project. We adopted the deferral method for our reaction-based plants in November 2020.

Asset impairment charges
Non-cash asset impairment charges for the three and nine months ended September 30, 2021 decreased $47.7 million and increased $37.6$22.3 million, quarter-to-quarter primarilyrespectively, when compared to the same periods in 2020.  We recorded non-cash impairment charges of $44.3 million during the nine months ended September 30, 2021 due to the sale of a coal bed natural gas gathering system and the related Val Verde treating facility, both of which were components of our San Juan Gathering System.  The remainder of our asset impairment charges for the three and nine months ended September 30, 2021 and 2020 are attributable to the write-off of assets that are no longer expected to be used or constructed, including the cancellation of the Midland-to-ECHO 4 crude oil pipeline construction project.project in September 2020.

We are closely monitoring the recoverability of our long-lived assets, investments in unconsolidated affiliates and goodwill in light of the adverse economic effects of the COVID-19 pandemic.  If the adverse economic impacts of the pandemic persist for longer periods than currently expected, these developments could result in the recognition of non-cash impairment charges in the future.


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Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019.  Total operating costs and expenses for the nine months ended September 30, 2020 decreased $4.39 billion when compared to the nine months ended September 30, 2019 primarily due to lower cost of sales.  The cost of sales associated with our marketing of crude oil and natural gas decreased a combined $3.2 billion period-to-period primarily due to lower average purchase prices, which accounted for a $2.67 billion decrease, and lower sales volumes, which accounted for an additional $524.3 million decrease.  The cost of sales associated with our marketing of NGLs decreased a net $1.82 billion period-to-period primarily due to lower average purchase prices, which accounted for a $2.63 billion decrease, partially offset by higher sales volumes, which accounted for an $809.9 million increase. The cost of sales associated with our marketing of petrochemicals and refined products increased a net $628.4 million period-to-period primarily due to higher sales volumes, which accounted for a $1.55 billion increase, partially offset by lower average purchase prices, which accounted for a $921.1 million decrease.

Other operating costs and expenses for the nine months ended September 30, 2020 decreased $123.0 million period-to-period primarily due to lower maintenance, chemicals and power-related expenses, which accounted for a $191.7 million decrease, partially offset by higher ad valorem taxes and employee compensation costs, which accounted for a $52.3 million increase.  Depreciation, amortization and accretion expense increased $80.5 million period-to-period primarily due to assets placed into full or limited service since the first quarter of 2019 (e.g., the iBDH plant, Mentone and Orla facilities, Mont Belvieu Frac X and the Enterprise Navigator ethylene terminal).  Non-cash asset impairment charges increased $39.2 million period-to-period primarily due to our cancellation of the Midland-to-ECHO 4 crude oil pipeline construction project.

General and administrative costs

General and administrative costs for the three and nine months ended September 30, 2021 decreased $5.2$3.0 million quarter-to-quarterand $7.7 million, respectively, when compared to the same periods in 2020 primarily due to lower employee compensation expenses and legal and other professional services costs.

General and administrative costs increased $2.6 million period-to-period primarily due to higher professional services costs.

Equity in income of unconsolidated affiliates

Equity income from our unconsolidated affiliates for the three and nine months ended September 30, 2020 decreased $57.3 2021 increased $55.6 million and $95.2 $111.1 million, respectively, when compared to the same periods in 20192020 primarily due to decreasedhigher earnings from our investments in crude oil pipelines.

Operating income

Operating income for the three and nine months ended September 30, 2020 decreased $91.7 2021 increased $130.6 million and $333.8 million,$373.3 million, respectively, when compared to the same periods in 20192020 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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changes.

Interest expense

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

 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
 2020  2019  2020  2019  2021  2020  2021  2020 
Interest charged on debt principal outstanding $334.9  $319.3  $1,000.4  $934.2  $322.1  $334.9  $969.8  $1,000.4 
Impact of interest rate hedging program, including related amortization (1)  9.9   90.3   29.2   97.9   10.2   9.9   29.0   29.2 
Interest costs capitalized in connection with construction projects (2)(1)  (34.5)  (33.9)  (96.9)  (102.9)  (23.0)  (34.5)  (63.8)  (96.9)
Other (3)(2)  10.2   7.2   25.5   21.0   6.6   10.2   19.8   25.5 
Total $320.5  $382.9  $958.2  $950.2  $315.9  $320.5  $954.8  $958.2 

(1)Amounts presented for the three and nine months ended September 30, 2019 reflect an unrealized, mark-to-market loss of $94.9 million recognized in September 2019 in connection with the exercise of swaptions.  Due to declining interest rates, the counterparties to the swaptions exercised their right to put us into ten forward-starting swaps on September 30, 2019 having an aggregate notional value of $1.0 billion. Since the swaptions were not designated as hedging instruments and were subject to mark-to-market accounting, we incurred an unrealized, mark-to-market loss at inception of the forward-starting swaps that is reflected as an increase in interest expense for the three and nine months ended September 30, 2019.
(2)We capitalize interest costs incurred on funds used to construct property, plant and equipment while the asset is in its construction phase.  Capitalized interest amounts become part of the historical cost of an asset and are charged to earnings (as a component of depreciation expense) on a straight-line basis over the estimated useful life of the asset once the asset enters its intended service.  When capitalized interest is recorded, it reduces interest expense from what it would be otherwise.  Capitalized interest amounts fluctuate based on the timing of when projects are placed into service, our capital investment levels and the interest rates charged on borrowings.
(3)(2)Primarily reflects facility commitment fees charged in connection with our revolving credit facilities and amortization of debt issuance costs.

Interest charged on debt principal outstanding, which is a key driver of interest expense, increased a net decreased $12.8$15.6 million quarter-to-quarter primarily due to increasedlower debt principal amounts outstanding during the third quarter of 2020, which accounted for a $22.1 million increase, partially offset by the effect of lower overall interest rates during the third quarter of 2020, which accounted for a $6.5 million decrease.2021.  Our weighted-average debt principal balance for the third quarter of 20202021 was $29.07$30.27 billion compared to $27.93$30.27 billion for the third quarter of 2019.  In general, our debt principal balances have increased over time due to the partial debt financing of our capital investments.2020.

For the nine months ended September 30, 2020,2021, interest charged on debt principal outstanding increased a net $66.2 decreased $30.6 million period-to-period primarily due to increasedlower debt principal amounts outstanding during the nine months ended September 30, 2020,2021, which accounted for an $84.2 $21.8 million increase, partially offset bydecrease, and the effecteffects of lower overall interest rates during the nine months ended September 30, 2020,2021, which accounted for an $18.0 additional $8.8 million decrease.  Our weighted-average debt principal balance for the nine months ended September 30, 20202021 was $29.38 billion compared to $29.84 billion compared to $27.29 billion for the nine months ended September 30, 2019.2020.

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




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Change in fair value of Liquidity Option

On February 25, 2020, the Partnership received notice from Marquard & Bahls AG (“M&B”) of M&B’s election to exercise its rights (the “Liquidity Option”) under the Liquidity Option Agreement among the Partnership, OTA Holdings, Inc., a Delaware corporation previously named Oiltanking Holding Americas, Inc. (“OTA”), and M&B dated October 1, 2014 (the “Liquidity Option Agreement”).  The Partnership settled its obligations under the Liquidity Option Agreement on March 5, 2020.

For the period in which the Liquidity Option was outstanding, we recognized non-cash expense in connection with accretion and changes in management estimates that affected the valuation of the Liquidity Option liability.  Expense amounts attributable to changes in the fair value of the Liquidity Option were $38.7 million and $123.1 million during the three and nine months ended September 30, 2019, respectively.  Expense of $2.3 million for the first quarter of 2020 primarily reflects accretion expense for the period in which the Liquidity Option liability was outstanding before it was settled on March 5, 2020.  The higher level of expense recognized in the three and nine months ended September 30, 2019 was primarily due to a decrease in the discount factor used in determining the present value of the liability.

Income taxes

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

 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
 2020  2019  2020  2019  2021  2020  2021  2020 
Deferred tax benefit (expense) attributable to OTA $21.3     $158.0     $(6.8) $21.3  $(20.1) $158.0 
Texas Margin Tax  (7.2) $(15.5)  (21.9) $(36.5)
Revised Texas Franchise Tax (“Texas Margin Tax”)  (9.6)  (7.2)  (37.0)  (21.9)
Other  5.0   0.1   2.5   (0.9)  0.3   5.0   (0.2)  2.5 
Benefit from (provision for) income taxes $19.1  $(15.4) $138.6  $(37.4) $(16.1) $19.1  $(57.3) $138.6 

On March 5,February 25, 2020, we received notice from Marquard & Bahls AG (“M&B”) of its election to exercise its rights  under the Liquidity Option Agreement among the Partnership, OTA Holdings, Inc. (a Delaware corporation previously named Oiltanking Holding Americas, Inc. (“OTA”)), and M&B dated October 1, 2014 (the “Liquidity Option Agreement”).  The Partnership settled its obligations under the Liquidity Option Agreement on March 5, 2020 and indirectly assumed the deferred tax liability of OTA, which reflects OTA’s outside basis difference in the limited partner interests it received from the Partnership in October 2014.

At March 5, 2020, the Partnership’s liability recognized in connection with the Liquidity Option Agreement was $511.9 million (referred to as the “Liquidity Option liability”).  Upon settlement of the Liquidity Option Agreement, the Liquidity Option liability was effectively replaced by the deferred tax liability of OTA calculated in accordance with ASC 740, Income Taxes.

At March 5, 2020, the Liquidity Option liability amount was $511.9 million.  Since the book value of the Liquidity Option liability exceeded OTA’s estimated deferred tax liability of $439.7 million on that date, we recognized a non-cash benefit in earnings of $72.2 million, which is reflected in the “Benefit from (provision for) income tax”taxes” line on our Unaudited Condensed Statement of Consolidated Operations for the nine months ended September 30, 2020. Subsequent to March 5, 2020 and through September 30, 2020, OTA recognized an additional net, non-cash deferred income tax benefit of $85.8 million, due towhich reflected a decrease in the outside basis difference of its investment in the Partnership which in turn was drivencaused by a decline in the market price of Partnershipthe Partnership’s common units sincesubsequent to March 5, 2020 through September 30, 2020.  In total, our earnings for the three and nine months ended September 30, 2020 reflect $21.3$158.0 million and $158.0 million, respectively, of net deferred income tax benefit attributable to OTA.

On September 30, 2020, OTA exchanged the Partnership common units it owned for non-publicly traded preferred units having a stated value of $1,000 per unit.  As a result, and beginning September 30, 2020, OTA’s deferred tax liability no longer fluctuates due to market price changes in the Partnership’sour common units.  For information regarding the issuance of preferred units on September 30, 2020, including the OTA-related exchange, see “Liquidity and Capital Resources” within this Part I, Item 2.

For additional information regarding income taxes, see Note 11 ofIncome tax expense attributable to the NotesTexas Margin Tax increased $2.4 million quarter-to-quarter and $15.1 million period-to-period primarily due to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.




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an increase in the Texas apportionment factor and higher Partnership earnings.

Business Segment Highlights

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

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





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The following table presents gross operating margin by segment and non-generally accepted accounting principle (“non-GAAP”)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 September 30,
  
For the Nine Months
Ended September 30,
 
 2020  2019  2020  2019  2021  2020  2021  2020 
Gross operating margin by segment:                        
NGL Pipelines & Services $1,028.1  $1,008.3  $3,038.2  $2,933.8  $1,022.9  $1,028.1  $3,206.9  $3,038.2 
Crude Oil Pipelines & Services  481.8   496.2   1,569.1   1,671.7   422.9   481.8   1,242.0   1,569.1 
Natural Gas Pipelines & Services  208.4   258.5   701.1   824.6   223.3   208.4   960.5   701.1 
Petrochemical & Refined Products Services  315.0   288.4   785.0   835.9   411.3   315.0   1,019.1   785.0 
Total segment gross operating margin (1)  2,033.3   2,051.4   6,093.4   6,266.0   2,080.4   2,033.3   6,428.5   6,093.4 
Net adjustment for shipper make-up rights  (39.9)  (15.3)  (54.1)  (15.7)  9.8   (39.9)  46.4   (54.1)
Total gross operating margin (non-GAAP) $1,993.4  $2,036.1  $6,039.3  $6,250.3  $2,090.2  $1,993.4  $6,474.9  $6,039.3 

(1)Within the context of this table, total segment gross operating margin represents a subtotal and corresponds to measures similarly titled within our business segment disclosures found under Note 10 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

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

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

 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
 2020  2019  2020  2019  2021  2020  2021  2020 
Operating income $1,382.5  $1,474.2  $4,326.9  $4,660.7  $1,513.1  $1,382.5  $4,700.2  $4,326.9 
Adjustments to reconcile operating income to total gross operating margin
(addition or subtraction indicated by sign):
                                
Depreciation, amortization and accretion expense in operating costs and
expenses
  484.2   467.1   1,461.3   1,380.8 
Asset impairment and related charges in operating costs and expenses  77.0   39.4   90.4   51.2 
Net gains attributable to asset sales in operating costs and expenses  (0.6)  (0.1)  (2.1)  (2.6)
Depreciation, amortization and accretion expense in operating costs
and expenses (1)
  502.7   484.2   1,497.9   1,461.3 
Asset impairment charges in operating costs and expenses  29.3   77.0   112.7   90.4 
Net losses (gains) attributable to asset sales and related matters in operating
costs and expenses
  (2.2)  (0.6)  9.0   (2.1)
General and administrative costs  50.3   55.5   162.8   160.2   47.3   50.3   155.1   162.8 
Total gross operating margin (non-GAAP) $1,993.4  $2,036.1  $6,039.3  $6,250.3  $2,090.2  $1,993.4  $6,474.9  $6,039.3 

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

Each of our business segments benefits from the supporting role of our marketing activities.  The main purpose of our marketing activities is to support the utilization and expansion of assets across our midstream energy asset network by increasing the volumes handled by such assets, which results in additional fee-based earnings for each business segment.  In performing these support roles, our marketing activities also seek to participate in supply and demand opportunities as a supplemental source of gross operating margin for us.  The financial results of our marketing efforts fluctuate due to changes in volumes handled and overall market conditions, which are influenced by current and forward market prices for the products bought and sold.
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Two major winter storms, Uri and Viola, impacted Texas and the southern U.S. in mid-February 2021 (the “February 2021 winter storms”).  The storms had a major impact on the electric power grid in Texas, which resulted in widespread power outages.  Voluntarily and in accordance with our agreements with the Electric Reliability Council of Texas, Inc. (“ERCOT”), we temporarily shut down our non-essential plants and other operations in Texas to support residential power consumption. Those Texas assets that remained operational (e.g., our natural gas processing plants, storage facilities and Texas Intrastate System) were impacted by rolling blackouts.  The economic impacts of these disruptions, higher power and natural gas costs, as well as losses on natural gas hedges, were mitigated by sales of natural gas to electricity generators, natural gas utilities and industrial customers to assist them in meeting their requirements.  During and following the storms, many of our customers also experienced downtime due to freeze-related damage and repairs that impacted our volumes.

Estimated Impact of Hurricane Ida on Results for the Third Quarter of 2021

In late August 2021, southern Louisiana and Mississippi, including its critical energy infrastructure, were impacted by the cumulative effects of Hurricane Ida.  Impacts on the energy industry included, but were not limited to, severe flooding and limited access to facilities, disruptions to offshore production in the Gulf of Mexico, and reduced energy demand from area refineries and petrochemical facilities.  Our plant, pipeline and storage assets in southern Louisiana and Mississippi did not experience significant property damage, and the majority have returned to normal operations.  We expect our volumes impacted by the remaining third-party facility disruptions to return to normal levels as repairs are completed and production is fully restored.

We estimate that Hurricane Ida reduced our gross operating margin for the third quarter of 2021 by approximately $30 million, almost all of which is related to our Louisiana and Mississippi processing, transportation and fractionation assets and related marketing activities, which are a component of our NGL Pipelines & Services segment.  Of this amount, approximately $25 million represents the combined net impact of lower than anticipated volumes and lost business opportunities.  The remaining $5 million represents expenses, net of property damage insurance reimbursements, which we incurred during the quarter in connection with hurricane-related repair and recovery costs.  As a result of the COVID-19 pandemic and lower energy commodity prices,our deductible levels, we experienced a reductiondo not expect any reimbursement from insurance in volumes on a number of our assets (e.g., crude oil pipelines and export docks, natural gas gathering systems) during the three and nine months ended September 30, 2020 due to reduced upstream drilling and production activity and lower downstream refinery activity and demand for transportation fuels. Furthermore, we may continue to experience throughput declines in the future on our gathering systems, long-haul liquids and natural gas pipelines and at our terminal and other facilities until the pandemic ends and economic activity is fully restored.  For a general discussion of the impact of the pandemic on our partnership and industry, see “Current Outlook” within this Part I, Item 2.connection with business interruption claims from Hurricane Ida.

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 September 30,
  
For the Nine Months
Ended September 30,
 
 2020  2019  2020  2019  2021  2020  2021  2020 
Segment gross operating margin:                        
Natural gas processing and related NGL marketing activities $256.8  $288.0  $708.3  $829.3  $263.9  $256.8  $844.2  $708.3 
NGL pipelines, storage and terminals  602.9   593.4   1,862.5   1,739.4   569.6   602.9   1,751.3   1,862.5 
NGL fractionation  168.4   126.9   467.4   365.1   189.4   168.4   611.4   467.4 
Total $1,028.1  $1,008.3  $3,038.2  $2,933.8  $1,022.9  $1,028.1  $3,206.9  $3,038.2 
                                
Selected volumetric data:                                
NGL pipeline transportation volumes (MBPD)  3,446   3,557   3,563   3,532   3,481   3,446   3,389   3,563 
NGL marine terminal volumes (MBPD)  643   602   696   590   664   643   661   696 
NGL fractionation volumes (MBPD)  1,350   1,003   1,357   990   1,254   1,350   1,229   1,357 
Equity NGL production volumes (MBPD) (1)  141   111   156   138   150   141   169   156 
Fee-based natural gas processing volumes (MMcf/d) (2, 3)  4,105   4,724   4,299   4,729 
Fee-based natural gas processing volumes (MMcf/d) (2,3)  3,990   4,105   4,064   4,299 

(1)Represents the NGL volumes we earn and take title to in connection with our processing activities.
(2)Volumes reported correspond to the revenue streams earned by our natural gas processing plants.
(3)Fee-based natural gas processing volumes are measured at either the wellhead or plant inlet in MMcf/d.

Natural gas processing and related NGL marketing activities
Third Quarter of 20202021 Compared to Third Quarter of 20192020.  Gross operating margin from natural gas processing and related NGL marketing activities for the third quarter of 2020 decreased $31.2 2021 increased $7.1 million when compared to the third quarter of 2019.

Gross operating margin from our natural gas processing facilities located in the Rocky Mountains (Meeker, Pioneer and Chaco plants) decreased a combined $23.0 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $27.2 million decrease, and lower processing volumes, which accounted for an additional $8.2 million decrease, partially offset by lower operating costs, which accounted for a $9.0 million increase.  On a combined basis, fee-based natural gas processing volumes at these plants decreased 398 MMcf/d and equity NGL production volumes increased 28 MBPD quarter-to-quarter.

Gross operating margin from our South Texas natural gas processing facilities decreased $22.9 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities), which accounted for an $8.9 million decrease, lower average processing fees, which accounted for a $6.8 million decrease, and lower processing volumes, which accounted for an additional $5.5 million decrease.  On a combined basis, fee-based natural gas processing volumes at our South Texas plants decreased 242 MMcf/d and equity NGL production volumes increased 6 MBPD quarter-to-quarter.

Gross operating margin from our Louisiana and Mississippi natural gas processing facilities decreased $8.1 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 processing volumes, which accounted for an additional $3.9 million decrease.  On a combined basis, fee-based natural gas processing and equity NGL production volumes at our Louisiana and Mississippi plants decreased 374 MMcf/d and 7 MBPD, respectively, quarter-to-quarter (net to our interest).  Certain plants in Louisiana and Mississippi were impacted by lower Gulf of Mexico production as a result of shut-ins associated with Hurricane Laura in August 2020.


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Gross operating margin from our Permian Basin natural gas processing facilities increased a net $5.4 $30.3 million quarter-to-quarter primarily due to higher average processing volumes,margins (including the impact of hedging), which accounted for a $13.4$16.3 million increase, partially offset by lower average processing fees,and higher equity NGL production, which accounted for an additional $11.4 million increase.  Fee-based natural gas processing volumes and equity NGL volumes at these facilities increased 144 MMcf/d and 33 MBPD, respectively, quarter-to-quarter.

Gross operating margin from our Rockies natural gas processing facilities (Meeker, Pioneer and Chaco) increased a $5.8combined $25.9 million decrease, and lowerquarter-to-quarter primarily due to higher average processing margins (including the impact of hedging activities), which accounted for an additional $3.7 million decrease..  On a combined basis, fee-based natural gas processing volumes and equity NGL production at our Permian Basin plants increased 345 these facilities decreased 160 MMcf/d and 18 MBPD, respectively, quarter-to-quarter.

Gross operating margin from our Louisiana and Mississippi natural gas processing facilities increased $12.7 million quarter-to-quarter primarily due to higher average processing margins (including the impact of hedging activities).  Fee-based natural gas processing volumes decreased 70 MMcf/d and equity NGL production increased 3 MBPD, quarter-to-quarter (net to our interest).

Gross operating margin from our South Texas natural gas processing facilities increased a net $4.5 million quarter-to-quarter primarily due to higher average processing margins (including the impact of hedging activities).  Fee-based processing volumes and equity NGL production at our South Texas natural gas processing facilities decreased 3 MMcf/d and 5 MBPD, respectively, quarter-to-quarter.

Gross operating margin from our NGL marketing activities increased a net $16.8 decreased $68.9 million quarter-to-quarter primarily due to higher sales volumes, which accounted for a $36.1 million increase, partially offset by lower average sales margins (including the impact of hedging activities),.  Results from NGL marketing strategies that optimize our transportation, storage, plant and export assets decreased a combined $117.9 million quarter-to-quarter, partially offset by higher earnings from non-cash mark-to-market activities, which accounted for a $19.4$49.0 million decrease. The quarter-to-quarter increase in gross operating margin can be attributed to results from marketing strategies that seek to optimize our storage assets, which accounted for a $68.5 million increase, partially offset by lower earnings from strategies that seek to optimize our export, plant and transportation assets, which accounted for a combined $40.6 million decrease.  In addition, gross operating margin from our NGL marketing activities attributable to non-cash, mark-to-market earnings decreased $11.1 million quarter-to-quarter.increase. 

Nine Months Ended September 30, 20202021 Compared to Nine Months Ended September30, 20192020.  Gross operating margin from natural gas processing and related NGL marketing activities for the nine months ended September 30, 2020 decreased $121.0 2021 increased $135.9 million when compared to the nine months ended September 30, 2019.  Gross operating margin from our Rocky Mountains natural gas processing facilities decreased a combined $80.8 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities).  On a combined basis, fee-based natural gas processing volumes at our plants in the Rockies decreased 305 MMcf/d and equity NGL production volumes increased 6 MBPD period-to-period.2020.  

Gross operating margin from our South Texas natural gas processing facilities decreased $65.5 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $41.4 million decrease, lower average processing fees, which accounted for an $11.0 million decrease, and lower processing volumes, which accounted for an additional $11.2 million decrease.  On a combined basis, fee-based natural gas processing volumes at these plants decreased 141 MMcf/d and equity NGL production volumes increased 7 MBPD period-to-period.

Gross operating margin from our Permian Basin natural gas processing facilities decreased a net $13.8 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $20.9 million decrease, lower average processing fees, which accounted for a $15.4 million decrease, and higher operating costs, which accounted for an additional $9.9 million decrease, partially offset by higher processing volumes, which accounted for a $33.0 million increase.  On a combined basis, fee-based natural gas processing and equity NGL production volumes at our Permian Basin plants increased 287 MMcf/d and 7 MBPD, respectively, period-to-period, primarily due to additional processing capacity at our Orla facility placed into service in July 2019 and the start-up of our Mentone facility in December 2019.

Gross operating margin from our Louisiana and Mississippi natural gas processing facilities decreased a net $20.9 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $22.6 million decrease, and lower processing volumes, which accounted for an additional $10.3 million decrease, partially offset by higher average processing fees, which accounted for a $7.9 million increase, and lower operating costs, which accounted for an additional $6.6 million increase.  Net to our interest, fee-based natural gas processing volumes at these plants decreased a combined 319 MMcf/d period-to-period.

Gross operating margin from our NGL marketing activities increased a net $65.4 $53.0 million period-to-period primarily due to higher sales volumes, which accounted for a $193.7 million increase, partially offset by lower average sales margins (including the impact of hedging activities), which accounted for a $128.2 million decrease. The period-to-period increase in gross operating margin can be attributed to results from marketing strategies that seek to optimize our storage and transportation assets, which accounted for a combined $97.7$70.5 million increase, partially offset by lower earningssales volumes, which accounted for a $15.6 million decrease.  Results from marketing strategies that seek to optimize our export and storage assets decreased a combined $91.6 million period-to-period, partially offset by higher earnings from the optimization of our transportation and plant assets, which accounted for a combined $40.2$66.9 million decrease.increase.  In addition, gross operating margin from our NGL marketing activities attributable to non-cash, mark-to-market earnings increased $7.9$77.7 million period-to-period. 

Gross operating margin from our Permian Basin natural gas processing facilities increased a net $42.8 million period-to-period primarily due to higher fee-based natural gas processing volumes, which accounted for a $29.5 million increase, and higher average processing margins (including the impact of hedging), which accounted for an additional $20.4 million increase, partially offset by higher operating costs, which accounted for a $6.8 million decrease.  Fee-based natural gas processing volumes and equity NGL production at these facilities increased 255 MMcf/d and 29 MBPD, respectively, period-to-period.


Gross operating margin from our Rockies natural gas processing facilities increased a combined net $33.5 million period-to-period primarily due to higher average processing margins (including the impact of hedging activities), which accounted for a $34.5 million increase, and lower operating costs, which accounted for an additional $6.3 million increase, partially offset by lower fee-based natural gas processing volumes, which accounted for a $7.9 million decrease.  On a combined basis, fee-based natural gas processing volumes and equity NGL production at these facilities decreased 268 MMcf/d and 9 MBPD, respectively, period-to-period.


Gross operating margin from our Louisiana and Mississippi natural gas processing facilities increased a net $26.5 million period-to-period primarily due to higher average processing margins (including the impact of hedging activities), which accounted for a $28.9 million increase, and lower operating costs, which accounted for an additional $5.1 million increase, partially offset by lower average processing fees and volumes, which accounted for decreases of $7.7 million and $3.0 million, respectively.  Fee-based natural gas processing volumes decreased 108 MMcf/d period-to-period (net to our interest).
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Gross operating margin from our South Texas natural gas processing facilities decreased a net $22.7 million period-to-period primarily due to lower equity NGL production of 7 MBPD, which accounted for a $47.6 million decrease, and lower average processing fees, which accounted for an additional $38.3 million decrease, partially offset by higher average processing margins (including the impact of hedging activities), which accounted for a $67.9 million period-to-period increase.  Fee-based processing volumes at these facilities decreased 88 MMcf/d period-to-period.

NGL pipelines, storage and terminals
Third Quarter of 20202021 Compared to Third Quarter of 20192020.  Gross operating margin from our NGL pipelines, storage and terminal assets forduring the third quarter of 2020 increased $9.52021 decreased $33.3 million when compared to the third quarter of 2019.2020.

A number of our pipelines, including the Mid-America Pipeline System, Seminole NGL Pipeline, Chaparral NGL Pipeline, and Shin Oak NGL Pipeline, Texas Express Pipeline and Front Range Pipeline, serve Permian Basin and/or Rocky Mountain producers. On a combined basis, gross operating margin from these pipelines increased a net $11.1decreased $30.6 million quarter-to-quarter primarily due to higherlower average transportation fees, which accounted for a $21.9 million decrease, and lower transportation volumes, which accounted for an $18.0additional $7.3 million decrease.  Transportation volumes on these pipelines decreased a combined 10 MBPD quarter-to-quarter (net to our interest).

Gross operating margin at our Morgan’s Point Ethane Export Terminal increased $6.3 million quarter-to-quarter primarily due to an increase in loading volumes of 23 MBPD, which accounted for a $4.3 million increase, and lower operating costs, which accounted for an additional $6.4$2.1 million increase, partially offset byincrease.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020.  Gross operating margin from our NGL pipelines, storage and terminal assets during the nine months ended September 30, 2021 decreased $111.2 million when compared to the nine months ended September 30, 2020.

On a combined basis, gross operating margin from our pipelines that serve Permian Basin and/or Rocky Mountain producers decreased a net $58.9 million period-to-period primarily due to lower transportation volumes of 4373 MBPD (net to our interest), which accounted for a $7.1$54.3 million decrease.decrease, and higher operating costs, which accounted for an additional $23.0 million decrease, partially offset by higher handling fee revenues, which accounted for an $11.6 million increase, and higher average transportation fees, which accounted for an additional $6.8 million increase.

Gross operating margin from LPG-related activities at EHT increased $4.5our Enterprise Hydrocarbons Terminal (“EHT”) decreased $26.0 million quarter-to-quarterperiod-to-period primarily due to higherlower export volumes of 4553 MBPD.  Gross operating margin from our related Houston Ship Channel Pipeline System increased $3.1 decreased $4.9 million quarter-to-quarterperiod-to-period primarily due to a 39 54 MBPD increasedecrease in transportation volumes.

Gross operating margin fromat our Mont Belvieu storage facility decreased a net $7.7Morgan’s Point Ethane Export Terminal increased $7.6 million quarter-to-quarterperiod-to-period primarily due to lower handling and throughput fee revenues, which accounted for an $18.5 million decrease, partially offset by higher storage fees, which accounted for a $13.3 million increase.loading volumes of 18 MBPD.

Gross operating margin from our Dixie Pipeline and related terminals decreased a combined $4.7 million quarter-to-quarter primarily due to lower transportation volumes of 57 MBPD.  Gross operating margin from our South Louisiana NGL Pipeline System and related storage facilities decreased a combined $7.1 million quarter-to-quarter primarily due to lower transportation volumes of 69 MBPD, which accounted for a $4.9 million decrease, and lower loading and other fee revenues, which accounted for an additional $1.3 million decrease.  The decrease in transportation volumes for these pipelines in the third quarter of 2020 was partially due to the effects of Hurricane Laura, which caused shut-ins of Gulf of Mexico production as well as power outages at certain pump stations.

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019.  Gross operating margin from our NGL pipelines, storage and terminal assets for the nine months ended September 30, 2020 increased $123.1 million when compared to the nine months ended September 30, 2019.

On a combined basis, gross operating margin from our pipelines serving Permian Basin and/or Rocky Mountain producers increased a net $63.1$16.8 million period-to-period primarily due to higher average transportation fees,maintenance and other operating costs, which accounted for a $47.1$9.6 million increase,decrease, and lower transportation volumes of 20 MBPD, which accounted for an additional $7.3 million decrease. 

Gross operating margin from our Chambers County storage complex decreased a net $10.2 million period-to-period primarily due to lower throughput fee revenues, which accounted for a $12.0 million decrease, and higher operating costs, which accounted for an additional $26.8 million increase, partially offset by lower transportation volumes, which accounted for a $7.2 million decrease.  Transportation volumes from these pipelines decreased a combined 99 MBPD (net to our interest).

Gross operating margin from LPG-related activities at EHT increased $53.1 million period-to-period primarily due to higher export volumes of 116 MBPD. The increase in export volumes is attributable to an LPG expansion project at EHT that was completed in the third quarter of 2019.  Gross operating margin from our Houston Ship Channel Pipeline System increased $14.9 million period-to-period primarily due to a 92 MBPD increase in transportation volumes.

Gross operating margin from our Aegis Pipeline increased $29.8 million period-to-period primarily due to a 115 MBPD increase in transportation volumes associated with contract commitments.

Gross operating margin from our Mont Belvieu storage facility decreased a net $15.4 million period-to-period primarily due to lower handling and throughput fee revenues, which accounted for a $31.5$15.2 million decrease, partially offset by higher storage fees, which accounted for an $18.4 million increase.

Gross operating margin from our South Louisiana NGL Pipeline System and related storage facilities decreased a combined $15.1 million period-to-period primarily due to lower transportation volumes of 42 MBPD,fee revenues, which accounted for a $6.3$17.0 million decrease, and lower terminal revenues, which accounted for an additional $6.2 million decrease.increase.

Gross operating margin from our South Texas NGL Pipeline System decreased $9.6increased $12.1 million period-to-period primarily due to lowerhigher pipeline capacity fee revenues earned from an affiliate pipeline.  Transportation volumes on our South Texas NGL Pipeline System increased 30decreased 11 MBPD period-to-period.

NGL fractionation
Third Quarter of 2021 Compared to Third Quarter of 2020.  Gross operating margin from NGL fractionation during the third quarter of 2021 increased $21.0 million when compared to the third quarter of 2020.  


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NGL fractionation
Third Quarter of 2020 Compared to Third Quarter of 2019.  Gross operating margin from our Chambers County NGL fractionation for the third quarter of 2020complex increased $41.5 a net $23.6 million when compared to the third quarter of 2019quarter-to-quarter primarily due to higher fractionation volumes, which accounted for a $35.0 million increase, and higher ancillary service revenues, which accounted for an additional $17.1 million increase, partially offset by higher operating costs, which accounted for a $32.8 million decrease.  NGL fractionation volumes at our Mont BelvieuChambers County NGL fractionation complex, which increased includes the average daily operating rates for newly constructed assets from the time the asset was placed into service, decreased 40348 MBPD quarter-to-quarter (net to our interest).  While the average daily operating rate for our Chambers County NGL fractionation complex decreased quarter-to-quarter, total NGL fractionation volumes increased primarily due to the start-upa full quarter of the firstcontributions from Frac XI, which entered service in September 2020.

Gross operating margin from our Norco NGL fractionator decreased $4.9 million quarter-to-quarter primarily due to higher maintenance costs and secondlower fractionation units (“Frac X” and “Frac XI”) in March 2020 and September 2020, respectively,volumes as a result of Hurricane Ida.  NGL fractionation volumes at our newly completedNorco NGL fractionation facility located in Chambers County, Texas.fractionator decreased 22 MBPD quarter-to-quarter.

Nine Months Ended September 30, 20202021 Compared to Nine Months Ended September 30, 20192020.  Gross operating margin from NGL fractionation during the nine months ended September 30, 20202021 increased $102.3$144.0 million when compared to the nine months ended September 30, 2019.  2020.  

Gross operating margin from our Mont BelvieuChambers County NGL fractionation complex increased a net $162.265.4 million period-to-period. This increase was primarily due to higher fractionation volumes, which increased 341 MBPD period-to-period (net to our interest) primarily due to the start-up of Frac Xaccounted for a $107.6 million increase, and Frac XI.  Gross operating margin from our Hobbs NGL fractionator increased $21.3 higher ancillary service revenues, which accounted for an additional $45.6 million period-to-period primarily due to major maintenance activities during the first quarter of 2019.  NGL fractionation volumes at our Hobbs NGL fractionator increased 17 MBPD period-to-period.  Gross operating margin from our South Texas NGL fractionators increased $8.6 million period-to-period primarily due to lower maintenance and otherincrease, partially offset by higher operating costs, which accounted for a $4.4$114.0 million increase, and higherdecrease.  NGL fractionation volumes at our Chambers County NGL fractionation complex, which includes the average daily operating rates for newly constructed assets from the time the asset was placed into service, decreased 55 MBPD period-to-period (net to our interest).  While the average daily operating rate for our Chambers County NGL fractionation complex decreased period-to-period, total NGL fractionation volumes increased primarily due to a full period of contributions from Frac X and Frac XI, which entered service in late March 2020 and September 2020, respectively.

In addition, gross operating margin at our Chambers County NGL fractionation complex increased due to $63.217 million in margins on the optimization of our power supply arrangements and $40.5 million of payments received in connection with our participation in the Texas Load Resources Demand Response Program (“LaaR”) during the February 2021 winter storms.  The amounts earned from optimization activities were based on the settlement of ERCOT prices, which were finalized by the State of Texas during the second quarter of 2021.  The amounts earned from the LaaR program partially compensate us for higher electricity expenses incurred during the storms and for lost revenues resulting from voluntary outages during the storms.

Gross operating margin from our Norco NGL fractionator decreased $16.7 million period-to-period primarily due to higher maintenance costs and lower fractionation volumes as a result of downtime for major maintenance activities during the second quarter of 2021 and Hurricane Ida during the third quarter of 2021.  NGL fractionation volumes at our Norco NGL fractionator decreased 21 MBPD which accounted for an additional $4.2 million increase.period-to-period.

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 September 30,
  
For the Nine Months
Ended September 30,
 
 2020  2019  2020  2019  2021  2020  2021  2020 
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
 $51.9  $89.3  $165.2  $298.6 
Non-cash mark-to-market gains (losses)  (0.5)  10.0   0.4   91.2 
Total Midland-to-ECHO 1 pipeline and related business activities  51.4   99.3   165.6   389.8 
Midland-to-ECHO 2 pipeline  34.2   27.0   102.4   72.5 
Total Midland-to-ECHO System  85.6   126.3   268.0   462.3 
Midland-to-ECHO System and related business activities $99.8  $82.3  $274.8  $264.7 
Other crude oil pipelines, terminals and related marketing results  396.2   369.9   1,301.1   1,209.4   323.1   399.5   967.2   1,304.4 
Total $481.8  $496.2  $1,569.1  $1,671.7  $422.9  $481.8  $1,242.0  $1,569.1 
                                
Selected volumetric data:                                
Crude oil pipeline transportation volumes (MBPD)  1,739   2,321   2,008   2,315   2,047   1,739   2,009   2,008 
Crude oil marine terminal volumes (MBPD)  662   987   790   972   588   662   642   790 

In general, segment volumes for the three and nine months ended September 30, 2020 were adversely impacted by the reduction in upstream crude oil production activities caused by the pandemic and crude oil price shock.
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Third Quarter of 20202021 Compared to Third Quarter of 20192020.  Gross operating margin from our Crude Oil Pipelines & Services segment for the third quarter of 20202021 decreased $14.4$58.9 million when compared to the third quarter of 2019.2020.

Gross operating margin from our crude oil marketing activities (excluding those attributable to the Midland-to-ECHO System and related business activitiesSystem) decreased a net $71.540.7 million quarter-to-quarter primarily due to lower average sales margins from marketing activities (including the impact of hedging activities), which accounted for a $42.9.  Results from crude oil marketing strategies that optimize our storage and transportation assets decreased $55.3 million decrease, lower transportation volumes, which accounted for a $10.1and $18.0 million decrease, and lower deficiency and other revenues, which accounted for an additional $12.1 million decrease, partially offset by lower chemical and other operating costs of $21.8 million.quarter-to-quarter, respectively.

Gross operating margin from our equity investment in the Eagle Ford Crude Oil Pipelinecrude oil activities at EHT decreased $8.9 $8.0 million quarter-to-quarter primarily due to lower transportation volumes.  storage revenues and other fees.  Crude oil terminal volumes at EHT decreased 131 MBPD quarter-to-quarter.

Gross operating margin from our South Texas Crude Oil Pipeline System decreased $15.6$5.8 million quarter-to-quarter primarily due to lower average transportation volumes.  On an aggregate basis,fees.  Transportation volumes on our South Texas Crude Oil Pipeline System increased 17 MBPD quarter-to-quarter.  Gross operating margin from our West Texas Pipeline System decreased $4.8 million quarter-to-quarter primarily due to lower average transportation fees.  Transportation volumes on our West Texas Pipeline System increased 96 MBPD quarter-to-quarter.

Gross operating margin from our Midland-to-ECHO System and related business activities increased a net $17.5 million quarter-to-quarter primarily due to higher transportation volumes on these three pipeline systems decreased 180of 142 MBPD quarter-to-quarter (net to our interest).
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, which accounted for a $30.5 million increase, partially offset by lower average sales margins from marketing activities, which accounted for a $10.5 million decrease.  The net quarter-to-quarter increase in transportation volumes for this system is generally due to the Midland-to-ECHO 3 pipeline, which was placed into service in October 2020.

Gross operating margin from our equity investment in the Seaway Pipeline decreased $17.5 million quarter-to-quarter primarily due to lower average transportation fees, which accounted for a $10.9 million decrease, and lower transportation volumes, which accounted for an additional $7.5 million decrease.  Net to our interest, transportation and marine volumes on the Seaway Pipeline decreased 269 MBPD and 75 MBPD, respectively, quarter-to-quarter.

Gross operating margin from our ECHO terminal decreased $7.0 million quarter-to-quarter primarily due to lower terminaling and storage revenues.  Gross operating margin from crude oil activities at EHT decreased a net $14.2 million quarter-to-quarter primarily due to lower deficiency fees, which accounted for a $22.7 million decrease, partially offset by higher storage and other revenues, which accounted for an $8.5 million increase, and lower operating costs, which accounted for an additional $3.0 million increase.  Crude oil terminal volumes at EHT decreased by 183 MBPD quarter-to-quarter.

Gross operating margin from our other crude oil marketing activities increased $91.7$9.5 million quarter-to-quarter primarily due to higher average sales margins (includingtransportation volumes.  Transportation volumes on the impact of hedging activities).  TheSeaway Pipeline increased 49 MBPD quarter-to-quarter increase in gross operating margin from our crude oil marketing activities, including those related(net to our Midland-to-ECHO System, is primarily due to results from marketing strategies that seek to optimize our storage assets.interest).

Nine Months Ended September 30, 20202021 Compared to Nine Months Ended September 30, 20192020.  Gross operating margin from our Crude Oil Pipelines & Services segment for the nine months ended September 30, 20202021 decreased $102.6$327.1 million when compared to the nine months ended September 30, 2019.2020.

Gross operating margin from our crude oil marketing activities (excluding those attributable to the Midland-to-ECHO System and related business activitiesSystem) decreased $273.6194.3 million period-to-period primarily due to lower average sales margins from marketing activities (including the impact of hedging activities) of $208.0.  Results from crude oil marketing strategies that optimize our storage and transportation assets decreased $172.8 million partially offset by lower chemical and other$46.9 million period-to-period, respectively.  In addition, gross operating costs of $37.7 million. margin attributable to non-cash, mark-to-market earnings decreased $28.1 million period-to-period.

Gross operating margin from our South Texas Crude Oil Pipeline System decreased $32.8$37.8 million period-to-period primarily due to lower transportation volumes of 17 MBPD, which accounted for a $24.2$20.9 million decrease, and lower average transportation and other fees, which accounted for an additional $13.0$17.7 million decrease.  Gross operating margin from our equity investment in the Eagle Ford Crude Oil Pipeline decreased $21.5$11.3 million period-to-period primarily due to lower transportation volumes.  On an aggregate basis, transportation volumes on these three pipeline systems decreased 98of 52 MBPD period-to-period (net to our interest).

Gross operating margin from our West Texas Pipeline System decreased $33.1 million period-to-period primarily due to lower average transportation fees.  Transportation volumes on our West Texas Pipeline System increased 20 MBPD period-to-period.

Gross operating margin from crude oil activities at EHT decreased $6.7 million period-to-period primarily due to lower storage revenues and other fees.  Crude oil terminal volumes at EHT decreased 175 MBPD period-to-period.

Gross operating margin from our equity investment in the Seaway Pipeline decreased a net $44.7increased $32.5 million period-to-period primarily due to lower transportation volumes, which accounted for a $30.3 million decrease, and lower average transportation fees, which accounted for an additional $17.4 million decrease.  Net to our interest, transportation and marineLaaR payments from power service providers in connection with the February 2021 winter storms.  Transportation volumes on theour Seaway Pipeline decreased 17161 MBPD and 23 MBPD, respectively, period-to-period.

Gross operating margin from our ECHO terminal decreased $25.0 million period-to-period primarily due to a benefit recognized during the second quarter of 2019 in connection with a settlement, which accounted for $13.9 million of the decrease, and lower terminaling and storage revenue, which accounted for an additional $12.9 million decrease.

Gross operating margin from our other crude oil marketing activities increased $192.9 million period-to-period primarily due to higher average sales margins (including the impact of hedging activities). The period-to-period increase in gross operating margin from our crude oil marketing activities, including those related(net to our Midland-to-ECHO System, is primarily due to results from marketing strategies that seek to optimize our storage assets.interest).

Gross operating margin from our West Texas System increased $9.5 million period-to-period primarily due to higher deficiency fees.  Transportation volumes decreased 4 MBPD period-to-period.  Lastly, gross operating margin from our EFS Midstream system increased $9.1 million period-to-period primarily due to higher average transportation fees.

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Gross operating margin from our Midland-to-ECHO System and related business activities increased a net $10.1 million period-to-period primarily due to higher transportation volumes of 115 MBPD (net to our interest), which accounted for a $45.8 million increase, and lower operating costs, which accounted for an additional $8.5 million increase, partially offset by lower average sales margins from marketing activities, which accounted for a $46.9 million decrease.  As noted previously, the increase in transportation volumes is generally attributable to placing the Midland-to-ECHO 3 pipeline into service during the fourth quarter of 2020.

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 September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
 2020  2019  2020  2019  2021  2020  2021  2020 
Segment gross operating margin $208.4  $258.5  $701.1  $824.6  $223.3  $208.4  $960.5  $701.1 
                                
Selected volumetric data:                                
Natural gas pipeline transportation volumes (BBtus/d)  13,131   14,474   13,322   14,341   14,556   13,131   14,144   13,322 

Third Quarter of 20202021 Compared to Third Quarter of 20192020.  Gross operating margin from our Natural Gas Pipelines & Services segment for the third quarter of 2020 decreased $50.12021 increased $14.9 million when compared to the third quarter of 2019.2020.

Gross operating margin from our natural gas marketing activities decreased $35.0increased $37.5 million quarter-to-quarter primarily due to lowerhigher average sales margins, (including the impact of hedging activities), which were negatively impacted by lowerbenefited from higher regional natural gas price spreads acrossin Louisiana and Texas. The indicative price spreads averaged $0.72 per MMBtu for the third quarter of 2020 versus $1.36 per MMBtu for the third quarter of 2019.

Gross operating margin from our Acadian Gas System decreased $19.4and Haynesville Gathering System increased a combined $10.1 million quarter-to-quarter primarily due to benefits from settlements received in the third quarter of 2019,higher transportation volumes, which accounted for a $16.7$5.9 million decrease,increase, and lowerhigher capacity reservation revenues, on the Haynesville Extension pipeline, which accounted for an additional $6.0$4.4 million decrease.  Transportationincrease.  On a combined basis, transportation volumes onincreased 543 BBtus/d.

Gross operating margin from our Acadian GasTexas Intrastate System decreased 302a net $22.1 million quarter-to-quarter primarily due to lower capacity reservation revenues, which accounted for a $33.5 million decrease, partially offset by higher storage and other fees, which accounted for a $5.3 million increase, and higher transportation volumes of 782 BBtus/d, quarter-to-quarter.which accounted for an additional $3.8 million increase. The quarter-to-quarter increase in transportation volumes for this system is primarily due to the addition of new firm and interruptible transportation agreements.

Gross operating margin from our Permian Basin Gathering System increased $9.2 million quarter-to-quarter primarily due to higher volumes of 432 BBtus/d.

On a combined basis, gross operating margin from our Jonah Gathering System, Piceance Basin Gathering System, and San Juan Gathering System in the Rocky Mountains decreased a net $2.4$8.8 million quarter-to-quarter primarily due to lower condensate sales, which accounted for a $9.5 million decrease, partially offset by higher natural gas gathering volumes of 577184 BBtus/d, which accounted for an $11.9a $2.3 million decrease, partially offset by lower operating costs, which accounted for an $8.0 million increase.  The quarter-to-quarter increase in natural gas gathering volumes is attributable to deliveries at our Orla facility.

Nine Months Ended September 30, 20202021 Compared to Nine Months Ended September 30, 20192020.  Gross operating margin from our Natural Gas Pipelines & Services segment for the nine months ended September 30, 2020 decreased $123.52021 increased $259.4 million when compared to the nine months ended September 30, 2019.

Gross operating margin from our2020.  As noted previously, two major winter storms impacted Texas Intrastate System decreased $45.5 million period-to-period primarily dueand the southern U.S. in mid-February 2021.  Given the higher demand for natural gas during the storms, we sold natural gas to lower capacity reservation revenues.  Transportation volumes on our Texas Intrastate System decreased 280 BBtus/d period-to-period.  Gross operating margin from our Acadian Gas System decreased $42.8 million period-to-period primarily due to lower capacity reservation revenues on the Haynesville Extension pipeline, which accounted for a $27.1 million decrease,assist electricity generators, natural gas utilities and net benefits from settlements, which accounted for an additional $15.4 million decrease.  Transportation volumes on our Acadian Gas System decreased 164 BBtus/d period-to-period.  Gross operating margin from our Haynesville Gathering System decreased $17.2 million period-to-period primarily due to lower gathering volumes of 223 BBtus/d, which accounted for an $11.0 million decrease, and lower gathering, compression and other fee revenues, which accounted for an additional $9.7 million decrease.

On a combined basis, gross operating margin from our Jonah Gathering System, Piceance Basin Gathering System, and San Juan Gathering Systemindustrial customers in the Rockies decreased a net $13.6 million period-to-period primarily due to lower volumes of 483 BBtus/d, which accounted for a $30.6 million decrease, partially offset by lower operating costs, which accounted for a $16.3 million increase.

meeting their requirements.  Gross operating margin from our natural gas marketing activities decreased $38.9increased $276.3 million period-to-period primarily due to lowerhigher average sales margins (including the impact of hedging activities), which accounted for a $27.3 million decrease, and lower sales volumes, which accounted for an additional $11.6 million decrease.
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Gross operating margin from our Permian Basin Gathering System increased $22.9$36.9 million period-to-period primarily due to higher condensate sales, which accounted for a 337 BBtus/d$29.5 million increase, inand higher natural gas gathering volumes.volumes of 359 BBtus/d, which accounted for an additional $8.9 million increase.  The period-to-period increase in gathering volumes is attributable to deliveries at our Mentone and Orla facilities.


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Gross operating margin from our Texas Intrastate System decreased a net $41.3 million period-to-period primarily due to lower capacity reservation revenues, which accounted for an $85.3 million decrease, partially offset by higher storage and other fees, which accounted for a $23.7 million increase, and higher transportation volumes of 596 BBtus/d, which accounted for an additional $14.5 million increase.

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 September 30,
  
For the Nine Months
Ended September 30,
 
 2020  2019  2020  2019  2021  2020  2021  2020 
Segment gross operating margin:                        
Propylene production and related activities $133.1  $130.8  $302.2  $366.8  $259.7  $133.1  $609.5  $302.2 
Butane isomerization and related operations  18.7   15.5   44.9   60.7   27.8   18.7   53.1   44.9 
Octane enhancement and related plant operations  40.0   54.6   145.7   131.4   45.2   40.0   78.8   145.7 
Refined products pipelines and related activities  101.5   74.4   242.9   241.6   57.9   101.5   229.8   242.9 
Ethylene exports and other services  21.7   13.1   49.3   35.4   20.7   21.7   47.9   49.3 
Total $315.0  $288.4  $785.0  $835.9  $411.3  $315.0  $1,019.1  $785.0 
                                
Selected volumetric data:                                
Propylene production volumes (MBPD)  83   105   84   99   96   83   98   84 
Butane isomerization volumes (MBPD)  102   109   92   110   108   102   85   92 
Standalone DIB processing volumes (MBPD)  120   103   119   97 
Standalone deisobutanizer (“DIB”) processing volumes (MBPD)  153   120   155   119 
Octane enhancement and related plant sales volumes (MBPD) (1)  35   33   34   33   39   35   33   34 
Pipeline transportation volumes, primarily refined products &
petrochemicals (MBPD)
  844   747   780   742 
Pipeline transportation volumes, primarily refined products and petrochemicals (MBPD)  782   844   889   780 
Marine terminal volumes, primarily refined products and
petrochemicals (MBPD)
  226   297   249   344   264   226   243   249 

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

Propylene production and related activities
Third Quarter of 20202021 Compared to Third Quarter of 20192020.  Gross operating margin from propylene production and related activities for the third quarter of 20202021 increased $2.3$126.6 million when compared to the third quarter of 2019.

2020.  Gross operating margin from our Lou-TexChambers County propylene pipelineproduction facilities increased a net $2.9combined $128.8 million quarter-to-quarter primarily due to higher average transportation fees, which accounted for a $5.6 million increase, partially offset by lower transportation volumes of 5 MBPD, which accounted for a $2.5 million decrease.  Gross operating margin from our Louisiana RGP Gathering System increased $2.4 million quarter-to-quarter primarily due to higher deficiency fee revenues.

Gross operating margin from our propylene production facilities decreased a combined $4.3 million quarter-to-quarter primarily due to lower average sales margins, which accounted for an $11.6 million decrease, lower propylene and associated by-product sales volumes, which accounted for an additional $11.2 million decrease, partially offset by higher fractionation and other fees, which accounted for a $12.4 million increase, and lower operating costs, which accounted for an additional $6.1 million increase.margins.  Propylene and associated by-product production volumes at these facilities decreasedincreased a combined 2012 MBPD quarter-to-quarter (net to our interest). As refiners reduced their utilization rates in response to lower demand for refined products caused by the pandemic, there was a decrease in the availability of refinery grade propylene feedstock used by our facilities to create polymer grade propylene, which contributed to the reduction in our volumes.

Nine Months Ended September 30, 20202021 Compared to Nine Months Ended September 30, 20192020.  Gross operating margin from propylene production and related activities for the nine months ended September 30, 2020 decreased $64.6 million.

Gross operating margin from our propylene production facilities decreased a combined $70.72021 increased $307.3 million period-to-period when compared to the nine months ended September 30, 2019 primarily due to lower average sales margins, which accounted for a $62.2 million decrease, and lower propylene and associated by-product sales volumes, which accounted for an additional $23.6 million decrease, partially offset by lower operating costs, which accounted for a $7.1 million increase.  Propylene production volumes at these facilities decreased a combined 14 MBPD period-to-period (net to our interest).
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Gross operating margin from our propylene export terminals increased $7.0 million period-to-period primarily due to higher average terminal fees.  Propylene export volumes decreased 6 MBPD period-to-period.

Isomerization and related operations
Third Quarter of 2020 Compared to Third Quarter of 2019.  Gross operating margin from isomerization and related operations increased $3.2 million quarter-to-quarter primarily due to an increase in blending revenues, which accounted for a $1.9 million increase, and higher standalone DIB processing volumes of 17 MBPD, which accounted for an additional $1.3 million increase.

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019.  Gross operating margin from isomerization and related operations decreased $15.8 million period-to-period primarily due to lower average by-product sales prices, which accounted for a $17.9 million decrease, and lower isomerization volumes of 18 MBPD, which accounted for an additional $9.5 million decrease, partially offset by lower operating costs, which accounted for a $13.7 million increase.

Octane enhancement and related plant operations
Third Quarter of 2020 Compared to Third Quarter of 2019.2020.  Gross operating margin from our octane enhancement and related plant operations decreased $14.6 million quarter-to-quarter primarily due to lower average sales margins, which accounted forChambers County propylene production facilities increased a $9.1 million decrease, and higher operating expenses, which accounted for an additional $7.1 million decrease.  The increase in operating expenses is primarily due to our iBDH plant, which is integrated with our legacy octane enhancement and high purity isobutylene assets and was placed into service in December 2019.

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019.  Gross operating margin from our octane enhancement and related plant operations increased $14.3combined $301.5 million period-to-period primarily due to higher average sales margins, which accounted for a $19.1$194.4 million increase, and higher propylene fractionation fees, which accounted for an additional $103.0 million increase.  Propylene and associated by-product production volumes at these facilities increased a combined 12 MBPD period-to-period (net to our interest). 

Butane isomerization and related operations
Third Quarter of 2021 Compared to Third Quarter of 2020.  Gross operating margin from butane isomerization and related operations increased $9.1 million quarter-to-quarter primarily due to higher by-product sales.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020.  Gross operating margin from butane isomerization and related operations increased $8.2 million period-to-period primarily due to higher by-product sales, which accounted for a $17.3 million increase, partially offset by higher operating costs, which accounted for a $10.5 million decrease. 

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Octane enhancement and related plant operations
Third Quarter of 2021 Compared to Third Quarter of 2020.  Gross operating margin from our octane enhancement and related plant operations increased $5.2 million quarter-to-quarter primarily due to higher sales volumes, which accounted for an additionala $9.3 million increase, partially offset by higher operating expenses,costs, which accounted for a $17.6$5.7 million decrease.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020.  Gross operating margin from our octane enhancement and related plant operations decreased $66.9 million period-to-period primarily due to lower average sales margins (including the impact of hedging activities), which accounted for a $41.3 million decrease, lower sales volumes, which accounted for an $8.2 million decrease, and largely attributablehigher operating costs, which accounted for an additional $17.9 million decrease.  Production volumes at these facilities for 2021 were lower when compared to start-up2020 primarily due to planned major maintenance activities, which were completed in the last week of January 2021 for our HPIB plant and the iBDHbeginning of May 2021 for our octane enhancement plant.

Refined products pipelines and related activities
Third Quarter of 20202021 Compared to Third Quarter of 20192020.  Gross operating margin from refined products pipelines and related activities for the third quarter of 2020 increased $27.12021 decreased $43.6 million when compared to the third quarter of 2019.

2020.  Gross operating margin from our refined products marketing activities increased a net $30.6decreased $43.1 million quarter-to-quarter primarily due to higher sales volumes, which accounted for a $45.7 million increase, partially offset by lower average sales margins (including the impact of hedging activities), which accounted for a $15.2 million decrease. The quarter-to-quarter increase in gross operating margin from our refined products marketing activities is primarily due to results .from marketing strategies that seek to optimize our storage assets.

Gross operating margin from our TE Products Pipeline System decreased a net $8.1 million quarter-to-quarter primarily due to lower average NGL transportation fees, which accounted for a $17.4 million decrease, partially offset by higher average petrochemical transportation fees, which accounted for a $10.6 million increase.  Overall transportation volumes on our TE Products Pipeline System increased a net 54 MBPD quarter-to-quarter.

Nine Months Ended September 30, 20202021 Compared to Nine Months Ended September 30, 20192020.  Gross operating margin from refined products pipelines and related activities for the nine months ended September 30, 2020 increased $1.32021 decreased $13.1 million when compared to the nine months ended September 30, 2019.2020.

Gross operating margin from our refined products marketing activities increaseddecreased a net $31.9$27.1 million period-to-period primarily due to lower average sales margins (including the impact of hedging activities), which accounted for a $44.3 million decrease, partially offset by higher sales volumes, which accounted for a $17.6 million increase.

Gross operating margin at our TE Products Pipeline System increased $11.1 million period-to-period primarily due to higher sales volumes. The period-to-period increase in gross operating margin from our refined products marketing activities is primarily due to results from marketing strategies that seek to optimize our storage assets.

Gross operating margin from our TE Products Pipeline System decreased $26.3 million period-to-period primarily due to lower interstate refined productsaggregate transportation volumes which accounted for a $17.3 million decrease, and lower average NGL transportation fees, which accounted for an additional $13.4 million decrease, partially offset by higher average petrochemical transportation fees, which accounted for an $11.8 million increase.related fees.  Overall, transportation volumes on our TE Products Pipeline System increased a net 1782 MBPD period-to-period.
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Gross operating margin from our refined products terminal in Beaumont, Texas decreased a net $8.9 million period-to-period primarily due to lower storage revenues, which accounted for a $14.8 million decrease, partially offset by lower operating costs, which accounted for a $7.7 million increase.  Terminaling volumes at Beaumont decreased a net 82 MBPD period-to-period.

Ethylene exports and other services
Third Quarter of 20202021 Compared to Third Quarter of 20192020.  Gross operating margin from ethylene exports and other services forduring the third quarter of 2020 increased a net $8.62021 decreased $1.0 million when compared to the third quarter of 2019.2020.  Gross operating margin from marine transportation decreased $5.5 million quarter-to-quarter primarily due to higher operating costs.  Gross operating margin from our ethylene export terminal which was first placed into limited service in December 2019, and its related operations was a combined $13.9increased $4.4 million for the third quarter of 2020.quarter-to-quarter primarily due to higher storage revenues and other fees.  Loading volumes at our ethylene export terminal for the third quarter of 2020 were 15 decreased 3 MBPD (net to our interest).  Gross operating margin from marine transportation decreased $5.8 million quarter-to-quarter primarily due to lower fleet utilization rates.

Nine Months Ended September 30, 20202021 Compared to Nine Months Ended September 30, 20192020.  Gross operating margin from ethylene exports and other services during the nine months ended September 30, 2020 increased $13.92021 decreased $1.4 million when compared to the nine months ended September 30, 2019.2020.  Gross operating margin from marine transportation decreased $24.2 million period-to-period primarily due to lower average fees and lower fleet utilization rates.  Gross operating margin from our ethylene export terminal and its related operations was $16.2increased $22.7 million for the nine months ended September 30, 2020.  Loadingperiod-to-period primarily due to higher loading volumes at our ethylene export terminal were 9of 3 MBPD (net to our interest) during the nine months ended September 30, 2020..  


Liquidity and Capital Resources

Based on current market conditions (as of the filing date of this quarterly report), we believe that the Partnership and its consolidated businesses will have sufficient liquidity, cash flow from operations and access to capital markets to fund their capital investments and working capital needs for the reasonably foreseeable future.  At September 30, 2020,2021, we had $6.03$6.7 billion of consolidated liquidity, which was comprised of $5.0$4.5 billion of available borrowing capacity under EPO’s revolving credit facilities and $1.03 $2.2billion billion of unrestricted cash on hand.

We may issue equitydebt and debtequity 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 the Partnership and EPO to issue an unlimited amount of equity and debt securities, respectively.
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Enterprise Declares Cash Distribution for Third Quarter of 20202021

On October 712, 2020,2021, we announced that the Board declared a quarterly cash distribution of $0.4450$0.45 per common unit, or $1.78$1.80 per unit on an annualized basis, to be paid to the Partnership’s common unitholders with respect to the third quarter of 2020.2021.  The quarterly distribution is payable on November 12, 2020,2021 to unitholders of record as of the close of business on October 3029, 2021.  The total amount to be paid is $, 2020.  In light of current economic conditions, management will evaluate any future increases in cash distributions989.7 million, which includes $7.8 million for distribution equivalent rights on a quarterly basis.  phantom unit awards.

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

Consolidated Debt

At September 30, 2020,2021, the average maturity of EPO’s consolidated debt obligations was approximately 20.620.9 years.  The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations at September 30, 20202021 for the years indicated (dollars in millions):

     Scheduled Maturities of Debt 
  Total  
Remainder
of 2020
  2021  2022  2023  2024  Thereafter 
Principal amount of senior and junior debt obligations $30,146.4  $–  $1,325.0  $1,400.0  $1,250.0  $850.0  $25,321.4 

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   Scheduled Maturities of Debt 
 Total 
Remainder
of 2021
 2022 2023 2024 2025 Thereafter 
Senior Notes $27,175.0  $–  $1,400.0  $1,250.0  $850.0  $1,150.0  $22,525.0 
Junior Subordinated Notes  2,646.4   –   –   –   –   –   2,646.4 
Total $29,821.4  $–  $1,400.0  $1,250.0  $850.0  $1,150.0  $25,171.4 

In January 2020,February 2021, EPO issued $3.0 billion aggregate principal amountrepaid all of senior notes comprised of (i) $1.0 billion principal amount of 2.80% fixed-rate senior notes due January 2030 (“Senior Notes AAA”), (ii) $1.0 billion principal amount of 3.70% fixed-rate senior notes due January 2051 (“Senior Notes BBB”) and (iii) $1.0 billion principal amount of 3.95% fixed-rate senior notes due January 2060 (“Senior Notes CCC”).   Net proceeds from this offering were used by EPO for the repayment of $500$750.0 million in principal amount of its Senior Notes Q that matured in JanuaryTT using remaining cash on hand attributable to its August 2020 temporary repaymentsenior notes offering and proceeds from the issuance of amounts outstandingshort-term notes under its commercial paper program and for general company purposes.  program.

In addition, net proceeds from this offering were used byMarch 2021, EPO forredeemed all of the repayment of $1.0 billion$575.0 million outstanding principal amount of its Senior Notes Y that maturedRR one month prior to their scheduled maturity in September 2020.April 2021.  These notes were redeemed at par (i.e., at a redemption price equal to the outstanding principal amount of such notes to be redeemed, plus accrued and unpaid interest thereon) using proceeds from the issuance of short-term notes under its commercial paper program.

In AugustSeptember 2021, EPO entered into a new 364-Day Revolving Credit Agreement (the “September 2021 364-Day Revolving Credit Agreement”) that replaced its September 2020 364-Day Revolving Credit Agreement.  The September 2021 364-Day Revolving Credit Agreement matures in September 2022.  EPO’s borrowing capacity was unchanged from the prior 364-day revolving credit agreement.  As of September 30, 2021, there are no principal amounts outstanding under this new revolving credit agreement.

In September 2021, EPO entered into a new revolving credit agreement that matures in September 2026 (the “September 2021 Multi-Year Revolving Credit Agreement”). The September 2021 Multi-Year Revolving Credit Agreement replaced EPO’s prior multi-year revolving credit agreement that was scheduled to mature in September 2024.  EPO’s borrowing capacity decreased from $3.5 billion under the prior multi-year revolving credit agreement to $3.0 billion (which may be increased by up to $500.0 million to $3.5 billion at EPO’s election, provided certain conditions are met) under the September 2021 Multi-Year Revolving Credit agreement.  As of September 30, 2021, there are no principal amounts outstanding under this new revolving credit agreement.

In September 2021, EPO issued $1.0 billion in principal amount of 3.20% fixed-rate senior notes due February 20522053 (“Senior Notes DDD”EEE”) and $250.0 million.  Senior Notes EEE were issued at 99.170% of their principal amount and have a fixed rate of reopened 2.80% fixed-rate Senior Notes AAA.  We received aggregate net proceedsinterest of $1.25 billion from the sale of the notes after deducting underwriting discounts and other estimated offering expenses payable by us.  3.30% per year.  Net proceeds from the issuance of these senior notes will be used for general company purposes, including for growth capital investments, and to repay all or partthe repayment of debt (including the repayment of a portion of our $750.0 million in principal amount of 3.50% Senior Notes TT, which matureVV and/or a portion of our $650.0 million in principal amount of 4.05% Senior Notes CC, in each case at their maturity in February 2021.2022).
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In September 2020, EPO entered into a new 364-Day Revolving Credit Agreement that replaced its September 2019 364-Day Revolving Credit Agreement.  The new 364-Day Revolving Credit Agreement matures in September 2021. There was no principal amount outstanding under the September 2019 364-Day Revolving Credit Agreement when it expired and was replaced by the September 2020 364-Day Revolving Credit Agreement.  In addition, following execution of the September 2020 364-Day Revolving Credit Agreement, EPO terminated its April 2020 364-Day Revolving Credit Agreement on September 11, 2020.

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

Credit Ratings

As of November 86, 2020,2021, the investment-grade credit ratings of EPO’s long-term senior unsecured debt securities were BBB+ from Standard and Poor’s, Baa1 from Moody’s and BBB+ from Fitch Ratings.  In addition, the credit ratings of EPO’s short-term senior unsecured debt securities were A-2 from Standard and Poor’s, P-2 from Moody’s and F-2 from Fitch Ratings.  EPO’s credit ratings reflect only the view of a rating agency and should not be interpreted as a recommendation to buy, sell or hold any of our securities.  A credit rating can be revised upward or downward or withdrawn at any time by a rating agency, if it determines that circumstances warrant such a change. A credit rating from one rating agency should be evaluated independently of credit ratings from other rating agencies.

Common Unit Repurchases Under 2019 Buyback Program

In January 2019, we announced that the Board had approved a $2.0 billion multi-year unit buyback program (the “2019 Buyback Program”), which provides the Partnership with an additional method to return capital to investors.  The Partnership repurchased an aggregate 8,342,2463,367,377 and 4,077,193 common units under the 2019 Buyback Program through open market and private purchases during the three and nine months ended September 30, 2020.2021, respectively.  The total purchase pricecost of these repurchases, was $173.8 million including commissions and fees,. Units repurchased under the 2019 Buyback Program are immediately cancelled upon acquisition. was $74.9 million and $88.8 million, respectively. As of September 30, 2020,2021, the remaining available capacity under the 2019 Buyback Program was $1.75 billion.

In addition to the 2019 Buyback Program, privately held affiliates of EPCO acquired 1,459,000 of the Partnership’s common units on the open market during the nine months ended September 30, 2020.  In the aggregate, 9,801,246$1.64 common units were purchased on the open market during the nine months ended September 30, 2020 under the 2019 Buyback Program and by privately held affiliates of EPCO.

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March 2020 Issuance of Common Units to Skyline North Americas, Inc. and related acquisition of Treasury Units

On March 5, 2020, the Partnership settled its obligations under the Liquidity Option Agreement by issuing 54,807,352 new common units to Skyline North Americas, Inc. in exchange for the capital stock of OTA.  Upon settlement of the Liquidity Option, we indirectly acquired the 54,807,352 Partnership common units owned by OTA (which were issued by the Partnership to OTA in October 2014) and assumed all future income tax obligations of OTA, including its deferred tax liability.  For additional information regarding settlement of the Liquidity Option, see Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

September 2020 Issuance of Series A Cumulative Convertible Preferred Units

On September 30, 2020, the Partnership issued and sold an aggregate of 50,000 Series A Cumulative Convertible Preferred Units in a private placement transaction.  The stated value of each preferred unit is $1,000 per unit.  The total offering price for the preferred units was $50.0 million, of which $32.5 million was received in cash with the remaining $17.5 million funded through the exchange of 1,120,588 of the Partnership’s common units owned by the purchasers.  Cash proceeds from the preferred unit offering include $15.0 million received from a privately held affiliate of EPCO for the purchase of 15,000 preferred units.

Concurrently, the Partnership exchanged all of the 54,807,352 Partnership common units owned directly by OTA for 855,915 of the Partnership’s new preferred units having an equivalent value.  The preferred units held by OTA, like the common units OTA held prior to the exchange, are accounted for as treasury units by the Partnership in consolidation.  The historical cost of the treasury units did not change as a result of the exchange and remains at the $1.3 billion recognized in March 2020 in connection with settlement of the Liquidity Option.

For additional information regarding the preferred units, see Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.billion.

Cash Flow Statement Highlights

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

 
For the Nine Months
Ended September 30,
 
For the Nine Months
Ended September 30,
 
 2020  2019 2021 2020 
Net cash flows provided by operating activities $4,291.6  $4,826.2  $6,387.3  $4,291.6 
Cash used in investing activities  2,564.2   3,372.8   1,721.5   2,564.2 
Cash used in financing activities  1,006.3   655.7   3,465.8   1,006.3 

Net cash flows provided by operating activities are largely dependent on earnings from our consolidated business activities. Changes in energy commodity prices may impact the demand for natural gas, NGLs, crude oil, petrochemical and refined products, which could impact sales of our products and the demand for our midstream services. Changes in demand for our products and services may be caused by other factors, including prevailing economic conditions, reduced demand by consumers for the end products made with hydrocarbon products, increased competition, public health emergencies, adverse weather conditions and government regulations affecting prices and production levels.  We may also incur credit and price risk to the extent customers do not fulfill their contractual obligations to us in connection with our marketing activities and long-term take-or-pay agreements.  For a more complete discussion of these and other risk factors, pertinent to our business, see “Risk Factors” included under Part I, Item 1A of the 20192020 Form 10-K and10-K.

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




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

Operating activities
Net cash flows provided by operating activities for the nine months ended September 30, 2020 decreased2021 increased $2.1 534.6 millionbillion when compared to the nine months ended September 30, 20192020 primarily due to:

•
a $1.02 b283.0 millionillion period-to-period decreaseincrease primarily due to higher levels of working capital employed in our marketing activities, which accounted for a $1.3 billion decrease, partially offset by the timing of cash receipts and payments related to operations;

•
a $157.8 million period-to-period decrease resulting from lower partnership earnings in the nine months ended September 30, 2020 when compared to the nine months ended September 30, 2019 (determined by adjusting our $41.9 million period-to-period decrease in net income for changes in the non-cash items identified on our Unaudited Condensed Statements of Consolidated Cash Flows); and
a $715.9 million period-to-period increase attributable to the return of working capital employed in our marketing activities primarily related to storage optimization strategies;
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•
a $93.8 million period-to-period decrease in cash distributions attributable to earnings from unconsolidated affiliates, with those unconsolidated affiliates owning crude oil pipelines and terminals accounting for substantially all of the decrease.

a $288.1 million period-to-period increase resulting from higher partnership earnings (determined by adjusting our $170.9 million period-to-period increase in net income for changes in the non-cash items identified on our Unaudited Condensed Statements of Consolidated Cash Flows); and

a $68.5 million period-to-period increase in cash distributions received on earnings from unconsolidated affiliates primarily attributable to our investments in crude oil pipelines.

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

Investing activities
Cash used in investing activities for during the nine months ended September 30, 20202021 decreased $808.6 million$842.7 million when compared to the nine months ended September 30, 2020 primarily due to an $865.9 million period-to-period decrease in investments for property, plant and equipment (see “Capital Investments” within this Part I, Item 2 for additional information).

Financing activities
Cash used in financing activities during the nine months ended September 30, 2021 increased $2.46 billion when compared to the nine months ended September 30, 2020.  The period-to-period increase was primarily due to a net cash outflow of $273.2 million related to debt during the nine months ended September 30, 2021 compared to a net cash inflow of $2.19 billion during the nine months ended September 30, 2019 primarily due to:

•
a $630.5 million period-to-period decrease in investments for property, plant and equipment (see “Capital Investments” within this Part I, Item 2 for additional information);

•
a $90.2 million period-to-period decrease in investments in unconsolidated affiliates primarily due to lower cash outlays for NGL and crude oil pipeline projects; and

•
a $71.0 million period-to-period increase in cash distributions attributable to the return of capital from unconsolidated affiliates, with those unconsolidated affiliates owning crude oil pipelines and terminals accounting for substantially all of the increase.

Financing activities
Cash used in financing activities for2020.  During the nine months ended September 30, 2020 increased a net $350.6 million when compared to2021, we repaid $1.33 billion aggregate principal amount of senior notes, partially offset by the issuance of $1.0 billion principal amount of senior notes.  During the nine months ended September 30, 2019 primarily due to:

•
a $569.6 million period-to-period decrease in cash contributions from noncontrolling interests. In July 2019, an affiliate of Apache Corporation acquired a noncontrolling 33% equity interest in our consolidated subsidiary that owns the Shin Oak NGL Pipeline for $440.7 million.  In addition, cash contributions from noncontrolling interests in connection with our Pascagoula natural gas processing plant and ethylene export facility decreased a combined $95.0 million period-to-period;

•
a $92.7 million period-to-period increase in cash used to acquire common units under our 2019 Buyback Program;

•
an $82.2 million period-to-period decrease in net cash proceeds from the issuance of common units under our distribution reinvestment plan (“DRIP”) and employee unit purchase plan (“EUPP”).  In July 2019, the Partnership announced that, beginning with the quarterly distribution payment paid in August 2019, it would use common units purchased on the open market, rather than issuing new common units, to satisfy its delivery obligations under the DRIP and EUPP; and

•
a $48.5 million period-to-period increase in cash distributions paid to common unitholders attributable to increases in the quarterly cash distribution rate per unit; partially offset by
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Table2020, we issued $4.25 billion aggregate principal amount of Contentssenior notes, partially offset by the repayment of $1.5 billion aggregate principal amount of senior notes.  In addition, net repayments of short term notes under EPO’s commercial paper program were $481.8 million during the nine months ended September 30, 2020.


•
a net $437.9 million period-to-period increase in net cash inflows from debt.  For the nine months ended September 30, 2020, we issued $4.25 billion aggregate principal amount of senior notes, partially offset by the repayment of $1.5 billion principal amount of senior notes.  For 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 addition, net repayments of short term notes under EPO’s commercial paper program were $481.7 million during the nine months ended September 30, 2020; and

•
a $32.5 million increase in cash proceeds from the issuance of preferred units on September 30, 2020.

Non-GAAP Cash Flow Measures

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

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

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

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











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

 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
 2020  2019  2020  2019  2021  2020  2021  2020 
Net income attributable to common unitholders (GAAP) (1) $1,052.6  $1,019.2  $3,437.4  $3,494.4  $1,153.0  $1,052.6  $3,605.7  $3,437.4 
Adjustments to net income attributable to common unitholders to
derive DCF (addition or subtraction indicated by sign):
                                
Depreciation, amortization and accretion expenses  513.4   493.6   1,545.1   1,456.7   534.9   513.4   1,593.7   1,545.1 
Cash distributions received from unconsolidated affiliates (2)  146.7   170.6   462.3   485.1   147.8   146.7   447.1   462.3 
Equity in income of unconsolidated affiliates  (82.0)  (139.3)  (336.1)  (431.3)  (137.6)  (82.0)  (447.2)  (336.1)
Asset impairment and related charges  77.0   39.5   90.4   51.3 
Asset impairment charges  29.4   77.0   112.9   90.4 
Change in fair market value of derivative instruments  37.7   85.8   (53.7)  2.0   (47.5)  37.7   (86.3)  (53.7)
Change in fair value of Liquidity Option  –   38.7   2.3   123.1   –   –   –   2.3 
Deferred income tax expense (benefit)  (18.3)  6.7   (149.0)  10.9   9.0   (18.3)  33.1   (149.0)
Sustaining capital expenditures (3)  (83.1)  (90.8)  (226.0)  (232.5)  (70.3)  (83.1)  (330.9)  (226.0)
Other, net(4)  (1.3)  14.8   30.1   13.8   (13.3)  (1.3)  (112.4)  30.1 
Operational DCF (4)(5) $1,642.7  $1,638.8  $4,802.8  $4,973.5  $1,605.4  $1,642.7  $4,815.7  $4,802.8 
Proceeds from asset sales  4.3   0.7   8.4   16.8   7.8   4.3   58.1   8.4 
Monetization of interest rate derivative instruments accounted
for as cash flow hedges
  –   –   (33.3)  –   –   –   75.2   (33.3)
DCF (non-GAAP) $1,647.0  $1,639.5  $4,777.9  $4,990.3  $1,613.2  $1,647.0  $4,949.0  $4,777.9 
                                
Cash distributions paid to common unitholders with respect to period $978.5  $974.4  $2,938.1  $2,907.0 
Cash distributions paid to common unitholders with respect to period, including distribution equivalent rights on phantom unit awards $989.7  $978.5  $2,972.6  $2,938.1 
                                
Cash distribution per common unit declared by Enterprise GP with respect to period (5)(6) $0.4450  $0.4425  $1.3350  $1.3200  $0.4500  $0.4450  $1.3500  $1.3350 
                                
Total DCF retained by the Partnership with respect to period (6)(7) $668.5  $665.1  $1,839.8  $2,083.3  $623.5  $668.5  $1,976.4  $1,839.8 
                                
Distribution coverage ratio (7)(8)  1.7x  1.7x  1.6x  1.7x  1.6x  1.7x  1.7x  1.6x

(1)
For a discussion of the primary drivers of changes in our comparative income statement amounts, see “Income“Income Statement Highlights”Highlights” within this Part I, Item 2.
(2)Reflects aggregate distributions received from unconsolidated affiliates attributable to both earnings and the return of capital.
(3)Sustaining capital expenditures include cash payments and accruals applicable to the period.
(4)The nine months ended September 30, 2021 includes $100 million of trade accounts receivable that we do not expect to collect in the normal billing cycle.
(5)Represents DCF before proceeds from asset sales and the monetization of interest rate derivative instruments accounted for as cash flow hedges.
(5)(6)
See Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report for additional information regarding our quarterly cash distributions declared with respect to the yearsperiods indicated.
(6)(7)
At the sole discretion of Enterprise GP, cashCash retained by the partnership with respect to each of these periods was primarily reinvested in growthPartnership may be used for capital projects.  This retainageinvestments, debt service, working capital, operating expenses, common unit repurchases, commitments and contingencies and other amounts.  The retention of cash substantially reducedreduces our reliance on the equity capital markets to fund such expenditures.
markets.
(7)(8)Distribution coverage ratio is determined by dividing DCF by total cash distributions paid to common unitholders and in connection with distribution equivalent rights with respect to the period.





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

 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
 2020  2019  2020  2019  2021  2020  2021  2020 
Net cash flows provided by operating activities (GAAP) $1,097.8  $1,642.5  $4,291.6  $4,826.2  $2,370.3  $1,097.8  $6,387.3  $4,291.6 
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  603.0   77.0   692.0   409.0   (647.9)  603.0   (1,047.1)  692.0 
Sustaining capital expenditures  (83.1)  (90.8)  (226.0)  (232.5)  (70.3)  (83.1)  (330.9)  (226.0)
Distributions received from unconsolidated affiliates attributable
to the return of capital
  66.9   30.5   124.9   53.9   4.3   66.9   41.2   124.9 
Proceeds from asset sales  4.3   0.7   8.4   16.8   7.8   4.3   58.1   8.4 
Net income attributable to noncontrolling interest  (31.4)  (25.6)  (82.4)  (67.3)
Net income attributable to noncontrolling interests  (28.3)  (31.4)  (82.3)  (82.4)
Monetization of interest rate derivative instruments accounted
for as cash flow hedges
  –   –   (33.3)  –   –   –   75.2   (33.3)
Other, net  (10.5)  5.2   2.7   (15.8)  (22.7)  (10.5)  (152.5)  2.7 
DCF (non-GAAP) $1,647.0  $1,639.5  $4,777.9  $4,990.3  $1,613.2  $1,647.0  $4,949.0  $4,777.9 

Free Cash Flow
Free Cash Flow (“FCF”), a non-GAAP financial measure, is a traditional cash flow metricmeasure 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 midstream energy companies, including master limited partnerships. In general, FCF is a measure ofreflects how much cash flow a business generates during a specified time period after accounting for all capital investments, including expendituresthose for growth and sustaining capital projects. By comparison, only sustaining capital expenditures are reflected in DCF.

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

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

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

 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
  
For the Twelve Months Ended
September 30,
  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
 2020  2019  2020  2019  2020  2021  2020  2021  2020 
Net cash flows provided by operating activities (GAAP) $1,097.8  $1,642.5  $4,291.6  $4,826.2  $5,985.9  $2,370.3  $1,097.8  $6,387.3  $4,291.6 
Adjustments to net cash flows provided by operating activities to derive FCF (addition or subtraction indicated by sign):                                    
Cash used in investing activities  (633.7)  (1,086.3)  (2,564.2)  (3,372.8)  (3,766.9)  (492.8)  (633.7)  (1,721.5)  (2,564.2)
Cash contributions from noncontrolling interests  1.5   491.2   21.2   590.8   63.2   4.9   1.5   23.0   21.2 
Cash distributions paid to noncontrolling interests  (36.0)  (22.8)  (97.8)  (69.7)  (134.3)  (43.7)  (36.0)  (115.1)  (97.8)
FCF (non-GAAP) $429.6  $1,024.6  $1,650.8  $1,974.5  $2,147.9  $1,838.7  $429.6  $4,573.7  $1,650.8 

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


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Capital Investments

Capital investing activity throughoutThe following table summarizes our capital investments for the domestic energy industry has been reduced significantlyperiods indicated (dollars in responsemillions):

  
For the Nine Months
Ended September 30,
 
  2021  2020 
Capital investments for property, plant and equipment: (1)      
   Growth capital projects (2) $1,473.6  $2,440.2 
   Sustaining capital projects (3)  332.1   231.4 
      Total $1,805.7  $2,671.6 
         
Investments in unconsolidated affiliates $1.3  $9.9 

(1)Growth and sustaining capital amounts are presented on a cash basis.  In total, these amounts represent “Capital expenditures” as presented on our Unaudited Condensed Statements of Consolidated Cash Flows.
(2)Growth capital projects either (a) result in new sources of cash flow due to enhancements of or additions to existing assets (e.g., additional revenue streams, cost savings resulting from debottlenecking of a facility, etc.) or (b) expand our asset base through construction of new facilities that will generate additional revenue streams and cash flows.
(3)Sustaining capital projects are capital expenditures (as defined by GAAP) resulting from improvements to existing assets.  Such expenditures serve to maintain existing operations but do not generate additional revenues or result in significant cost savings. Sustaining capital expenditures include the costs of major maintenance activities at our reaction-based plants, which are accounted for using the deferral method.

As of September 30, 2021, we have $2.9 billion of growth capital projects scheduled to the supply and demand disruptions causedbe placed into service by the COVID-19 pandemicend of 2023.  This includes a natural gasoline hydrotreater facility at our Chambers County complex, which was placed into service in October 2021, the Gillis Lateral natural gas pipeline and its related infrastructure in the related oil price shock. In lightfourth quarter of these adverse macroeconomic conditions, we have reevaluated2021 and our planned capital investmentsPDH 2 facility in order to maximize available liquidity.the second quarter of 2023.

Based on information currently available, we expect our total capital investments for 2020,2021, net of expected contributions from joint venture partners,noncontrolling interests, to approximate $3.2$2.2 billion for sanctioned projects, which reflects growth capital investments of      $2.9$1.7 billion and approximately $300 million for sustaining capital expenditures.expenditures of $440 million.  In addition, we currently expect our growth capital investments in 2021 and 2022 for sanctioned projects to approximate $1.6$800 million; however, growth capital expenditures for 2022 could ultimately be in the range of $1.0 billion and $800 million, respectively.to $1.5 billion considering projects currently under development. These amounts do not include capital investments associated with SPOT, our proposed deepwater offshore crude oil terminal (the Sea Port Oil Terminal, or SPOT), which remains subject to governmental approvals.  We currently anticipate receiving approval for SPOT as early as mid-2022; however, we can give no assurance as to whether the project will ultimately be approved or the timing of such decision.

Our forecast of capital investments for 2020 through 2022 is based on announced strategic operating and growth plans (through the filing date of this quarterly report), which are dependent upon our ability to generate the required funds from either operating cash flows or other means, including borrowings under debt agreements, the issuance of additional equity and debt securities, and potential divestitures.  We may revise our forecast of capital investments due to factors beyond our control, such as adverse economic conditions, weather-related issues and changes in supplier prices.  Furthermore, our forecast of capital investments may change due to decisions made by management at a later date, which may include unforeseen acquisition opportunities.  Our success in raising capital, including partnering with other companies to share project costs and risks, continues to be a significant factor in determining how much capital we can invest.  We believe our access to capital resources is sufficient to meet the demands of our current and future growth needs and, although we expect to make the forecast capital investments noted above, we may adjust the timing and amounts of projected expenditures in response to changes in capital market conditions.

We placed Frac X and Frac XI into service in March 2020 and September 2020, respectively. In addition, expansion projects on our Texas Express Pipeline and Front Range Pipeline were placed into commercial service in April 2020. We also placed the Midland-to-ECHO segment of the Midland-to-Webster pipeline into service in October 2020.  We currently have $3.9 billion of growth capital projects scheduled to be completed by the end of 2023, which includes completion of our PDH 2 facility in the second quarter of 2023.

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

  
For the Nine Months
Ended September 30,
 
  2020  2019 
Capital investments for property, plant and equipment: (1)
      
Growth capital projects (2) $2,440.2  $3,072.4 
Sustaining capital projects (3)  231.4   229.7 
   Total $2,671.6  $3,302.1 
         
Investments in unconsolidated affiliates $9.9  $100.1 

(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 Nine Months Ended September 30, 20202021 with Nine Months Ended September 30, 20192020

In total, investments in growth capital projects decreased $632.2$966.6 million period-to-period primarily due to the following:

completion of projects at our Mont Belvieu complex, which accounted for a $510.6 million decreaseassociated with crude oil pipelines (e.g., expansion projects involving the Midland-to-ECHO System and included placing into service our iBDH facility (December 2019), Frac X (March 2020) and Frac XI (September 2020);

completion of the Shin Oak NGL Pipeline (in stages through the fourth quarter of 2019)related crude oil-related infrastructure supporting Permian Basin producers), which accounted for a $316.4combined $361.3 million decrease;
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completion of projects at our Chambers County complex (e.g., the completion of Frac X and Frac XI), which accounted for a $316.7 million decrease;

lower investments in Permian Basin natural gas processing facilities and related infrastructure, that support Permian Basin production, which accounted for a $274.5$68.7 million decrease. We completed the final phase of our Orla plant in July 2019 and placed our Mentone plant into service in December 2019;decrease; and

lower investments in projects attributablerelated to our ethylene business, which accounted for a $129.0$52.6 million decrease; partially offset by,

higher investments in our PDH 2 facility, which accounted for a $293.7 million increase;

higher investments in crude oil pipelines, including those expanding our Midland-to-ECHO System, and related infrastructure that support Permian Basin production, which accounted for a combined $98.8 million increase; and

higher investments in natural gas pipelines and related infrastructure in support of East Texas and Louisiana production, which accounted for a $50.9 million increase.decrease.

Investments in unconsolidated affiliates decreased $90.2attributable to sustaining capital projects increased $100.7 million period-to-period primarily due to lower spending on joint venture dock infrastructurethe cost of major maintenance activities performed during the nine months ended September 30, 2021 at Corpus Christicertain of our reaction-based plants (PDH 1, octane enhancement and other crude oil-related projects, whichhigh purity isobutylene facilities).  These costs accounted for a $46.4$97.0 million decrease, and NGL pipeline expansion projects, which accounted for an additional $38.1 million decrease.

Fluctuationsof the period-to-period increase in investments for sustaining capital projectsinvestments. For reaction-based plants, we use the deferral method when accounting for major maintenance activities.  Under the deferral method, major maintenance costs are primarily duecapitalized and amortized over the period until the next major overhaul project. We adopted the deferral method for our reaction-based plants in November 2020.  Historically, the costs of major maintenance activities attributable to the timing and cost of pipeline integrity and similar projects.our reaction-based facilities, principally our octane enhancement assets, were not material to our consolidated financial statements.

Critical Accounting Policies and Estimates

A discussion of our critical accounting policies and estimates is included in our 20192020 Form 10-K.  The following types of estimates, in our opinion, are subjective in nature, require the exercise of professional judgment and involve complex analysis:

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

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

valuation and amortization methods of customer relationships and estimated useful lives of qualifyingcontract-based intangible assets;

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

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

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

Other Items

Parent-Subsidiary Guarantor Relationship

The Partnership (the “Parent Guarantor”) has guaranteed the payment of principal and interest on the consolidated debt obligations of EPO (the “Subsidiary Issuer”), with the exception of the remaining debt obligations of TEPPCO Partners, L.P. (collectively, the “Guaranteed Debt”).  If EPO were to default on any of its Guaranteed Debt, the Partnership would be responsible for full and unconditional repayment of such obligations. At September 30, 2021, the total amount of Guaranteed Debt was $30.03 billion, which was comprised of $27.17 billion of EPO’s senior notes, $2.63 billion of EPO’s junior subordinated notes and $225.1 million of related accrued interest.

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

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

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

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

In accordance with Rule 13.01 of Regulation S-X, the summarized financial information of the Obligor Group excludes the Obligor Group’s equity in income and investments in the consolidated subsidiaries of EPO that are not party to the guarantee obligations (the “Non-Obligor Subsidiaries”). The total carrying value of the Obligor Group’s investments in the Non-Obligor Subsidiaries was $45.62 billion at September 30, 2021. The Obligor Group’s equity in the earnings of the Non-Obligor Subsidiaries for the nine months ended September 30, 2021 was $3.15 billion. Although the net assets and earnings of the Non-Obligor Subsidiaries are not directly available to the holders of the Guaranteed Debt to satisfy the repayment of such obligations, there are no significant restrictions on the ability of the Non-Obligor Subsidiaries to pay distributions or make loans to EPO or the Partnership.  EPO exercises control over the Non-Obligor Subsidiaries. We continue to believe that the unaudited condensed consolidated financial statements of the Partnership presented under Part I, Item 1 of this quarterly report provide a more appropriate view of our credit standing. Our investment grade credit ratings are based on the Partnership’s consolidated financial statements and not the Obligor Group’s financial information presented below.

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

Selected asset information: 
September 30,
2021
  
December 31,
2020
 
   Current receivables from Non-Obligor Subsidiaries $691.1  $775.4 
   Other current assets  8,233.5   5,805.7 
   Long-term receivables from Non-Obligor Subsidiaries  187.3   187.3 
   Other noncurrent assets, excluding investments in Non-Obligor Subsidiaries of $45.62 billion at September 30, 2021 and $45.98 billion at December 31, 2020
  8,678.3   8,198.5 
         
Selected liability information:        
   Current portion of Guaranteed Debt, including interest of $225.1 million at September 30, 2021 and $455.6 million at December 31, 2020
 $1,624.4  $1,780.6 
   Current payables to Non-Obligor Subsidiaries  1,403.3   1,129.0 
   Other current liabilities  5,928.9   3,858.6 
   Noncurrent portion of Guaranteed Debt, principal only  28,406.8   28,806.8 
   Noncurrent payables to Non-Obligor Subsidiaries  27.0   27.0 
   Other noncurrent liabilities  61.9   42.9 
         
Mezzanine equity of Obligor Group:        
   Preferred units $49.3  $49.3 








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

  
For the Nine
Months Ended
September 30,
2021
  
For the Twelve
Months Ended
December 31,
2020
 
Revenues from Non-Obligor Subsidiaries $10,939.8  $2,602.4 
Revenues from other sources  10,303.6   15,361.4 
Operating income of Obligor Group  1,461.6   1,069.7 
Net income (loss) of Obligor Group excluding equity in earnings of Non-Obligor Subsidiaries of $3.15 billion for the nine months ended September 30, 2021 and $3.54 billion for the twelve months ended December 31, 2020
  457.6   (157.0)

Contractual Obligations

We have contractual future product purchase commitments for natural gas, NGLs, crude oil, petrochemicals and refined products.  These commitments representproducts representing enforceable and legally binding agreements as of the reporting date. Our product purchase commitments at September 30, 2020 declined by an estimated $6.3increased from $14.8 billion when compared to those reported in our 2019 Form 10-K primarily due to lower NGL and crude oil prices sinceat December 31, 2019.

2020 to $The principal amount of our consolidated debt obligations were 22.1$30.1 billion at September 30, 2020 compared2021 primarily due to $27.88 billion at December 31, 2019.  See “Liquidityan increase in crude oil and Capital Resources – Consolidated Debt” within this Part I, Item 2 for information regarding EPO’s senior notes offerings during 2020.NGL prices between the two reporting dates.

Off-Balance Sheet Arrangements

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

Related Party Transactions

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


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ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK.

General

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

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

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

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

the hedged forecasted transaction occurs within the expected time period.

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

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

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Commodity Hedging Activities

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

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

 Volume (1)Accounting
Derivative Purpose
Current (2)
Long-Term (2)
Treatment
Derivatives designated as hedging instruments:   
Natural gas processing:   
Forecasted natural gas purchases for plant thermal reduction (billion cubic feet (“Bcf”))7.4n/aCash flow hedge
Forecasted sales of NGLs (million barrels (“MMBbls”)) (3)1.1n/aCash flow hedge
Octane enhancement:   
Forecasted purchase of NGLs (MMBbls)0.3n/aCash flow hedge
Forecasted sales of octane enhancement products (MMBbls)1.2n/aCash flow hedge
Natural gas marketing:   
Natural gas storage inventory management activities (Bcf)5.2n/aFair value hedge
NGL marketing:   
Forecasted purchases of NGLs and related hydrocarbon products (MMBbls)143.35.6Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products (MMBbls)179.716.6Cash flow hedge
NGLs inventory management activities (MMBbls)0.80.7Fair value hedge
Refined products marketing:   
Forecasted purchases of refined products (MMBbls)46.88.1Cash flow hedge
Forecasted sales of refined products (MMBbls)54.011.5Cash flow hedge
Refined products inventory management activities (MMBbls)0.1n/aFair value hedge
Crude oil marketing:   
Forecasted purchases of crude oil (MMBbls)51.0n/aCash flow hedge
Forecasted sales of crude oil (MMBbls)65.2n/aCash flow hedge
Petrochemical marketing:   
Forecasted sales of petrochemical products (MMBbls)0.3n/aCash flow hedge
Derivatives not designated as hedging instruments:   
Natural gas risk management activities (Bcf) (4)37.90.7Mark-to-market
NGL risk management activities (MMBbls) (4)26.410.8Mark-to-market
Refined products risk management activities (MMBbls) (4)4.0n/aMark-to-market
Crude oil risk management activities (MMBbls) (4)19.55.9Mark-to-market

(1)Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes.
(2)The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is December 2022, December 2021 and December 2022, respectively.
(3)Forecasted NGL sales volumes under natural gas processing exclude 0.3 MMBbls of additional hedges executed under contracts that have been designated as normal sales agreements.
(4)Reflects the use of derivative instruments to manage risks associated with our transportation, processing and storage assets.

At September 30, 2020,2021, our predominant commodity hedging strategies consisted of (i) hedging anticipated future purchases and sales of commodity products associated with transportation, storage and blending activities, (ii) hedging the fair value of commodity products held in inventory and (iii) hedging natural gas processing margins.  

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TableFor a summary of Contents

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

Sensitivity Analysis

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

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

Natural gas marketing portfolio
  Portfolio Fair Value at   Portfolio Fair Value at 
Scenario
Resulting
Classification
December 31,
2019
 
September 30,
2020
 
October 15,
2020
 
Resulting
Classification
December 31,
2020
 
September 30,
2021
 
October 15,
2021
 
Fair value assuming no change in underlying commodity pricesAsset (Liability) $1.1  $6.6  $(2.5)Asset (Liability) $3.7  $(3.1) $0.2 
Fair value assuming 10% increase in underlying commodity pricesAsset (Liability)  (4.3)  3.5   (6.5)Asset (Liability)  2.6   (4.8)  (1.1)
Fair value assuming 10% decrease in underlying commodity pricesAsset (Liability)  6.6   9.7   1.6 Asset (Liability)  4.9   (1.4)  1.6 

NGL and refined products marketing, natural gas processing and octane enhancement portfolio
  Portfolio Fair Value at   Portfolio Fair Value at 
Scenario
Resulting
Classification
December 31,
2019
 
September 30,
2020
 
October 15,
2020
 
Resulting
Classification
December 31,
2020
 
September 30,
2021
 
October 15,
2021
 
Fair value assuming no change in underlying commodity pricesAsset (Liability) $43.7  $(255.4) $(298.3)Asset (Liability) $(388.2) $(399.8) $(371.8)
Fair value assuming 10% increase in underlying commodity pricesAsset (Liability)  (19.0)  (394.1)  (437.2)Asset (Liability)  (521.0)  (413.6)  (381.2)
Fair value assuming 10% decrease in underlying commodity pricesAsset (Liability)  106.4   (116.6)  (159.3)Asset (Liability)  (255.4)  (386.1)  (362.3)

Crude oil marketing portfolio
   Portfolio Fair Value at 
Scenario
Resulting
Classification
December 31,
2019
 
September 30,
2020
 
October 15,
2020
 
Fair value assuming no change in underlying commodity pricesAsset (Liability) $(9.6) $(108.0) $(115.4)
Fair value assuming 10% increase in underlying commodity pricesAsset (Liability)  (50.6)  (179.1)  (190.3)
Fair value assuming 10% decrease in underlying commodity pricesAsset (Liability)  31.5   (37.0)  (40.5)

At September 30, 2020, our commodity hedging strategies exhibited in the stress test values were mainly attributable to contango positions in our NGL, refined products and crude oil marketing portfolios.

The decrease in fair value of our commodity hedging portfolios from September 30, 2020 to October 15, 2020 is primarily due to an increase in the underlying commodity prices.  In general, we expect that any loss on these derivative instruments would be offset by gains recognized at settlement on the physical transactions.

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   Portfolio Fair Value at 
Scenario
Resulting
Classification
December 31,
2020
 
September 30,
2021
 
October 15,
2021
 
Fair value assuming no change in underlying commodity pricesAsset (Liability) $(184.3) $(71.0) $(127.6)
Fair value assuming 10% increase in underlying commodity pricesAsset (Liability)  (266.5)  (136.6)  (200.9)
Fair value assuming 10% decrease in underlying commodity pricesAsset (Liability)  (102.1)  (5.5)  (54.3)

Interest Rate Hedging Activities

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

Sensitivity Analysis

At September 30, 2020,As a result of market conditions in March 2021, we terminated our interest rate hedging portfolio consisted of forward-starting swaps. Forward-starting swaps hedge the risk of an increase in underlying benchmark interest rates during the period of time between the inception date of the swap agreement and the future date of a debt issuance. Under the terms of the forward-starting swaps, we pay to the counterparties (at the expected settlement dates of the instruments) amounts based on a fixed interest rate applied to a notional amount and receive from the counterparties an amount equal to a variable interest rate (based on LIBOR or an equivalent index rate) on the same notional amount.

With respect to the tabular data below, the portfolio’s estimated economic value at a given date is based on a number of factors, including the number and types of derivatives outstanding at that date, the notional value of the swaps and associated interest rates.  The following table summarizes ourentire portfolio of forward-starting swaps, at September 30, 2020 (dollarsrepresenting an aggregate $1.08 billion in millions):

Hedged Transaction
Number and Type
of Derivatives
Outstanding
Notional
Amount
Expected
Settlement
Date
Weighted-Average
Fixed Rate
Locked
Accounting
Treatment
Future long-term debt offering1 forward-starting swap$75.04/20212.41%Cash flow hedge
Future long-term debt offering5 forward-starting swaps$500.04/2021
2.13%
Cash flow hedge
Future long-term debt offering2 forward-starting swaps (1)$150.02/20221.72%Cash flow hedge
Future long-term debt offering1 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 during the first quarternotional value.  As of 2020.

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

   
Forward-Starting Swap
Portfolio Fair Value at
 
Scenario
Resulting
Classification
December 31,
2019
 
September 30,
2020
 
October 15,
2020
 
Fair value assuming no change in underlying interest ratesAsset (Liability) $(13.5) $(187.9) $(170.2)
Fair value assuming 10% increase in underlying interest ratesAsset (Liability)  38.2   (154.5)  (135.7)
Fair value assuming 10% decrease in underlying interest ratesAsset (Liability)  (68.3)  (222.4)  (206.0)

The increase in fair value of ourthis quarterly report, we do not have any interest rate hedging portfolio from September 30, 2020 to October 15, 2020 was primarily due to an increase in market interest rates relative to the fixed rates specified in the swap agreements.  Upon settlement, we would expect that any loss on these swaps would be offset by lower interest rates on future debt issuances.


derivative instruments outstanding.
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ITEM 4.  CONTROLS AND PROCEDURES.

Disclosure Controls and Procedures

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

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

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

Changes in Internal Control over Financial Reporting

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


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

Section 302 and 906 Certifications

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


PART II.  OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS.

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

In July 2020, we received a Proposed Agreed Order from the Texas Commission on Environmental Quality for alleged excess emissions at our Mont Belvieu facility.  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 financial statements.

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

On occasion, we are assessed monetary penalties by reference intogovernmental authorities related to administrative or judicial proceedings involving environmental matters.  In July 2021, we received a civil penalty demand from the U.S. Department of Justice and the State of Colorado regarding alleged violations of hydrocarbon leak detection and repair regulations applicable to our Meeker gas processing plant in Colorado.  The eventual resolution of this Part II, Item 1.matter may result in monetary sanctions in excess of $0.3 million; however, we do not expect such expenditures to be material to our consolidated financial statements.



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ITEM 1A.  RISK FACTORS.

An investment in our securities involves certain risks. Security holders and potential investors in our securities should carefully consider the risks described under “Risk Factors”“Risk Factors” set forth in Part I, Item 1A of our 20192020 Form 10-K, in addition to other information in such annual report and this quarterly report (including the additional risk factor set forth below).report.  The risk factors set forth in our 20192020 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 COVID-19 pandemic 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.

Changes in the supply of and demand for hydrocarbon products impacts both the volume of products that we sell and the level of services that we provide to customers, which in turn has a direct impact on our financial position, results of operations and cash flows. The global effects of the COVID-19 pandemic, including the consequences of international COVID-19 containment measures (e.g., quarantines, travel restrictions, temporary business closures and similar protective actions), reduced near-term demand for hydrocarbon products in 2020 by record amounts causing a significant oversupply situation.  Also, in the early stages of the pandemic, disputes between members of the OPEC+ group over crude oil production levels led to unprecedented volatility in the global energy markets and a historic collapse in crude oil prices.  Although the OPEC+ group and other producers subsequently reached agreements to gradually reduce the oversupply of crude oil through production cuts, the downturn in the energy industry caused by lower prices and demand negatively impacted us, the producers we work with and our other customers to varying degrees.

Across the globe, many countries have begun to ease their COVID-19 containment measures and central banks and governments have instituted fiscal measures in an effort to stimulate economic activity.  As a result, hydrocarbon demand has started to recover; however, a continuation of this trend remains dependent on successful containment of the disease and the development of approved vaccines or proven therapeutics. 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 on 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 impact of the pandemic on our financial condition, results of operations and cash flows depends largely on developments outside our control, including the duration of the outbreak and the related impact on overall economic activity, all of which cannot be predicted with certainty.  To the extent the pandemic adversely affects our financial condition, results of operations and cash flows, 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 IssuancesIssuance of Unregistered Securities

On September 30, 2020, the Partnership issued and sold an aggregateHolders of 50,000our Series A Cumulative Convertible Preferred Units inare entitled to receive cumulative quarterly distributions at a private placement transaction.  The stated valuerate of each preferred unit is $1,0007.25% per unit.  The total offering price forannum. We may satisfy our obligation to pay distributions to the preferred unitholders through the issuance, in whole or in part, of additional preferred units was $50.0 million, of which $32.5 million was received(referred to as paid-in-kind or “PIK” distributions), with the remainder in cash, withsubject to certain rights of a holder to elect all cash and other conditions as described in our partnership agreement.

The Partnership made quarterly PIK distributions to preferred unitholders in the remaining $17.5 million funded throughfirst, second and third quarters of 2021 of an aggregate 15,931, 15,940 and 16,229 preferred units, respectively.  With the exchangeexception of 1,120,588274 preferred units distributed in the first quarter of the Partnership’s common units owned by the purchasers.  Cash proceeds from the preferred unit offering include $15.0 million received from2021 to a privately held affiliate of EPCO for the purchase of 15,000 preferred units.

Concurrently, the Partnership exchangedaffiliate, all of the 54,807,352 Partnership commonPIK distributions made during the nine months ended September 30, 2021 were to OTA. The preferred units owned directlyheld by OTA are accounted for 855,915 of the Partnership’s new preferredas treasury units having an equivalent value.in consolidation.  For additional information regarding the preferred units, see Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

The issuance and saleissuances of the preferred units as described above,PIK distributions during the three and nine months ended September 30, 2021 were undertaken in reliance upon exemptionsan exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) and Section 3(a)(9) thereof.

Other than as described above, there were no sales of unregistered equity securities during the three months ended September 30, 2020.third quarter of 2021.

Issuer Purchases of Equity Securities

The following table summarizes the Partnership’sour equity repurchase activity during the third quarter of 2020:2021:

Period 
Total
Number of Common Units
Purchased
  
Average
Price Paid
per Common
Unit
 
Total
Number of
Common Units
Purchased
as Part of
2019 Buyback
Program
 
Remaining
Dollar
Amount of
Common Units
That May
Be Purchased
Under the 2019 Buyback
Program
($ thousands)
 
2019 Buyback Program: (1)          
   July 2020  –  $–   $1,778,911 
   August 2020  749,057  $17.66   $1,765,684 
   September 2020  1,235,450  $16.49   $1,745,312 
Vesting of phantom unit awards:             
   August 2020 (2)  23,903  $17.65 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)            
   July 2021  –  $–   –  $1,718,911 
   August 2021  2,633,836  $22.29   2,633,836  $1,660,191 
   September 2021  733,541  $21.90   733,541  $1,644,128 
Vesting of phantom unit awards:                
   July 2021  –  $–   n/a   n/a 
   August 2021 (2)  41,555  $22.37   n/a   n/a 
   September 2021  –  $–   n/a   n/a 

(1)In January 2019, we announced the 2019 Buyback Program, which authorized the repurchase of up to $2 billion of the Partnership’sEPD’s common units.  Common unitsUnits repurchased under this program during 2020 wereare cancelled immediately upon acquisition.
(2)
Of the 112,794 157,220 phantom unit awards that vested in August 20202021 and converted to common units, 23,90341,555 units were sold back to the Partnershipus by employees to cover related withholding tax requirements. These repurchases are not part of any announced program.  We cancelled these units immediately upon acquisition.


ITEM 3.  DEFAULTS UPON SENIOR SECURITIES.

None.


ITEM 4.  MINE SAFETY DISCLOSURES.

Not applicable.
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ITEM 5.  OTHER INFORMATION.


None.


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).

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2.11
Agreement and Plan of Merger, dated as of April 28, 2011, by and among Enterprise Products Partners L.P., Enterprise Products Holdings LLC, EPD MergerCo LLC, Duncan Energy Partners L.P. and DEP Holdings, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed April 29, 2011).

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2.12
Contribution and Purchase Agreement, dated as of October 1, 2014, by and among Enterprise Products Partners L.P., Oiltanking Holding Americas, Inc. and OTB Holdco, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed October 1, 2014).
2.13
Agreement and Plan of Merger, dated as of November 11, 2014, by and among Enterprise Products Partners L.P., Enterprise Products Holdings LLC, EPOT MergerCo LLC, Oiltanking Partners, L.P. and OTLP GP, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed November 12, 2014).
2.14
Amendment No. 1 dated as of June 6, 2018 to Contribution and Purchase Agreement, by and among Enterprise Products Partners L.P., Oiltanking Holding Americas, Inc., Enterprise Products Holdings LLC and Marquard & Bahls, AG (incorporated by reference to Exhibit 2.2 to Form 8-K filed June 12, 2018).
3.1
Certificate of Limited Partnership of Enterprise Products Partners L.P. (incorporated by reference to Exhibit 3.6 to Form 10-Q filed November 9, 2007).
3.2
Certificate of Amendment to Certificate of Limited Partnership of Enterprise Products Partners L.P., filed on November 22, 2010 with the Delaware Secretary of State (incorporated by reference to Exhibit 3.6 to Form 8-K filed November 23, 2010).
3.3
Seventh Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated as of September 30, 2020 (incorporated by reference to Exhibit 3.1 to Form 8-K filed October 1, 2020).
3.4
Certificate of Formation of Enterprise Products Holdings LLC (formerly named EPE Holdings, LLC) (incorporated by reference to Exhibit 3.3 to Form S-1/A Registration Statement, Reg. No. 333-124320, filed by Enterprise GP Holdings L.P. on July 22, 2005).
3.5
Certificate of Amendment to Certificate of Formation of Enterprise Products Holdings LLC (formerly named EPE Holdings, LLC), filed on November 22, 2010 with the Delaware Secretary of State (incorporated by reference to Exhibit 3.5 to Form 8-K filed November 23, 2010).
3.6
Fifth Amended and Restated Limited Liability Company Agreement of Enterprise Products Holdings LLC dated effective as of September 7, 2011 (incorporated by reference to Exhibit 3.1 to Form 8-K filed September 8, 2011).
3.7
Amendment No. 1 to Fifth Amended and Restated Limited Liability Company Agreement of Enterprise Products Holdings LLC, dated effective as of April 26, 2017 (incorporated by reference to Exhibit 3.1 to Form 8-K filed May 2, 2017).
3.8
Amendment No. 2 to Fifth Amended and Restated Limited Liability Company Agreement of Enterprise Products Holdings LLC, dated effective as of November 6, 2019 (incorporated by reference to Exhibit 3.12 to Form 10-Q filed November 8, 2019).
3.9
Company Agreement of Enterprise Products Operating LLC dated June 30, 2007 (incorporated by reference to Exhibit 3.3 to Form 10-Q filed August 8, 2007).
3.10
Certificate of Incorporation of Enterprise Products OLPGP, Inc., dated December 3, 2003 (incorporated by reference to Exhibit 3.5 to Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).
3.11
Bylaws of Enterprise Products OLPGP, Inc., dated December 8, 2003 (incorporated by reference to Exhibit 3.6 to Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).
4.1
Form of Common Unit certificate (incorporated by reference to Exhibit A to Exhibit 3.1 to Form 8-K filed October 1, 2020).
4.2
Description of the Registrant’s Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934 (incorporated by reference to Exhibit 4.2 to Form 10-K filed February 28, 2020).

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4.3
Indenture, dated as of March 15, 2000, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and First Union National Bank, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed March 14, 2000).
4.4
Second Supplemental Indenture, dated as of February 14, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 10-K filed March 31, 2003).
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4.5
Third Supplemental Indenture, dated as of June 30, 2007, among Enterprise Products Operating L.P., as Original Issuer, Enterprise Products Partners L.P., as Parent Guarantor, Enterprise Products Operating LLC, as New Issuer, and U.S. Bank National Association, as successor Trustee (incorporated by reference to Exhibit 4.55 to Form 10-Q filed August 8, 2007).
4.6
Indenture, dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed October 6, 2004).
4.7
Fourth Supplemental Indenture, dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.5 to Form 8-K filed October 6, 2004).
4.8
Sixth Supplemental Indenture, dated as of March 2, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed March 3, 2005).
4.9
Tenth Supplemental Indenture, dated as of June 30, 2007, among Enterprise Products Operating L.P., as Original Issuer, Enterprise Products Partners L.P., as Parent Guarantor, Enterprise Products Operating LLC, as New Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.54 to Form 10-Q filed August 8, 2007).
4.10
Thirteenth Supplemental Indenture, dated as of April 3, 2008, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed April 3, 2008).
4.11
Sixteenth Supplemental Indenture, dated as of October 5, 2009, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed October 5, 2009).
4.124.11
Seventeenth Supplemental Indenture, dated as of October 27, 2009, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed October 28, 2009).
4.134.12
 
Eighteenth Supplemental Indenture, dated as of October 27, 2009, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed October 28, 2009).
4.144.13
Nineteenth Supplemental Indenture, dated as of May 20, 2010, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed May 20, 2010).
4.154.14
Twentieth Supplemental Indenture, dated as of January 13, 2011, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed January 13, 2011).
4.164.15
Twenty-First Supplemental Indenture, dated as of August 24, 2011, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed August 24, 2011).

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4.174.16
Twenty-Second Supplemental Indenture, dated as of February 15, 2012, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.25 to Form 10-Q filed May 10, 2012).

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4.184.17
Twenty-Third Supplemental Indenture, dated as of August 13, 2012, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed August 13, 2012).
4.194.18
Twenty-Fourth Supplemental Indenture, dated as of March 18, 2013, 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 March 18, 2013).
4.204.19
Twenty-Fifth Supplemental Indenture, dated as of February 12, 2014, 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 February 12, 2014).
4.214.20
Twenty-Sixth Supplemental Indenture, dated as of October 14, 2014, 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 October 14, 2014).
4.224.21
Twenty-Seventh Supplemental Indenture, dated as of May 7, 2015, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed May 7, 2015).
4.234.22
Twenty-Eighth Supplemental Indenture, dated as of April 13, 2016, 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 13, 2016).
4.244.23
Twenty-Ninth Supplemental Indenture, dated as of August 16, 2017, 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 16, 2017).
4.254.24
Thirtieth Supplemental Indenture, dated as of February 15, 2018, 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 February 15, 2018).
4.264.25
Thirty-First Supplemental Indenture, dated as of February 15, 2018, 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 February 15, 2018).
4.274.26
Thirty-Second Supplemental Indenture, dated as of October 11, 2018, 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 11, 2018).
4.284.27
Thirty-Third Supplemental Indenture, dated as of July 8, 2019, 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 July 8, 2019).
4.294.28
Thirty-Fourth Supplemental Indenture, dated as of January 15, 2020, 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 15, 2020).

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4.304.29
Thirty-Fifth Supplemental Indenture, dated as of August 7, 2020, 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 August 7, 2020).

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Thirty-Sixth Supplemental Indenture, dated as of September 15, 2021, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, Wells Fargo Bank, National Association, as Original Trustee, and U.S. Bank National Association, as Series Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed September 15, 2021).



4.31
Form of Global Note representing $499.2 million principal amount of 6.875% Series B Senior Notes due 2033 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 10-K filed March 31, 2003).
4.32
Form of Global Note representing $350.0 million principal amount of 6.65% Series B Senior Notes due 2034 with attached Guarantee (incorporated by reference to Exhibit 4.19 to Form S-3 Registration Statement, Reg. No. 333-123150, filed March 4, 2005).
4.33
Form of Global Note representing $250.0 million principal amount of 5.75% Series B Senior Notes due 2035 with attached Guarantee (incorporated by reference to Exhibit 4.32 to Form 10-Q filed November 4, 2005).
4.34
Form of Global Note representing $700.0 million principal amount of 6.50% Senior Notes due 2019 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.4 to Form 8-K filed April 3, 2008).
4.35
Form of Global Note representing $500.0 million principal amount of 5.25% Senior Notes due 2020 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed October 5, 2009).
4.364.35
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).
4.374.36
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).
4.384.37
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).
4.394.38
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).
4.404.39
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).
4.414.40
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).
4.424.41
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).
4.434.42
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).
4.444.43
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).
4.454.44
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).

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4.464.45
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).
4.474.46
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).
4.484.47
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).
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4.494.48
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).
4.50
Form of Global Note representing $800.0 million principal amount of 2.55% Senior Notes due 2019 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.4 to Form 8-K filed October 14, 2014).
4.514.49
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).
4.524.50
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).
4.534.51
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).
4.544.52
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).
4.554.53
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).
4.564.54
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).
4.574.55
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).
4.584.56
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).
4.594.57
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).
4.604.58
Form of Global Note representing $1.0 billion principal amount of Junior Subordinated Notes E due 2077 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed August 16, 2017).
4.614.59
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).
4.624.60
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).
4.634.61
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).

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4.644.62
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).
4.654.63
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).
4.664.64
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).
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4.674.65
Form of Global Note representing $1,250.0 million principal amount of 3.125% Senior Notes due 2029 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed July 8, 2019).
4.684.66
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).
4.694.67
Form of Global Note representing $1,000.0 million principal amount of 2.800% Senior Notes due 2030 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed January 15, 2020).
4.704.68
Form of Global Note representing $1,000.0 million principal amount of 3.700% Senior Notes due 2051 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed January 15, 2020).
4.714.69
Form of Global Note representing $1,000.0 million principal amount of 3.950% Senior Notes due 2060 with attached Guarantee (incorporated by reference to Exhibit C to Exhibit 4.3 to Form 8-K filed January 15, 2020).
4.724.70
Form of Global Note representing $250.0 million principal amount of 2.800% Senior Notes due 2030 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed January 15, 2020).
4.734.71
Form of Global Note representing $1,000.0 million principal amount of 3.200% Senior Notes due 2052 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.4 to Form 8-K filed August 7, 2020).
4.744.72
Form of Global Note representing $1,000.0 million principal amount of 3.300% Senior Notes due 2053 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed September 15, 2021).
4.73
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).
4.754.74
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).
4.764.75
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).
4.774.76
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).

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4.784.77
Full Release of Guarantee, dated July 31, 2006, by Wachovia Bank, National Association, as Trustee, in favor of Jonah Gas Gathering Company (incorporated by reference to Exhibit 4.8 to the Form 10-Q filed by TEPPCO Partners, L.P. on November 7, 2006).
4.794.78
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).
4.804.79
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).

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4.814.80
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).
4.824.81
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).
4.834.82
First Supplemental Indenture, dated May 18, 2007, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and The Bank of New York Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.2 to the Form 8-K filed by TEPPCO Partners, L.P. on May 18, 2007).
4.844.83
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).
4.854.84
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).
4.864.85
Full Release of Guarantee, dated as of November 23, 2009, of TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P. by The Bank of New York Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.70 to Form 10-K filed March 1, 2010).
4.874.86
Registration Rights Agreement, dated as of March 5, 2020, between Enterprise Products Partners L.P. and Skyline North Americas, Inc. (incorporated by reference to Exhibit 4.1 to Form 8-K filed March 5, 2020).
4.884.87
Equity Distribution Agreement, dated June 24, 2020, by and among Enterprise Products Partners L.P., Enterprise Products OLPGP, Inc., Enterprise Products Operating LLC, Skyline North Americas, Inc. and Morgan Stanley & Co. LLC. (incorporated by reference to Exhibit 1.1 to Form 8-K filed June 25, 2020).
4.894.88
Specimen Unit Certificate for the Series A Cumulative Convertible Preferred Units, (incorporated by reference to Exhibit B to Exhibit 3.1 to Form 8-K filed October 1, 2020).

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4.904.89
Registration Rights Agreement, dated as of September 30, 2020, by and among Enterprise Products Partners L.P. and the Purchasers party thereto.thereto (incorporated by reference to Exhibit 4.2 to Form 8-K filed October 1, 2020).
10.1
364-Day Revolving Credit Agreement, dated as of September 8, 20207, 2021, by and among Enterprise Products Operating LLC, as Borrower, the Lenders party thereto, and Citibank, N.A., as Administrative Agent, Wells Fargo Bank, National Association, JPMorgan Chase Bank, N.A., Mizuho Bank, Ltd., MUFG Bank, Ltd. and Truist Bank, as Co-Syndication Agents, and Barclays Bank PLC, Royal Bank of Canada, Sumitomo Mitsui Banking Corporation, The Bank of Nova Scotia, Houston Branch, and The Toronto-Dominion Bank, New York Branch, as Co-Documentation Agents (incorporated by reference to Exhibit 10.1 to Form 8-K filed September 11, 2020)7, 2021).
10.2
Guaranty Agreement, dated as of September 8, 2020,7, 2021, by Enterprise Products Partners L.P. in favor of Citibank, N.A., as Administrative Agentadministrative agent (incorporated by reference to Exhibit 10.2 to Form 8-K filed September 11, 2020)7, 2021).
10.3
Series A Cumulative Convertible Preferred Unit PurchaseRevolving Credit Agreement, dated as of September 30, 2020,7, 2021, by and among Enterprise Products Partners L.P. andOperating LLC, as Borrower, the PurchasersLenders party thereto, (incorporated by reference to Exhibit 10.1 to Form 8-K filed October 1, 2020).
10.4
Securities Exchange Agreement, datedWells Fargo Bank, National Association, as Administrative Agent, Citibank, N.A., JPMorgan Chase Bank, N.A., Mizuho Bank, Ltd., MUFG Bank, Ltd. and Truist Bank, as Co-Syndication Agents, and Barclays Bank PLC, Royal Bank of September 30, 2020, byCanada, Sumitomo Mitsui Banking Corporation, The Bank of Nova Scotia, Houston Branch, and between Enterprise Products Partners L.P. and OTA Holdings, Inc. (incorporated by reference to Exhibit 10.2 to Form 8-K filed October 1, 2020).
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10.5***
Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of EPD PubCo Unit II L.P., datedThe Toronto-Dominion Bank, New York Branch, as of September 30, 2020Co-Documentation Agents (incorporated by reference to Exhibit 10.3 to Form 8-K filed October 1, 2020)September 7, 2021).
10.6***10.4
Amendment No. 2 to First Amended and RestatedGuaranty Agreement, of Limited Partnership of EPD PrivCo Unit I L.P., dated as of September 30, 20207, 2021, by Enterprise Products Partners L.P. in favor of Wells Fargo Bank, National Association, as administrative agent (incorporated by reference to Exhibit 10.4 to Form 8-K filed October 1, 2020)September 7, 2021).
22.1#
List of Issuers of Debt Securities Guaranteed by Enterprise Products Partners L.P. and Associated Securities at September 30, 2021.
31.1#
Sarbanes-Oxley Section 302 certification of A. James Teague for Enterprise Products Partners L.P.’s quarterly report on Form 10-Q for the nine months ended September 30, 2020.2021.
31.2#
Sarbanes-Oxley Section 302 certification of W. Randall Fowler for Enterprise Products Partners L.P.’s quarterly report on Form 10-Q for the nine months ended September 30, 2020.2021.
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 nine months ended September 30, 2020.2021.
32.2#
Sarbanes-Oxley Section 906 certification of W. Randall Fowler for Enterprise Products Partners L.P.’s quarterly report on Form 10-Q for the nine months ended September 30, 2020.2021.
101#
Interactive data files pursuant to Rule 405 of Regulation S-T formatted in iXBRL (Inline Extensible Business Reporting Language) in this Form 10-Q includes:include the: (i) the Unaudited Condensed Consolidated Balance Sheets, (ii) the Unaudited Condensed Statements of Consolidated Operations, (iii) the Unaudited Condensed Statements of Consolidated Comprehensive Income, (iv) the Unaudited Condensed Statements of Consolidated Cash Flows, (v) the Unaudited Condensed Statements of Consolidated Equity and (vi) Notes to the Unaudited Condensed Consolidated Financial Statements.
104#Cover Page Interactive Data File (embedded within the Inline XBRLiXBRL 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 November 6, 2020.8, 2021.

  
ENTERPRISE PRODUCTS PARTNERS L.P.
(A Delaware Limited Partnership)
 
  By:Enterprise Products Holdings LLC, as General Partner
   
  By:/s/ R. Daniel Boss
  Name:R. Daniel Boss
  Title:Executive Vice President – Accounting, Risk Control and Information Technology of the General Partner
    
By:/s/ Michael W. Hanson
Name:Michael W. Hanson
Title:
Vice President and Principal Accounting Officer
of the General Partner


















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