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, 20182019


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:  1-14323001-14323


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


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



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

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

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


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


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


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


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


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


There were 2,182,661,5502,189,169,528 common units of Enterprise Products Partners L.P. outstanding at the close of business on October 31, 2018.  Our common units trade on the New York Stock Exchange under the ticker symbol “EPD.”2019. 

Table of Contents

ENTERPRISE PRODUCTS PARTNERS L.P.
TABLE OF CONTENTS


  Page No.
PART I.  FINANCIAL INFORMATION.
Item 1.
Financial Statements.
 
 
Unaudited Condensed Consolidated Balance Sheets
2
 
Unaudited Condensed Statements of Consolidated Operations
3
 
Unaudited Condensed Statements of Consolidated Comprehensive Income
4
 
Unaudited Condensed Statements of Consolidated Cash Flows
5
 
Unaudited Condensed Statements of Consolidated Equity
6
 
Notes to Unaudited Condensed Consolidated Financial Statements:
 
 
1.  Partnership Organization and Basis of Presentation
8
 
2.  Summary of Significant Accounting Policies
9
 
3.  Inventories
1210
 
4.  Property, Plant and Equipment
1311
 
5.  Investments in Unconsolidated Affiliates
1412
 
6.  Intangible Assets and Goodwill
1613
 
7.  Debt Obligations
1714
 
8.  Equity and Distributions
2017
 
9.  Revenues
2320
 
10.  Business Segments and Related Information
2621
 
11.  Business CombinationsEarnings Per Unit
2925
 
12.  Earnings Per UnitEquity-Based Awards
3025
 
13.  Equity-Based Awards
30
14.  Derivative Instruments, Hedging Activities and Fair Value Measurements
3327
14.  Related Party Transactions
34
 
15.  Related Party TransactionsCommitments and Contingencies
4035
 
16.  Commitments and ContingenciesSupplemental Cash Flow Information
4239
 
17.  Supplemental Cash Flow Information
45
18.  Condensed Consolidating Financial Information
464
19.  Subsequent Events
530
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations.
5447
Item 3.
Quantitative and Qualitative Disclosures About Market Risk.
8577
Item 4.
Controls and Procedures.
8881
   
PART II.  OTHER INFORMATION.
Item 1.
Legal Proceedings.
8981
Item 1A.
Risk Factors.
8982
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds.
8982
Item 3.
Defaults Upon Senior Securities.
8982
Item 4.
Mine Safety Disclosures.
9082
Item 5.
Other Information.
9082
Item 6.
Exhibits.
9083
   
Signatures
9992


1

Table of Contents

PART I.  FINANCIAL INFORMATION.


Item 1.
Financial Statements.
ITEM 1.  FINANCIAL STATEMENTS.


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


 
September 30,
2018
  
December 31,
2017
  
September 30,
2019
  
December 31,
2018
 
ASSETS            
Current assets:            
Cash and cash equivalents $30.2  $5.1  $1,207.8  $344.8 
Restricted cash  248.9   65.2   –   65.3 
Accounts receivable – trade, net of allowance for doubtful accounts
of $12.2 at September 30, 2018 and $12.1 at December 31, 2017
  4,222.9   4,358.4 
Accounts receivable – trade, net of allowance for doubtful accounts
of $11.3 at September 30, 2019 and $11.5 at December 31, 2018
  4,261.7   3,659.1 
Accounts receivable – related parties  1.6   1.8   2.0   3.5 
Inventories  2,335.8   1,609.8   1,644.7   1,522.1 
Derivative assets  236.6   153.4   166.0   154.4 
Prepaid and other current assets  609.9   312.7   631.6   311.5 
Total current assets  7,685.9   6,506.4   7,913.8   6,060.7 
Property, plant and equipment, net  37,802.9   35,620.4   40,763.3   38,737.6 
Investments in unconsolidated affiliates  2,603.4   2,659.4   2,660.9   2,615.1 
Intangible assets, net of accumulated amortization of $1,693.4 at
September 30, 2018 and $1,564.8 at December 31, 2017 (see Note 6)
  3,654.2   3,690.3 
Intangible assets, net of accumulated amortization of $1,647.1 at
September 30, 2019 and $1,735.1 at December 31, 2018 (see Note 6)
  3,489.4   3,608.4 
Goodwill (see Note 6)
  5,745.2   5,745.2   5,745.2   5,745.2 
Other assets  260.6   196.4   442.7   202.8 
Total assets $57,752.2  $54,418.1  $61,015.3  $56,969.8 
                
LIABILITIES AND EQUITY                
Current liabilities:                
Current maturities of debt (see Note 7) $3,405.5  $2,855.0  $2,300.0  $1,500.1 
Accounts payable – trade  1,153.2   801.7   1,057.8   1,102.8 
Accounts payable – related parties  136.2   127.3   125.5   140.2 
Accrued product payables  5,149.8   4,566.3   4,198.8   3,475.8 
Accrued interest  190.5   358.0   237.2   395.6 
Derivative liabilities  487.1   168.2   202.4   148.2 
Other current liabilities  400.0   418.6   547.8   404.8 
Total current liabilities  10,922.3   9,295.1   8,669.5   7,167.5 
Long-term debt (see Note 7)
  22,508.5   21,713.7   25,639.2   24,678.1 
Deferred tax liabilities  68.4   58.5   91.4   80.4 
Other long-term liabilities  747.2   578.4   1,089.7   751.6 
Commitments and contingencies (see Note 16)
        
Commitments and contingencies (see Note 15)
        
Equity: (see Note 8)
                
Partners’ equity:                
Limited partners:                
Common units (2,182,661,550 units outstanding at September 30, 2018
and 2,161,089,479 units outstanding at December 31, 2017)
  23,380.4   22,718.9 
Accumulated other comprehensive loss  (307.3)  (171.7)
Common units (2,189,169,528 units outstanding at September 30, 2019
and 2,184,869,029 units outstanding at December 31, 2018)
  24,535.1   23,802.6 
Accumulated other comprehensive income (loss)  (39.1)  50.9 
Total partners’ equity  23,073.1   22,547.2   24,496.0   23,853.5 
Noncontrolling interests  432.7   225.2   1,029.5   438.7 
Total equity  23,505.8   22,772.4   25,525.5   24,292.2 
Total liabilities and equity $57,752.2  $54,418.1  $61,015.3  $56,969.8 




See Notes to Unaudited Condensed Consolidated Financial Statements.
2
2
Table of Contents



ENTERPRISE
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,
 
 2018  2017  2018  2017  2019  2018  2019  2018 
Revenues:                        
Third parties $9,571.7  $6,874.4  $27,257.4  $20,781.7  $7,948.5  $9,571.7  $24,730.2  $27,257.4 
Related parties  14.2   12.5   94.5   33.2   15.6   14.2   53.7   94.5 
Total revenues (see Note 9)  9,585.9   6,886.9   27,351.9   20,814.9   7,964.1   9,585.9   24,783.9   27,351.9 
Costs and expenses:                                
Operating costs and expenses:                                
Third parties  7,643.4   5,773.8   22,722.0   17,313.0   6,217.6   7,643.4   19,342.4   22,722.0 
Related parties  358.5   306.0   1,054.6   830.2   356.1   358.5   1,051.9   1,054.6 
Total operating costs and expenses  8,001.9   6,079.8   23,776.6   18,143.2   6,573.7   8,001.9   20,394.3   23,776.6 
General and administrative costs:                                
Third parties  15.3   11.0   57.5   47.7   19.1   15.3   60.9   57.5 
Related parties  37.4   30.3   99.6   89.7   36.4   37.4   99.3   99.6 
Total general and administrative costs  52.7   41.3   157.1   137.4   55.5   52.7   160.2   157.1 
Total costs and expenses (see Note 10)  8,054.6   6,121.1   23,933.7   18,280.6   6,629.2   8,054.6   20,554.5   23,933.7 
Equity in income of unconsolidated affiliates  112.0   113.4   350.0   315.2   139.3   112.0   431.3   350.0 
Operating income  1,643.3   879.2   3,768.2   2,849.5   1,474.2   1,643.3   4,660.7   3,768.2 
Other income (expense):     ��                          
Interest expense  (279.5)  (243.9)  (806.2)  (739.0)
Change in fair market value of Liquidity Option
Agreement (see Note 16)
  (18.5)  (8.9)  (34.9)  (33.0)
Gain on step acquisition of unconsolidated affiliate (see Note 11)  --   --   39.4   -- 
Interest expense (see Note 13)  (382.9)  (279.5)  (950.2)  (806.2)
Change in fair market value of Liquidity Option
Agreement (see Note 15)
  (38.7)  (18.5)  (123.1)  (34.9)
Gain on step acquisition of unconsolidated affiliate (see Note 16)  –   –   –   39.4 
Other, net  0.3   0.3   1.3   0.9   7.6   0.3   11.7   1.3 
Total other expense, net  (297.7)  (252.5)  (800.4)  (771.1)  (414.0)  (297.7)  (1,061.6)  (800.4)
Income before income taxes  1,345.6   626.7   2,967.8   2,078.4   1,060.2   1,345.6   3,599.1   2,967.8 
Provision for income taxes  (11.0)  (5.4)  (34.5)  (20.1)  (15.4)  (11.0)  (37.4)  (34.5)
Net income  1,334.6   621.3   2,933.3   2,058.3   1,044.8   1,334.6   3,561.7   2,933.3 
Net income attributable to noncontrolling interests  (21.4)  (10.4)  (45.6)  (33.0)
Net income attributable to noncontrolling interests (see Note 8)  (25.6)  (21.4)  (67.3)  (45.6)
Net income attributable to limited partners $1,313.2  $610.9  $2,887.7  $2,025.3  $1,019.2  $1,313.2  $3,494.4  $2,887.7 
                                
Earnings per unit: (see Note 12)
                
Basic earnings per unit $0.60  $0.28  $1.32  $0.94 
Diluted earnings per unit $0.60  $0.28  $1.32  $0.94 
Earnings per unit: (see Note 11)
                
Basic and diluted earnings per unit $0.46  $0.60  $1.59  $1.32 





























See Notes to Unaudited Condensed Consolidated Financial Statements.
3
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,
 
 2018  2017  2018  2017  2019  2018  2019  2018 
                        
Net income $1,334.6  $621.3  $2,933.3  $2,058.3  $1,044.8  $1,334.6  $3,561.7  $2,933.3 
Other comprehensive income (loss):                                
Cash flow hedges:                
Commodity derivative instruments:                
Cash flow hedges: (see Note 13)                
Commodity hedging derivative instruments:                
Changes in fair value of cash flow hedges  (145.8)  (177.8)  (156.0)  (2.6)  72.3   (145.8)  58.6   (156.0)
Reclassification of gains to net income
  (53.5)  (10.1)  (28.8)  (49.0)  (91.5)  (53.5)  (152.0)  (28.8)
Interest rate derivative instruments:                
Interest rate hedging derivative instruments:                
Changes in fair value of cash flow hedges  6.1   (0.3)  20.7   (4.8)  (18.6)  6.1   (23.8)  20.7 
Reclassification of losses to net income
  9.1   10.3   29.0   29.9   9.4   9.1   27.8   29.0 
Total cash flow hedges  (184.1)  (177.9)  (135.1)  (26.5)  (28.4)  (184.1)  (89.4)  (135.1)
Other  --   --   (0.5)  (0.1)  –   –   (0.6)  (0.5)
Total other comprehensive loss
  (184.1)  (177.9)  (135.6)  (26.6)  (28.4)  (184.1)  (90.0)  (135.6)
Comprehensive income  1,150.5   443.4   2,797.7   2,031.7   1,016.4   1,150.5   3,471.7   2,797.7 
Comprehensive income attributable to noncontrolling interests  (21.4)  (10.4)  (45.6)  (33.0)  (25.6)  (21.4)  (67.3)  (45.6)
Comprehensive income attributable to limited partners $1,129.1  $433.0  $2,752.1  $1,998.7  $990.8  $1,129.1  $3,404.4  $2,752.1 
  


























































See Notes to Unaudited Condensed Consolidated Financial Statements.
4
4
Table of Contents



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


 
For the Nine Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
 2018  2017  2019  2018 
Operating activities:            
Net income $2,933.3  $2,058.3  $3,561.7  $2,933.3 
Reconciliation of net income to net cash flows provided by operating activities:                
Depreciation, amortization and accretion  1,360.5   1,221.4   1,456.7   1,330.8 
Asset impairment and related charges (see Note 14)  21.4   35.2 
Asset impairment and related charges  51.3   21.4 
Equity in income of unconsolidated affiliates  (350.0)  (315.2)  (431.3)  (350.0)
Distributions received on earnings from unconsolidated affiliates  345.7   316.2   431.2   345.7 
Net gains attributable to asset sales  (8.1)  (1.1)  (2.6)  (8.1)
Deferred income tax expense  9.3   1.1   10.9   9.3 
Change in fair market value of derivative instruments  254.9   (14.2)  2.0   254.9 
Change in fair market value of Liquidity Option Agreement  34.9   33.0   123.1   34.9 
Gain on step acquisition of unconsolidated affiliate (see Note 11)  (39.4)  -- 
Net effect of changes in operating accounts (see Note 17)  (261.9)  (512.1)
Gain on step acquisition of unconsolidated affiliate (see Note 16)  –   (39.4)
Net effect of changes in operating accounts (see Note 16)  (409.0)  (261.9)
Other operating activities  (25.3)  (2.7)  32.2   4.4 
Net cash flows provided by operating activities  4,275.3   2,819.9   4,826.2   4,275.3 
Investing activities:                
Capital expenditures  (3,004.2)  (2,118.2)  (3,302.1)  (3,004.2)
Cash used for business combinations, net of cash received (see Note 11)  (150.6)  (198.7)
Cash used for business combination (see Note 16)  –   (150.6)
Investments in unconsolidated affiliates  (95.1)  (32.8)  (100.1)  (95.1)
Distributions received for return of capital from unconsolidated affiliates  47.0   36.8   53.9   47.0 
Proceeds from asset sales  24.1   6.2   16.8   24.1 
Other investing activities  (4.0)  2.8   (41.3)  (4.0)
Cash used in investing activities  (3,182.8)  (2,303.9)  (3,372.8)  (3,182.8)
Financing activities:                
Borrowings under debt agreements  67,086.3   53,150.4   44,629.6   67,086.3 
Repayments of debt  (65,742.1)  (52,133.2)  (42,855.3)  (65,742.1)
Debt issuance costs  (25.2)  (24.0)  (26.3)  (25.2)
Cash distributions paid to limited partners (see Note 8)  (2,782.9)  (2,660.4)  (2,871.1)  (2,782.9)
Cash payments made in connection with distribution equivalent rights  (13.2)  (11.2)  (16.4)  (13.2)
Cash distributions paid to noncontrolling interests  (50.9)  (35.4)  (69.7)  (50.9)
Cash contributions from noncontrolling interests (see Note 8)  222.0   0.4 
Net cash proceeds from the issuance of common units (see Note 8)  449.4   877.2 
Cash contributions from noncontrolling interests  590.8   222.0 
Net cash proceeds from the issuance of common units  82.2   449.4 
Repurchase of common units under 2019 Buyback Program (see Note 8)  (81.1)  – 
Other financing activities  (27.1)  2.3   (38.4)  (27.1)
Cash used in financing activities
  (883.7)  (833.9)  (655.7)  (883.7)
Net change in cash and cash equivalents, including restricted cash  208.8   (317.9)  797.7   208.8 
Cash and cash equivalents, including restricted cash, at beginning of period  70.3   417.6   410.1   70.3 
Cash and cash equivalents, including restricted cash, at end of period $279.1  $99.7  $1,207.8  $279.1 





















See Notes to Unaudited Condensed Consolidated Financial Statements.
5
5
Table of Contents



ENTERPRISE
ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 20182019
(Dollars in millions)


 Partners’ Equity        Partners’ Equity       
For the Three Months Ended September 30, 2018: 
Limited
Partners
  
Accumulated
Other
Comprehensive
Income (Loss)
  
Noncontrolling
Interests
  Total 
Balance, June 30, 2018 $22,794.8  $(123.2) $418.9  $23,090.5 
For the Three Months Ended September 30, 2019: 
Limited
Partners
  
Accumulated
Other
Comprehensive
Income (Loss)
  
Noncontrolling
Interests
  Total 
Balance, June 30, 2019 $24,450.5  $(10.7) $535.6  $24,975.4 
Net income  1,313.2   --   21.4   1,334.6   1,019.2   –   25.6   1,044.8 
Cash distributions paid to limited partners  (935.6)  --   --   (935.6)  (963.2)  –   –   (963.2)
Cash payments made in connection with distribution equivalent rights  (4.6)  --   --   (4.6)  (5.9)  –   –   (5.9)
Cash distributions paid to noncontrolling interests  --   --   (22.6)  (22.6)  –   –   (22.8)  (22.8)
Cash contributions from noncontrolling interests  --   --   15.1   15.1   –   –   491.2   491.2 
Net cash proceeds from the issuance of common units  188.4   --   --   188.4   –   –   –   – 
Common units issued in connection with employee compensation  --   --   --   -- 
Common units issued in connection with land acquisition  --   --   --   -- 
Repurchase of common units under 2019 Buyback Program (see Note 8)  –   –   –   – 
Amortization of fair value of equity-based awards  24.9   --   --   24.9   36.7   –   –   36.7 
Cash flow hedges  --   (184.1)  --   (184.1)  –   (28.4)  –   (28.4)
Other  (0.7)  --   (0.1)  (0.8)  (2.2)  –   (0.1)  (2.3)
Balance, September 30, 2018 $23,380.4  $(307.3) $432.7  $23,505.8 
Balance, September 30, 2019 $24,535.1  $(39.1) $1,029.5  $25,525.5 




 Partners’ Equity        Partners’ Equity       
For the Nine Months Ended September 30, 2018: 
Limited
Partners
  
Accumulated
Other
Comprehensive
Income (Loss)
  
Noncontrolling
Interests
  Total 
Balance, December 31, 2017 $22,718.9  $(171.7) $225.2  $22,772.4 
For the Nine Months Ended September 30, 2019: 
Limited
Partners
  
Accumulated
Other
Comprehensive
Income (Loss)
  
Noncontrolling
Interests
  Total 
Balance, December 31, 2018 $23,802.6  $50.9  $438.7  $24,292.2 
Net income  2,887.7   --   45.6   2,933.3   3,494.4   –   67.3   3,561.7 
Cash distributions paid to limited partners  (2,782.9)  --   --   (2,782.9)  (2,871.1)  –   –   (2,871.1)
Cash payments made in connection with distribution equivalent rights  (13.2)  --   --   (13.2)  (16.4)  –   –   (16.4)
Cash distributions paid to noncontrolling interests  --   --   (50.9)  (50.9)  –   –   (69.7)  (69.7)
Cash contributions from noncontrolling interests  --   --   222.0   222.0   –   –   590.8   590.8 
Net cash proceeds from the issuance of common units  449.4   --   --   449.4   82.2   –   –   82.2 
Common units issued in connection with employee compensation  39.1   --   --   39.1   45.6   –   –   45.6 
Common units issued in connection with land acquisition  30.0   --   --   30.0 
Repurchase of common units under 2019 Buyback Program  (81.1)  –   –   (81.1)
Amortization of fair value of equity-based awards  77.5   --   --   77.5   107.2   –   –   107.2 
Cash flow hedges  --   (135.1)  --   (135.1)  –   (89.4)  –   (89.4)
Other  (26.1)  (0.5)  (9.2)  (35.8)  (28.3)  (0.6)  2.4   (26.5)
Balance, September 30, 2018 $23,380.4  $(307.3) $432.7  $23,505.8 
Balance, September 30, 2019 $24,535.1  $(39.1) $1,029.5  $25,525.5 

































See Notes to Unaudited Condensed Consolidated Financial Statements.  For information regarding Unit History,
Accumulated Other Comprehensive Income (Loss) and Noncontrolling Interests, see Note 8.
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ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 20172018
(Dollars in millions)


 Partners’ Equity        Partners’ Equity       
For the Three Months Ended September 30, 2017: 
Limited
Partners
  
Accumulated
Other
Comprehensive
Income (Loss)
  
Noncontrolling
Interests
  Total 
Balance, June 30, 2017 $22,788.8  $(128.7) $220.1  $22,880.2 
For the Three Months Ended September 30, 2018: 
Limited
Partners
  
Accumulated
Other
Comprehensive
Income (Loss)
  
Noncontrolling
Interests
  Total 
Balance, June 30, 2018 $22,794.8  $(123.2) $418.9  $23,090.5 
Net income  610.9   --   10.4   621.3   1,313.2   –   21.4   1,334.6 
Cash distributions paid to limited partners  (902.6)  --   --   (902.6)  (935.6)  –   –   (935.6)
Cash payments made in connection with distribution equivalent rights  (4.0)  --   --   (4.0)  (4.6)  –   –   (4.6)
Cash distributions paid to noncontrolling interests  --   --   (12.3)  (12.3)  –   –   (22.6)  (22.6)
Cash contributions from noncontrolling interests  --   --   0.1   0.1   –   –   15.1   15.1 
Net cash proceeds from the issuance of common units  120.0   --   --   120.0   188.4   –   –   188.4 
Common units issued in connection with employee compensation  --   --   --   -- 
Amortization of fair value of equity-based awards  24.3   --   --   24.3   24.9   –   –   24.9 
Cash flow hedges  --   (177.9)  --   (177.9)  –   (184.1)  –   (184.1)
Other  (0.2)  --   --   (0.2)  (0.7)  –   (0.1)  (0.8)
Balance, September 30, 2017 $22,637.2  $(306.6) $218.3  $22,548.9 
Balance, September 30, 2018 $23,380.4  $(307.3) $432.7  $23,505.8 




 Partners’ Equity        Partners’ Equity       
For the Nine Months Ended September 30, 2017: 
Limited
Partners
  
Accumulated
Other
Comprehensive
Income (Loss)
  
Noncontrolling
Interests
  Total 
Balance, December 31, 2016 $22,327.0  $(280.0) $219.0  $22,266.0 
For the Nine Months Ended September 30, 2018: 
Limited
Partners
  
Accumulated
Other
Comprehensive
Income (Loss)
  
Noncontrolling
Interests
  Total 
Balance, December 31, 2017 $22,718.9  $(171.7) $225.2  $22,772.4 
Net income  2,025.3   --   33.0   2,058.3   2,887.7   –   45.6   2,933.3 
Cash distributions paid to limited partners  (2,660.4)  --   --   (2,660.4)  (2,782.9)  –   –   (2,782.9)
Cash payments made in connection with distribution equivalent rights  (11.2)  --   --   (11.2)  (13.2)  –   –   (13.2)
Cash distributions paid to noncontrolling interests  --   --   (35.4)  (35.4)  –   –   (50.9)  (50.9)
Cash contributions from noncontrolling interests  --   --   0.4   0.4   –   –   222.0   222.0 
Net cash proceeds from the issuance of common units  877.2   --   --   877.2   449.4   –   –   449.4 
Common units issued in connection with employee compensation  33.7   --   --   33.7   39.1   –   –   39.1 
Common units issued in connection with land acquisition  30.0   –   –   30.0 
Amortization of fair value of equity-based awards  74.1   --   --   74.1   77.5   –   –   77.5 
Cash flow hedges  --   (26.5)  --   (26.5)  –   (135.1)  –   (135.1)
Other  (28.5)  (0.1)  1.3   (27.3)  (26.1)  (0.5)  (9.2)  (35.8)
Balance, September 30, 2017 $22,637.2  $(306.6) $218.3  $22,548.9 
Balance, September 30, 2018 $23,380.4  $(307.3) $432.7  $23,505.8 



































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


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


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


Unless the context requires otherwise, references to “we,” “us,” “our,”“our” or “Enterprise” or “Enterprise Products Partners” are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries.  References to “EPD” mean Enterprise Products Partners L.P. on a standalone basis.  References to “EPO” mean Enterprise Products Operating LLC, which is aan indirect wholly owned subsidiary of Enterprise,EPD, and its consolidated subsidiaries, through which Enterprise Products Partners L.P.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.Cunningham, who is also an advisory director of Enterprise GP.  Ms. Duncan Williams and Mr. Bachmann also currently serve as managers of Dan Duncan LLC along with W. Randall Fowler, who is also a director and the President and Chief Financial Officer of Enterprise GP.


References to “EPCO” mean Enterprise Products Company, a privately held Texas corporation, and its privately held affiliates.  A majority of the outstanding voting capital stock of EPCO is owned by a voting trust, the current trustees (“EPCO Trustees”) of which are:  (i) Ms. Duncan Williams, who serves as Chairman of EPCO; (ii) Dr. Cunningham, who serves as Vice Chairman of EPCO; and (iii) Mr. Bachmann, who serves as the President and Chief Executive Officer of EPCO.  Ms. Duncan Williams and Mr. Bachmann also currently serve as directors of EPCO along with Mr. Fowler, who is also the Executive Vice President and Chief AdministrativeFinancial Officer of EPCO. EPCO, together with its privately held affiliates, owned approximately 32%31.9% of ourEPD’s limited partner interestscommon units at September 30, 2018.2019.

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


Note 1.  Partnership Organization and Basis of Presentation


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


We conduct substantially all of our business through EPO and are owned 100% by ourEPD’s limited partners from an economic perspective.  Enterprise GP manages our partnership and owns a non-economic general partner interest in us.  We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates under the collective common control of the DD LLC Trustees and the EPCO Trustees.  Like many publicly traded partnerships, we have no employees.  All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement (the “ASA”) or by other service providers.  See Note 1514 for information regarding related party matters.


Our results of operations for the nine months ended September 30, 20182019 are not necessarily indicative of results expected for the full year of 2018.2019.  In our opinion, the accompanying Unaudited Condensed Consolidated Financial Statements include all adjustments consisting of normal recurring accruals necessary for fair presentation.  Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with United States (“U.S.”) generally accepted accounting principles (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”).


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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, 20172018  (the “2017“2018 Form 10-K”) filed with the SEC on February 28, 2018.March 1, 2019.




Note 2.  Summary of Significant Accounting Policies


Apart from those matters noted below, there have been no changes in our significant accounting policies since those reported under Note 2 of the 20172018 Form 10-K.


Adoption of New Revenue Recognition Policies on January 1, 2018
For periods through December 31, 2017, we accounted for our revenue streams using Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 605, Revenue Recognition.  Under ASC 605, we recognized revenue when all of the following criteria were met: (i) persuasive evidence of an exchange arrangement existed between usCash, Cash Equivalents and the counterparty (e.g., published tariffs), (ii) delivery of products or the rendering of services had occurred, (iii) the price of the products or the fee for services was fixed or determinable and (iv) collectibility of the amount owed by the counterparty was reasonably assured.

Effective January 1, 2018, we adopted FASB ASC 606, Revenue from Contracts with Customers, using a modified retrospective approach that applied the new revenue recognition standard to existing contracts at the implementation date and any future revenue contracts.   As such, our consolidated revenues and related financial information for periods prior to January 1, 2018 were not adjusted and continue to be reported in accordance with ASC 605.   We did not record a cumulative effect adjustment upon initially applying ASC 606 since there was no impact on partners’ equity upon adoption; however, the extent of our revenue-related disclosures has increased under the new standard.

Due to the large number of individual contracts that were in effect at the implementation date of ASC 606, we evaluated our contracts using a portfolio approach based on the types of products sold or services rendered within our business segments.  There are no material differences in the amount or timing of revenues recognized under ASC 606 when compared to ASC 605.

The core principle of ASC 606 is that a company should recognize revenue in a manner that fairly depicts the transfer of goods or services to customers in amounts that reflect the consideration the company expects to receive for those goods or services.  We apply this core principle by following five key steps outlined in ASC 606: (i) identify the contract; (ii) identify the performance obligations in the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and (v) recognize revenue when (or as) the performance obligation is satisfied. Each of these steps involves management judgment and an analysis of the contract’s material terms and conditions.

Substantially all of our revenues are accounted for under ASC 606; however, to a limited extent, some revenues are accounted for under other guidance such as ASC 840, Leases, ASC 845, Nonmonetary Transactions or ASC 815, Derivatives and Hedging Activities.

Under ASC 606, we recognize revenue when or as we satisfy our performance obligation to the customer.  In situations where we have recognized revenue, but have a conditional right to consideration (based on something other than the passage of time) from the customer, we recognize unbilled revenue (a contract asset) on our consolidated balance sheet.  Unbilled revenue is reclassified to accounts receivable when we have an unconditional right of payment from the customer. Payments received from customers in advance of the period in which we satisfy a performance obligation are recorded as deferred revenue (a contract liability) on our consolidated balance sheet.
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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Our revenue streams are derived from the sale of products and providing midstream services.  Revenues from the sale of products are recognized at a point in time, which represents the transfer of control (and the satisfaction of our performance obligation under the contract) to the customer.  From that point forward, the customer is able to direct the use of, and obtain substantially all the benefits from, its use of the products.  With respect to midstream services (e.g., interruptible transportation), we satisfy our performance obligations over time and recognize revenues when the services are provided and the customer receives the benefits based on an output measure of volumes redelivered.  We believe this measure is a faithful depiction of the transfer of control for midstream services since there is (i) an insignificant period of time between the receipt of customers’ volumes and their subsequent redelivery, and (ii) it is not possible to individually track and differentiate customers’ inventories as they traverse our facilities.  For stand-ready performance obligations (e.g., a storage capacity reservation contract), we recognize revenues over time on a straight-line basis as time elapses over the term of the contract. We believe that these approaches accurately depict the transfer of benefits to the customer.

Customers are invoiced for product purchases or services rendered when we have an unconditional right to consideration under the associated contract. The consideration we are entitled to invoice may be either fixed, variable or a combination of both.  Examples of fixed consideration would be fixed payments from customers under take-or-pay arrangements, storage capacity reservation agreements and firm transportation contracts. Variable consideration represents payments from customers that are based on factors that fluctuate (or vary) based on volumes, prices or both. Examples of variable consideration include interruptible transportation agreements, market-indexed product sales contracts and the value of NGLs we retain under natural gas processing agreements.  The terms of our billings are typical of the industry for the products we sell.

Under certain midstream service agreements, customers are required to provide a minimum volume over an agreed-upon period with a provision that allows the customer to make-up any volume shortfalls over an agreed-upon period (referred to as “make-up rights”).  Revenue pursuant to such agreements is initially deferred and subsequently recognized when either the make-up rights are exercised, the likelihood of the customer exercising the rights becomes remote, or we are otherwise released from the performance obligation.

Customers may contribute funds to us to help offset the construction costs related to pipeline construction activities and production well tie-ins.   Under ASC 605, these amounts were accounted for as contributions in aid of construction costs (“CIACs”) and netted against property, plant and equipment.   Under ASC 606, these receipts are recognized as additional service revenues over the term of the associated midstream services provided to the customer.

As a practical expedient, for those contracts under which we have the ability to invoice the customer in an amount that corresponds directly with the value of the performance obligation completed to date, we recognize revenue as we have the right to invoice.

See Note 9 regarding our new revenue disclosures.

Impact of ASU 2016-18 on Restricted Cash Disclosures
We adopted Accounting Standard Update (“ASU”) No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash, in the fourth quarter of 2017 and applied this ASU retrospectively to the periods presented in our Unaudited Condensed Statements of Consolidated Cash Flows.  As a result, the decrease in restricted cash of $287.7 million was excluded from net cash used in investing activities for the nine months ended September 30, 2017.


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,
2018
  
December 31,
2017
  
September 30,
2019
  
December 31,
2018
 
Cash and cash equivalents $30.2  $5.1  $1,207.8  $344.8 
Restricted cash  248.9   65.2   –   65.3 
Total cash, cash equivalents and restricted cash shown in the
Unaudited Condensed Statements of Consolidated Cash Flows
 $279.1  $70.3  $1,207.8  $410.1 

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

Restricted cash represents amounts held in segregated bank accounts by our clearing brokers as margin in support of our commodity derivative instruments portfolio and related physical purchases and sales of natural gas, NGLs, crude oil and refined products.  Additional cash may be restricted to maintain our commodity derivative instruments portfolio as prices fluctuate or margin requirements change.  The balance of restricted cash at September 30, 2018 consisted of initial margin requirements of $58.9 million and variation margin requirements of $190.0 million. The initial margin requirements will be returned to us as the related derivative instruments are settled.  See Note 1413 for information regarding our derivative instruments and hedging activities.


Other Recent Accounting Developments

Lease accounting standard. 
In February 2016, the FASBFinancial Accounting Standards Board (“FASB”) issued ASCAccounting Standards Codification (“ASC”) 842, Leases(“ASC 842”), which requires substantially all leases to be recorded on the balance sheet. We will adoptadopted the new standard on January 1, 2019 and applyapplied it to (i) all new leases entered into after January 1, 2019 and (ii) all existing lease contracts as of January 1, 2019. ASC 842 will supersedesupersedes existing lease accounting guidance found under ASC 840, Leases (“ASC 840”).


The new standard introduces two leaselessee accounting models, which result in a lease being classified as either a “finance” or “operating” lease based on the basis of whether the lessee effectively obtains control of the underlying asset during the lease term.  A lease would be classified as a finance lease if it meets one of five classification criteria, four of which are generally consistent with currentASC 840 lease accounting guidance.  By default, a lease that does not meet the criteria to be classified as a finance lease will be deemed an operating lease.  Regardless of classification, the initial measurement of both lease types will result in the balance sheet recognition of a right-of-use (“ROU”) asset (representing a company’s right to use the underlying asset for a specified period of time) and a corresponding lease liability.  The lease liability will be recognized at the present value of the future lease payments, and the ROU asset will equal the lease liability adjusted for any prepaid rent, lease incentives provided by the lessor, and any indirect costs.


The subsequent measurement of each type of lease varies. FinanceFor finance leases, will be accounted for using the effective interest method.  Under this approach, a lessee will amortize the ROU asset (generally on a straight-line basis in a manner similar to depreciation) and the discount onaccrete the lease liability (as a component of interest expense) using the effective interest method.  Operating leases will result in the recognition of a single lease expense amount that is recorded on a straight-line basis (or another systematic basis, as appropriate).basis.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


ASC 842 will resultresulted in changes to the way our operating leases are recorded, presented and disclosed in our consolidated financial statements. Upon adoption of ASC 842 on January 1, 2019, we expect to recognizerecognized a ROU asset and a corresponding lease liability based on the present value of then existing long-term operating lease obligations. In addition, there arewe elected to apply several keypractical expedients and made accounting policy elections that we will make upon adoption of ASC 842 including:


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


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


We will not reassess whether any expired or existing contracts contain leases or the lease classification for any existing or expired leases.
The impact of adopting ASC 842 will be


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

Based on current information, we forecast that our total remaining payment obligations under then existing operating leases will approximate $310 million (undiscounted) at January 1, 2019.  As a result, we expect to recognize an estimated $250 million ROU asset and a $250 million lease liability on our consolidated balance sheet based on discounted amounts.  These amounts would represent less than 1% of our total consolidated assets and liabilities, respectively.
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Fair value measurements.  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 amends certain disclosure requirements related to fair value measurements.   The amendmentsWe will require incremental disclosures regarding uncertainties surrounding fair value measurements, including discussions of any interrelationships between significant unobservable inputs used to estimate Level 3 fair value measurements, and changesnot recast prior periods presented in unrealized gains and losses.  The amendments in this ASU are effective January 1, 2020, which is when we expect to apply the new requirements.  We are currently reviewing the effect of this ASU on our consolidated financial statements.

Credit losses.  In June 2016, the FASB issued ASU 2016-13, “Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.”  This ASU modifies the impairment modelstatements to utilize an expected loss methodology in place of the currently used incurred loss methodology.   These changes are expected to result in the more timely recognition of losses.  The amendments in this ASU are effective January 1, 2020, which is when we expect to applyreflect the new requirementslease accounting guidance.


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

See Note 15 for doubtful accounts is determined.  We are currently reviewing the effect of this ASU on our consolidated financial statements.disclosures regarding operating lease obligations.




Note 3.  Inventories


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


 
September 30,
2018
  
December 31,
2017
  
September 30,
2019
  
December 31,
2018
 
NGLs $1,658.6  $917.4  $928.2  $647.7 
Petrochemicals and refined products  198.6   161.5   183.2   264.7 
Crude oil  467.0   516.3   520.1   593.4 
Natural gas  11.6   14.6   13.2   16.3 
Total $2,335.8  $1,609.8  $1,644.7  $1,522.1 


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


 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
For the Three Months
Ended September 30,
 
For the Nine Months
Ended September 30,
 
 2018  2017  2018  2017 2019 2018 2019 2018 
Cost of sales (1) $6,838.9  $5,049.6  $20,371.2  $15,116.4  $5,276.5  $6,838.9  $16,721.5  $20,371.2 
Lower of cost or net realizable value adjustments
recognized within cost of sales
  1.7   1.7   4.3   7.7   6.8   1.7   17.1   4.3 
                
(1) Cost of sales is a component of “Operating costs and expenses” as presented on our Unaudited Condensed Statements of Consolidated Operations. Fluctuations in these amounts are primarily due to changes in energy commodity prices and sales volumes associated with our marketing activities.
 


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

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



Note 4.  Property, Plant and Equipment


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


 
Estimated
Useful Life
in Years
  
September 30,
2018
  
December 31,
2017
  
Estimated
Useful Life
in Years
  
September 30,
2019
  
December 31,
2018
 
Plants, pipelines and facilities (1) 3-45 (5)  $41,939.8  $37,132.2   3-45(5) $45,117.5  $42,371.0 
Underground and other storage facilities (2) 5-40 (6)   3,527.8   3,460.9   5-40(6)  3,888.8   3,624.2 
Transportation equipment (3) 3-10   181.1   177.1   3-10   197.6   187.1 
Marine vessels (4) 15-30   814.1   803.8   15-30   893.8   828.6 
Land      360.0   273.1       366.1   359.5 
Construction in progress      2,769.9   4,698.1       3,558.1   3,526.8 
Total      49,592.7   46,545.2       54,021.9   50,897.2 
Less accumulated depreciation      11,789.8   10,924.8       13,258.6   12,159.6 
Property, plant and equipment, net     $37,802.9  $35,620.4      $40,763.3  $38,737.6 
 
(1) Plants, pipelines and facilities include processing plants; NGL, natural gas, crude oil and petrochemical and refined products pipelines; terminal loading and unloading facilities; buildings; office furniture and equipment; laboratory and shop equipment and related assets. We placed a number of growth projects into service since December 31, 2017 including our propane dehydrogenation facility, the first processing train at our Orla natural gas processing facility, and our ninth NGL fractionator at Mont Belvieu.
(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.
 


(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.
In March 2018, we acquired the remaining 50% member interest of our Delaware Processing joint venture, which resulted in the consolidation of $200 million of property, plant and equipment.  See Note 11 for information regarding this recent acquisition.

In April 2018, we acquired 65-acres of waterfront property on the Houston Ship Channel for approximately $85.2 million, all of which was recorded as land.  The purchase price consisted of $55.2 million in cash with the balance funded through 1,223,242 newly-issued Enterprise common units.  The land is located immediately to the east of our Enterprise Hydrocarbons Terminal (“EHT”) and is expected to facilitate future expansion projects at EHT.

See Note 19 regarding the sale of our Red River System in October 2018.


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


 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
For the Three Months
Ended September 30,
 
For the Nine Months
Ended September 30,
 
 2018  2017  2018  2017 2019 2018 2019 2018 
Depreciation expense (1) $368.3  $327.5  $1,061.1  $966.1  $394.7  $368.3  $1,164.6  $1,061.1 
Capitalized interest (2)  28.1   53.6   113.4   137.7   33.9   28.1   102.9   113.4 
 
(1) Depreciation expense is a component of “Costs and expenses” as presented on our Unaudited Condensed Statements of Consolidated Operations.
(2) We capitalize interest costs incurred on funds used to construct property, plant and equipment while the asset is in its construction phase. The capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset’s estimated useful life as a component of depreciation expense. When capitalized interest is recorded, it reduces interest expense from what it would be otherwise.
 


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

Asset Retirement Obligations

Property, plant and equipment at September 30, 20182019 and December 31, 20172018 includes $49.6$66.4 million and $39.9$72.5 million, respectively, of asset retirement costs capitalized as an increase in the associated long-lived asset.  The following table presents information regarding our asset retirement obligations, or AROs, since January 1,December 31, 2018:


ARO liability balance, December 31, 2017 $86.7 
ARO liability balance, December 31, 2018 $126.3 
Liabilities incurred  0.5   0.8 
Liabilities settled  (1.9)  (0.8)
Revisions in estimated cash flows  11.4   (4.9)
Accretion expense  4.5   5.9 
ARO liability balance, September 30, 2018 $101.2 
ARO liability balance, September 30, 2019 $127.3 



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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Note 5.  Investments in Unconsolidated Affiliates


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

  
Ownership
Interest at
September 30,
2018
  
September 30,
2018
  
December 31,
2017
 
NGL Pipelines & Services:         
Venice Energy Service Company, L.L.C. 13.1%  $24.7  $25.7 
K/D/S Promix, L.L.C. 50%   31.2   30.9 
Baton Rouge Fractionators LLC 32.2%   16.7   17.0 
Skelly-Belvieu Pipeline Company, L.L.C. 50%   36.6   37.0 
Texas Express Pipeline LLC 35%   328.6   314.4 
Texas Express Gathering LLC 45%   44.7   35.9 
Front Range Pipeline LLC 33.3%   175.7   165.7 
Delaware Basin Gas Processing LLC (1) 100%   --   107.3 
Crude Oil Pipelines & Services:           
Seaway Crude Pipeline Company LLC 50%   1,370.3   1,378.9 
Eagle Ford Pipeline LLC 50%   385.1   385.2 
Eagle Ford Terminals Corpus Christi LLC 50%   104.4   75.1 
Natural Gas Pipelines & Services:            
White River Hub, LLC 50%   20.4   20.8 
Old Ocean Pipeline, LLC 50%   1.6   -- 
Petrochemical & Refined Products Services:           
Centennial Pipeline LLC 50%   59.5   60.8 
Other Various   3.9   4.7 
Total investments in unconsolidated affiliates     $2,603.4  $2,659.4 
             
(1)   In March 2018, we acquired the remaining 50% membership interest in our Delaware Processing joint venture. See Note 11 for information regarding this recent acquisition. 


In May 2018, we and Energy Transfer Partners, L.P. (“ETP”) formed Old Ocean Pipeline, LLC to facilitate the resumption of full service on the Old Ocean natural gas pipeline owned by ETP.  The 24-inch diameter Old Ocean Pipeline originates in Maypearl, Texas in Ellis County and extends south approximately 240 miles to Sweeny, Texas in Brazoria County.  ETP serves as operator of the pipeline.

 
September 30,
2019
  
December 31,
2018
 
NGL Pipelines & Services $690.9  $662.0 
Crude Oil Pipelines & Services  1,877.2   1,867.5 
Natural Gas Pipelines & Services  31.4   22.8 
Petrochemical & Refined Products Services  61.4   62.8 
Total $2,660.9  $2,615.1 
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


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,
  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
 2018  2017  2018  2017  2019  2018  2019  2018 
NGL Pipelines & Services $28.3  $18.8  $87.1  $53.3  $25.9  $28.3  $82.7  $87.1 
Crude Oil Pipelines & Services  83.7   95.9   265.1   266.3   113.2   83.7   348.8   265.1 
Natural Gas Pipelines & Services  2.1   0.9   4.7   2.8   1.6   2.1   4.9   4.7 
Petrochemical & Refined Products Services  (2.1)  (2.2)  (6.9)  (7.2)  (1.4)  (2.1)  (5.1)  (6.9)
Total $112.0  $113.4  $350.0  $315.2  $139.3  $112.0  $431.3  $350.0 

Summarized Combined Financial Information of Unconsolidated Affiliates
Combined results of operations data for the periods indicated for our unconsolidated affiliates are summarized in the following table (all data presented on a 100% basis):


 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
 2018  2017  2018  2017  2019  2018  2019  2018 
Income Statement Data:                        
Revenues $439.1  $401.6  $1,296.4  $1,116.7  $470.2  $439.1  $1,484.6  $1,296.4 
Operating income  258.0   249.3   789.8   682.8   300.3   258.0   938.1   789.8 
Net income  256.9   247.5   785.6   688.0   299.5   256.9   935.9   785.6 


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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Note 6.  Intangible Assets and Goodwill


Identifiable Intangible Assets

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


 September 30, 2018  December 31, 2017  September 30, 2019  December 31, 2018 
 
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 $457.3  $(198.4) $258.9  $447.4  $(187.5) $259.9  $447.8  $(202.8) $245.0  $457.3  $(201.9) $255.4 
Contract-based intangibles  363.4   (233.1)  130.3   280.8   (218.4)  62.4   162.6   (40.9)  121.7   363.4   (238.7)  124.7 
Segment total  820.7   (431.5)  389.2   728.2   (405.9)  322.3   610.4   (243.7)  366.7   820.7   (440.6)  380.1 
Crude Oil Pipelines & Services:                                                
Customer relationship intangibles  2,203.5   (161.8)  2,041.7   2,203.5   (127.0)  2,076.5   2,203.5   (226.9)  1,976.6   2,203.5   (174.1)  2,029.4 
Contract-based intangibles  281.0   (203.5)  77.5   281.0   (171.0)  110.0   276.9   (230.1)  46.8   276.9   (211.7)  65.2 
Segment total  2,484.5   (365.3)  2,119.2   2,484.5   (298.0)  2,186.5   2,480.4   (457.0)  2,023.4   2,480.4   (385.8)  2,094.6 
Natural Gas Pipelines & Services:                                                
Customer relationship intangibles  1,350.3   (439.9)  910.4   1,350.3   (417.1)  933.2   1,350.3   (473.3)  877.0   1,350.3   (447.8)  902.5 
Contract-based intangibles  464.7   (385.8)  78.9   464.7   (379.5)  85.2   468.0   (393.6)  74.4   464.7   (387.9)  76.8 
Segment total  1,815.0   (825.7)  989.3   1,815.0   (796.6)  1,018.4   1,818.3   (866.9)  951.4   1,815.0   (835.7)  979.3 
Petrochemical & Refined Products Services:                                                
Customer relationship intangibles  181.4   (50.3)  131.1   181.4   (45.9)  135.5   181.4   (56.2)  125.2   181.4   (51.8)  129.6 
Contract-based intangibles  46.0   (20.6)  25.4   46.0   (18.4)  27.6   46.0   (23.3)  22.7   46.0   (21.2)  24.8 
Segment total  227.4   (70.9)  156.5   227.4   (64.3)  163.1   227.4   (79.5)  147.9   227.4   (73.0)  154.4 
Total intangible assets $5,347.6  $(1,693.4) $3,654.2  $5,255.1  $(1,564.8) $3,690.3  $5,136.5  $(1,647.1) $3,489.4  $5,343.5  $(1,735.1) $3,608.4 


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


 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
 2018  2017  2018  2017  2019  2018  2019  2018 
NGL Pipelines & Services $9.2  $7.2  $25.6  $21.8  $7.3  $9.2  $25.4  $25.6 
Crude Oil Pipelines & Services  20.7   22.6   67.3   68.0   25.1   20.7   71.2   67.3 
Natural Gas Pipelines & Services  9.8   9.3   29.1   26.3   10.3   9.8   31.2   29.1 
Petrochemical & Refined Products Services  2.2   2.3   6.6   7.0   2.1   2.2   6.5   6.6 
Total $41.9  $41.4  $128.6  $123.1  $44.8  $41.9  $134.3  $128.6 


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


Remainder
of 2018
  2019  2020  2021  2022 
Remainder
of 2019
Remainder
of 2019
  2020  2021  2022  2023 
$36.8  $151.7  $140.7  $148.4  $144.6 40.5  $161.8  $162.8  $168.4  $168.5 


Goodwill

Goodwill represents the excess of the purchase price of an acquired business over the amounts assigned to assets acquired and liabilities assumed in the transaction.  There has been no change in our goodwill amounts since those reported in our 20172018 Form 10-K.


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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 7.  Debt Obligations


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


 
September 30,
2018
  
December 31,
2017
  
September 30,
2019
  
December 31,
2018
 
EPO senior debt obligations:            
Commercial Paper Notes, variable-rates $2,707.6  $1,755.7  $–  $– 
Senior Notes V, 6.65% fixed-rate, repaid April 2018  --   349.7 
Senior Notes OO, 1.65% fixed-rate, repaid May 2018  --   750.0 
Senior Notes N, 6.50% fixed-rate, due January 2019  700.0   700.0 
364-Day Revolving Credit Agreement, variable-rate, due September 2019  --   -- 
Senior Notes LL, 2.55% fixed-rate, due October 2019  800.0   800.0 
Senior Notes N, 6.50% fixed-rate, repaid January 2019  –   700.0 
Senior Notes LL, 2.55% fixed-rate, repaid October 2019  800.0   800.0 
Senior Notes Q, 5.25% fixed-rate, due January 2020  500.0   500.0   500.0   500.0 
Senior Notes Y, 5.20% fixed-rate, due September 2020  1,000.0   1,000.0   1,000.0   1,000.0 
364-Day Revolving Credit Agreement, variable-rate, due September 2020  –   – 
Senior Notes TT, 2.80% fixed-rate, due February 2021  750.0   --   750.0   750.0 
Senior Notes RR, 2.85% fixed-rate, due April 2021  575.0   575.0   575.0   575.0 
Senior Notes VV, 3.50% fixed-rate, due February 2022  750.0   750.0 
Senior Notes CC, 4.05% fixed-rate, due February 2022  650.0   650.0   650.0   650.0 
Multi-Year Revolving Credit Facility, variable-rate, due September 2022  --   -- 
Senior Notes HH, 3.35% fixed-rate, due March 2023  1,250.0   1,250.0   1,250.0   1,250.0 
Senior Notes JJ, 3.90% fixed-rate, due February 2024  850.0   850.0   850.0   850.0 
Multi-Year Revolving Credit Agreement, variable-rate, due September 2024  –   – 
Senior Notes MM, 3.75% fixed-rate, due February 2025  1,150.0   1,150.0   1,150.0   1,150.0 
Senior Notes PP, 3.70% fixed-rate, due February 2026  875.0   875.0   875.0   875.0 
Senior Notes SS, 3.95% fixed-rate, due February 2027  575.0   575.0   575.0   575.0 
Senior Notes WW, 4.15% fixed-rate, due October 2028  1,000.0   1,000.0 
Senior Notes YY, 3.125% fixed-rate, due July 2029  1,250.0   – 
Senior Notes D, 6.875% fixed-rate, due March 2033  500.0   500.0   500.0   500.0 
Senior Notes H, 6.65% fixed-rate, due October 2034  350.0   350.0   350.0   350.0 
Senior Notes J, 5.75% fixed-rate, due March 2035  250.0   250.0   250.0   250.0 
Senior Notes W, 7.55% fixed-rate, due April 2038  399.6   399.6   399.6   399.6 
Senior Notes R, 6.125% fixed-rate, due October 2039  600.0   600.0   600.0   600.0 
Senior Notes Z, 6.45% fixed-rate, due September 2040  600.0   600.0   600.0   600.0 
Senior Notes BB, 5.95% fixed-rate, due February 2041  750.0   750.0   750.0   750.0 
Senior Notes DD, 5.70% fixed-rate, due February 2042  600.0   600.0   600.0   600.0 
Senior Notes EE, 4.85% fixed-rate, due August 2042  750.0   750.0   750.0   750.0 
Senior Notes GG, 4.45% fixed-rate, due February 2043  1,100.0   1,100.0   1,100.0   1,100.0 
Senior Notes II, 4.85% fixed-rate, due March 2044  1,400.0   1,400.0   1,400.0   1,400.0 
Senior Notes KK, 5.10% fixed-rate, due February 2045  1,150.0   1,150.0   1,150.0   1,150.0 
Senior Notes QQ, 4.90% fixed-rate, due May 2046  975.0   975.0   975.0   975.0 
Senior Notes UU, 4.25% fixed-rate, due February 2048  1,250.0   --   1,250.0   1,250.0 
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   – 
Senior Notes NN, 4.95% fixed-rate, due October 2054  400.0   400.0   400.0   400.0 
TEPPCO senior debt obligations:                
TEPPCO Senior Notes, 6.65% fixed-rate, repaid April 2018  --   0.3 
TEPPCO Senior Notes, 7.55% fixed-rate, due April 2038  0.4   0.4   0.4   0.4 
Total principal amount of senior debt obligations  23,457.6   21,605.7   25,550.0   23,750.0 
EPO Junior Subordinated Notes A, variable-rate, redeemed August 2018  --   521.1 
EPO Junior Subordinated Notes B, fixed/variable-rate, redeemed March 2018  --   682.7 
EPO Junior Subordinated Notes C, variable-rate, due June 2067 (1)
  256.4   256.4   232.2   256.4 
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 
TEPPCO Junior Subordinated Notes, fixed/variable-rate, due June 2067   14.2   14.2 
TEPPCO Junior Subordinated Notes, variable-rate, due June 2067 (1)
  14.2   14.2 
Total principal amount of senior and junior debt obligations  26,128.2   24,780.1   28,196.4   26,420.6 
Other, non-principal amounts  (214.2)  (211.4)  (257.2)  (242.4)
Less current maturities of debt  (3,405.5)  (2,855.0)  (2,300.0)  (1,500.1)
Total long-term debt $22,508.5  $21,713.7  $25,639.2  $24,678.1 
 
(1) Variable rate is reset quarterly and based on 3-month 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%.
 


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

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


The following table presents the range of interest rates and weighted-average interest rates paid on our consolidated variable-rate debt during the nine months ended September 30, 2018:2019:


 
Range of Interest
Rates Paid
Weighted-Average
Interest Rate Paid
Commercial Paper Notes1.50% to 2.50%2.23%
Multi-Year Revolving Credit Facility2.58% to 5.00%3.37%
EPO Junior Subordinated Notes A (prior to redemption)5.08% to 6.07%5.71%
EPO Junior Subordinated Notes B (prior to redemption)7.03%7.03%
EPO Junior Subordinated Notes C4.26% to 5.10%4.80%
Range of Interest
Rates Paid
Weighted-Average
Interest Rate Paid
Commercial Paper Notes2.58% to 2.80%2.72%
EPO Junior Subordinated Notes C and TEPPCO Junior Subordinated Notes4.91% to 5.52%5.34%


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

The following table presents contractuallythe scheduled contractual maturities of principal amounts of our consolidated debt obligations outstanding at September 30, 20182019 for the next five years and in total thereafter:


     Scheduled Maturities of Debt 
  Total  
Remainder
of 2018
  2019  2020  2021  2022  Thereafter 
Commercial Paper Notes $2,707.6  $2,707.6  $--  $--  $--  $--  $-- 
Senior Notes  20,750.0   --   1,500.0   1,500.0   1,325.0   650.0   15,775.0 
Junior Subordinated Notes  2,670.6   --   --   --   --   --   2,670.6 
Total $26,128.2  $2,707.6  $1,500.0  $1,500.0  $1,325.0  $650.0  $18,445.6 
     Scheduled Maturities of Debt 
  Total  
Remainder
of 2019
  2020  2021  2022  2023  Thereafter 
Principal amount of senior and junior debt obligations at
    September 30, 2019
 $28,196.4  $800.0  $1,500.0  $1,325.0  $1,400.0  $1,250.0  $21,921.4 


In October 2019, we repaid $800.0 million principal amount of EPO’s Senior Notes LL at their maturity using unrestricted cash on hand.

Parent-Subsidiary Guarantor Relationships
Enterprise Products Partners L.P.
EPD acts as guarantor of the consolidated debt obligations of EPO, with the exception of the remaining debt obligations of TEPPCO.  If EPO were to default on any of its guaranteed debt, Enterprise Products Partners L.P.EPD would be responsible for full and unconditional repayment of that obligation.


Issuance of $3.0 Billion of Senior Notes in October 2018Amendment to Multi-Year Revolving Credit Agreement

In October 2018,September 2019, EPO issued $3.0entered into an amendment (the “First Amendment”) to its revolving credit agreement dated September 13, 2017 (the “Multi-Year Revolving Credit Agreement”).  The First Amendment reduces the borrowing capacity under the Multi-Year Revolving Credit Agreement from $4.0 billion aggregate principal amountto $3.5 billion (which may be increased by up to $500 million to $4.0 billion at EPO’s election provided certain conditions are met) and extends the maturity date to September 10, 2024, although the maturity date may be extended further at EPO’s request by up to two years, with the consent of senior notes comprised of (i) $750 million principal amount of senior notes due February 2022, (ii) $1.0 billion principal amount of senior notes due October 2028required lenders as set forth under the credit agreement.  Borrowings under this revolving credit agreement may be used for working capital, capital expenditures, acquisitions and (iii) $1.25 billion principal amount of senior notes due February 2049.  See Note 19 for information regarding this subsequent event and related use of proceeds.

Issuance of $2.0 Billion of Senior Notes and $700 Million of Junior Subordinated Notes in February 2018
In February 2018, EPO issued $2.7 billion aggregate principal amount of notes comprised of (i) $750 million principal amount of senior notes due February 2021 (“Senior Notes TT”), (ii) $1.25 billion principal amount of senior notes due February 2048 (“Senior Notes UU”) and (iii) $700 million principal amount of junior subordinated notes due February 2078 (“Junior Subordinated Notes F”).

Net proceeds from the February 2018 offerings were used by EPO for the temporary repayment of amounts outstanding under its commercial paper program, general company purposes,purposes.

The Multi-Year Revolving Credit Agreement contains customary representations, warranties, covenants (affirmative and negative) and events of default, the redemptionoccurrence of all $682.7 million outstanding aggregate principal amountwhich would permit the lenders to accelerate the maturity date of any amounts borrowed under this credit agreement.  The Multi-Year Revolving Credit Agreement also restricts EPO’s ability to pay cash distributions to its Junior Subordinated Notes B.

Senior Notes TT were issued at 99.946% of their principal amount and have a fixed-rate interest rate of 2.80% per year.  Senior Notes UU were issued at 99.865% of their principal amount and have a fixed-rate interest rate of 4.25% per year.parent, Enterprise Products Partners L.P., if an event of default (as defined in the credit agreement) has occurred and is continuing at the time such distribution is scheduled to be paid or would result therefrom.

EPO’s obligations under the Multi-Year Revolving Credit Agreement are not secured by any collateral; however, they are guaranteed the senior notes through an unconditional guarantee on an unsecured and unsubordinated basis.

The Junior Subordinated Notes F are redeemable at EPO’s option, in whole or in part, on one or more occasions, on or after February 15, 2028 at 100% of their principal amount, plus any accrued and unpaid interest thereon, and bear interest at a fixed rate of 5.375% per year through February 14, 2028.  Beginning February 15, 2028, the Junior Subordinated Notes F will bear interest at a floating rate based on a three-month LIBOR plus 2.57%, reset quarterly.by Enterprise Products Partners L.P. has guaranteed the Junior Subordinated Notes F through an unconditional guarantee on an unsecured and subordinated basis.
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RedemptionRenewal of Junior Subordinated Notes
In March 2018, EPO redeemed all of the $682.7 million outstanding aggregate principal amount of its Junior Subordinated Notes B at a price equal to 100% of the principal amount of the notes being redeemed, plus all accrued and unpaid interest thereon to, but not including, the redemption date.  This redemption was funded by EPO’s issuance of senior notes and junior subordinated notes in February 2018.

In August 2018, EPO redeemed all of the $521.1 million outstanding aggregate principal amount of its Junior Subordinated Notes A at a price equal to 100% of the principal amount of the notes being redeemed, plus all accrued and unpaid interest thereon to, but not including, the redemption date.  This redemption was funded by the issuance of short-term notes under EPO’s commercial paper program.

364-Day Revolving Credit Agreement

In September 2018,2019, EPO entered into a new 364-Day Revolving Credit Agreement that replaced its prior 364-day credit facility.  The new 364-Day Revolving Credit Agreement matures in September 2019.2020. There are currently no principal amounts outstanding under this revolving credit agreement.


Under the terms of the new 364-Day Revolving Credit Agreement, EPO may borrow up to $2.0$1.5 billion (which may be increased by up to $200 million to $2.2$1.7 billion at EPO’s election, provided certain conditions are met) at a variable interest rate for a term of up to 364 days, subject to the terms and conditions set forth therein.  To the extent that principal amounts are outstanding at the maturity date, EPO may elect to have the entire principal balance then outstanding continued as a non-revolving term loanloans for a period of one additional year, payable in September 2020.2021. Borrowings under this revolving credit agreement may be used for working capital, capital expenditures, acquisitions and general company purposes.


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


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


IncreaseIssuance of $2.5 Billion of Senior Notes in Amount Authorized under Commercial Paper ProgramJuly 2019

In June 2018,July 2019, EPO increased theissued $2.5 billion aggregate principal amount of short-termsenior notes that it could issue (andcomprised of $1.25 billion principal amount of senior notes due July 2029 (“Senior Notes YY”) and $1.25 billion principal amount of senior notes due January 2050 (“Senior Notes ZZ”).  Net proceeds from this offering were used by EPO for the repayment of debt and  for general company purposes, including for growth capital expenditures.

Senior Notes YY were issued at 99.955% of their principal amount and have outstandinga fixed interest rate of 3.125% per year.  Senior Notes ZZ were issued at any time) under99.792% of their principal amount and have a fixed interest rate of 4.20% per year. EPD has guaranteed the senior notes through an unconditional guarantee on an unsecured and unsubordinated basis.

Partial Retirement of Junior Subordinated Notes During Second Quarter of 2019

During the second quarter of 2019, EPO repurchased and retired $24.2 million in principal amount of its commercial paper program from $2.5 billionJunior Subordinated Notes C.  A $1.5 million gain on the extinguishment of these debt obligations is included in “Other, net” on our Unaudited Condensed Statements of Consolidated Operations with respect to $3.0 billion.  All commercial paper notes issued under the program are senior unsecured obligations of EPO that are unconditionally guaranteed by Enterprise Products Partners L.P.nine months ended September 30, 2019.


Lender Financial Covenants

We were in compliance with the financial covenants of our consolidated debt agreements at September 30, 2018.2019.


Letters of Credit

At September 30, 2018,2019, EPO had $101.4 million of letters of credit outstanding primarily related to our commodity hedging activities.


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Note 8.  Equity and Distributions


Limited Partner Common Units Outstanding

The following table summarizes changes in the number of ourEPD limited partner common units outstanding since December 31, 2017:2018:


Common units outstanding at December 31, 20172018  2,161,089,4792,184,869,029 
Common unit repurchases under 2019 Buyback Program(1,852,392)
Common units issued in connection with DRIP and EUPP  6,642,2861,516,779 
Common units issued in connection with the vesting of phantom unit awards, net  3,170,8612,379,620 
Cancellation of treasury units acquired in connection with the vesting of equity-based awards(949,778)
Common units issued in connection with employee compensation  1,443,5861,626,041 
Other  16,36021,595 
Common units outstanding at March 31, 20182019  2,171,412,7942,188,560,672 
Common unit repurchases under 2019 Buyback Program(1,056,736)
Common units issued in connection with DRIP and EUPP  3,234,8041,381,211 
Common units issued in connection with the vesting of phantom unit awards, net  115,115
Cancellation of treasury units acquired in connection with the vesting of equity-based awards(34,827)
Common units issued in connection with land acquisition (see Note 4)1,223,242120,831 
Common units outstanding at June 30, 20182019  2,175,951,128
Common units issued in connection with DRIP and EUPP6,600,4862,189,005,978 
Common units issued in connection with the vesting of phantom unit awards, net  151,692163,550 
Cancellation of treasury units acquired in connection with the vesting of equity-based awards(41,756)
Common units outstanding at September 30, 20182019  2,182,661,5502,189,169,528 


The net cash proceeds we received from the issuance of common units during the nine months ended September 30, 2018 were used to temporarily reduce amounts outstanding under EPO’s commercial paper program and revolving credit facilities and for general company purposes, including for growth capital expenditures.

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

Active Registration Statements
Universal shelf registration statement.  We have a universal shelf registration statement (the “2016“2019 Shelf”) on file with the SEC which allows Enterprise Products Partners L.P.EPD and EPO (each on a standalone basis) to issue an unlimited amount of equity and debt securities, respectively. The 2019 Shelf replaced our prior universal shelf registration statement, which expired in May 2019.  EPO issued $2.7 billion of senior and junior subordinated notes in February 2018 using the 2016 Shelf (see Note 7).  In addition, EPO issued $3.0$2.5 billion of senior notes in October 2018July 2019 using this registration statementthe 2019 Shelf (see Note 19)7).


At-the-Market (“ATM”) program.  We haveIn addition, EPD has a registration statement on file with the SEC covering the issuance of up to $2.54$2.54 billion of ourits common units in amounts, at prices and on terms to be determined by market conditions and other factors at the time of such offerings in connection with our ATMits at-the-market (“ATM”) program.  Pursuant to this program, we may sell common units under an equity distribution agreement between Enterprise Products Partners L.P. and certain broker-dealers from time-to-time by means of ordinary brokers’ transactions through the NYSE at market prices, in block transactions or as otherwise agreed to with the broker-dealer parties to the agreement.  

During the nine months ended September 30, 2019 and 2018 we, EPD did not issue any common units under theits ATM program.  During the nine months ended September 30, 2017, we issued 21,807,726 common units under this program for aggregate gross cash proceeds of $603.1 million, resulting in total net cash proceeds of $597.3 million.

After taking into account the aggregate sales price of common units sold under the ATM program in periods prior to fiscal 2018, we havethrough September 30, 2019, EPD has the capacity to issue additional common units under theits ATM program up to an aggregate sales price of $2.54 billion.

20We may issue additional equity and debt securities to assist us in meeting our future liquidity requirements, including those related to capital investments.

Common unit repurchases under 2019 Buyback Program
In January 2019, we announced that the Board of Enterprise GP had approved a $2.0 billion multi-year unit buyback program (the “2019 Buyback Program”), which provides EPD with an additional method to return capital to investors. The 2019 Buyback Program authorizes EPD to repurchase its common units from time to time, including through open market purchases and negotiated transactions.  The timing and pace of buy backs under the program will be determined by a number of factors including (i) our financial performance and flexibility, (ii) organic growth and acquisition opportunities with higher potential returns on investment, (iii) EPD’s unit price and implied cash flow yield and (iv) maintaining targeted financial leverage with a debt-to-normalized adjusted EBITDA (earnings before interest, taxes, depreciation and amortization) ratio of approximately 3.5 times.  No time limit has been set for completion of the program, and it may be suspended or discontinued at any time.

EPD repurchased 2,909,128 common units under the 2019 Buyback Program through open market purchases during the nine months ended September 30, 2019 (no repurchases were made during the third quarter of 2019).  The total purchase price of these repurchases was $81.1 million, excluding commissions and fees. The repurchased units were cancelled immediately upon acquisition.  At September 30, 2019, the remaining available capacity under the 2019 Buyback Program was $1.92 billion.
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Distribution reinvestment plan.  We have aCommon units issued in connection with DRIP and EUPP
EPD has registration statementstatements on file with the SEC in connection with ourits distribution reinvestment plan (“DRIP”) and employee unit purchase plan (“EUPP”).  The DRIP provides unitholders of recordEPD issued and beneficial owners of our common units a voluntary means by which they can increase the number of our common units they own by reinvesting the quarterly cash distributions they receive from us into the purchase of additional new common units.

We issueddelivered a total of 16,073,9742,601,727 new common units under our DRIP during the nine months ended September 30, 2018, which generated net cash proceeds of $438.1 million.  Privately held affiliates of EPCO reinvested $206 million through the DRIP during the nine months ended September 30, 2018 (this amount being a component of the2019, which generated net cash proceeds presented).of $73.7 million.  During the nine months ended September 30, 2017, we2018, EPD issued 10,345,655and delivered 16,073,974 new common units under ourthe DRIP, which generated net cash proceeds of $269.9$438.1 million.  After taking into account the number of common units issueddelivered under the DRIP through September 30, 2018, we have2019, EPD has the capacity to issuedeliver an additional 64,643,16657,544,841 common units under this plan.

Employee unit purchase plan.  In addition to  The period-to-period decrease in net cash proceeds from the DRIP we have registration statements on fileis primarily due to (i) lower reinvestments by privately held affiliates of EPCO in 2019, (ii) a reduction in the discount applicable to common unit purchases made under the DRIP from 2.5% to 0% beginning with the SECdistribution paid in connectionFebruary 2019 and (iii) the election to satisfy delivery obligations under the DRIP using common units purchased on the open market, rather than issuing new common units, beginning with our employee unit purchase plan (“EUPP”).  Wethe distribution paid in August 2019.

EPD issued 403,602and delivered 296,263 new common units under ourthe EUPP during the nine months ended September 30, 2018,2019, which generated net cash proceeds of $11.3$8.5 million.  During the nine months ended September 30, 2017, we2018, EPD issued 364,934and delivered 403,602 new common units under ourits EUPP, which generated net cash proceeds of $10.0$11.3 million.  After taking into account the number of common units issueddelivered under the EUPP through September 30, 2018, we2019, EPD may issuedeliver an additional 5,357,2094,763,149 common units under this plan.


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

In July 2019, EPD announced that, beginning with the quarterly distribution payment paid in August 2019, it would use common units purchased on the open market, rather than issuing new common units, to satisfy its delivery obligations under the DRIP and EUPP.  This election is subject to change in future quarters depending on the partnership’s need for equity capital.   In August 2019, a total of 1,410,020 common units were purchased on the open market and delivered to participants in connection with the DRIP and EUPP.  Apart from $0.5 million attributable to the plan discount available to all participants in the EUPP, the funds used to effect these purchases were sourced from the DRIP and EUPP participants.  No other partnership funds were used to satisfy these obligations.  We plan to use open market purchases to satisfy DRIP and EUPP reinvestments in connection with the distribution expected to be paid on November 12, 2019.

Common Units Issued in Connection With Employee Compensation
In February 2018, the dollar value2019, certain employees of EPCO received discretionary employee bonus payments, with respectless any retirement plan deductions and applicable withholding taxes, for work performed on our behalf during the prior fiscal year (e.g., the February 2019 bonus amount was applicable to the year ended December 31, 2017 (less any retirement plan deductions and withholding taxes)2018).  The net dollar value of the bonus amounts was remitted through the issuance of an equivalent value of newly issued EnterpriseEPD common units under EPCO’s 2008 Enterprise Products Long-Term Incentive Plan (Third Amendment and Restatement) (“2008 Plan”).  WeIn February 2019, EPD issued 1,443,5861,626,041 common units, which had a value of $39.1$45.6 million, in connection with the employee bonus payments.awards.  The compensation expense associated with this issuance of common unitseach bonus award was recognized during the year in which the work was performed.

Common Units Issued in Connection With the Vesting of Phantom Unit Awards
During the nine months ended December 31, 2017.September 30, 2019, after taking into account tax withholding requirements, EPD issued a net 2,664,001 new common units to employees in connection with the vesting of phantom unit awards.  See Note 12 for information regarding our phantom unit awards.

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Accumulated Other Comprehensive Income (Loss)

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


 Cash Flow Hedges        Cash Flow Hedges       
 
Commodity
Derivative
Instruments
  
Interest Rate
Derivative
Instruments
  Other  
Total
  
Commodity
Derivative
Instruments
  
Interest Rate
Derivative
Instruments
  Other  
Total
 
Accumulated Other Comprehensive Income (Loss), December 31, 2017 $(10.1) $(165.1) $3.5  $(171.7)
Accumulated Other Comprehensive Income (Loss), December 31, 2018 $152.7  $(104.8) $3.0  $50.9 
Other comprehensive income (loss) for period, before reclassifications  (156.0)  20.7   (0.5)  (135.8)  58.6   (23.8)  (0.6)  34.2 
Reclassification of losses (gains) to net income during period  (28.8)  29.0   --   0.2   (152.0)  27.8   –   (124.2)
Total other comprehensive income (loss) for period  (184.8)  49.7   (0.5)  (135.6)  (93.4)  4.0   (0.6)  (90.0)
Accumulated Other Comprehensive Income (Loss), September 30, 2018 $(194.9) $(115.4) $3.0  $(307.3)
Accumulated Other Comprehensive Income (Loss), September 30, 2019 $59.3  $(100.8) $2.4  $(39.1)


 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, 2016 $(83.8) $(199.8) $3.6  $(280.0)
Accumulated Other Comprehensive Income (Loss), December 31, 2017 $(10.1) $(165.1) $3.5  $(171.7)
Other comprehensive income (loss) for period, before reclassifications  (2.6)  (4.8)  (0.1)  (7.5)  (156.0)  20.7   (0.5)  (135.8)
Reclassification of losses (gains) to net income during period  (49.0)  29.9   --   (19.1)  (28.8)  29.0   –   0.2 
Total other comprehensive income (loss) for period�� (51.6)  25.1   (0.1)  (26.6)  (184.8)  49.7   (0.5)  (135.6)
Accumulated Other Comprehensive Income (Loss), September 30, 2017 $(135.4) $(174.7) $3.5  $(306.6)
Accumulated Other Comprehensive Income (Loss), September 30, 2018 $(194.9) $(115.4) $3.0  $(307.3)

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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,
 
Location 2018  2017  2018  2017    
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
Losses (gains) on cash flow hedges:            Location 2019  2018  2019  2018 
Interest rate derivativesInterest expense $9.1  $10.3  $29.0  $29.9 Interest expense $9.4  $9.1  $27.8  $29.0 
Commodity derivativesRevenue  (53.9)  (10.6)  (28.5)  (49.1)Revenue  (93.6)  (53.9)  (161.4)  (28.5)
Commodity derivativesOperating costs and expenses  0.4   0.5   (0.3)  0.1 Operating costs and expenses  2.1   0.4   9.4   (0.3)
Total  $(44.4) $0.2  $0.2  $(19.1)  $(82.1) $(44.4) $(124.2) $0.2 


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


Cash DistributionsNoncontrolling Interests

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

Noncontrolling interest balance in Equity, December 31, 2018 $438.7 
Net income attributable to noncontrolling interests  67.3 
Cash distributions paid to noncontrolling interests  (69.7)
Cash contributions from noncontrolling interests  590.8 
Other  2.4 
Noncontrolling interest balance in Equity, September 30, 2019 $1,029.5 
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Cash Distributions

In January 2019, management announced its plans to recommend to the Board an increase of $0.0025 per unit per quarter in EPD’s cash distribution rates per common unitrate with respect to the quarter indicated:

  
Distribution Per
Common Unit
 
Record
Date
Payment
Date
2017        
1st Quarter $0.4150 4/28/20175/8/2017
2nd Quarter $0.4200 7/31/20178/7/2017
3rd Quarter $0.4225 10/31/201711/7/2017
2018         
1st Quarter $0.4275 4/30/20185/8/2018
2nd Quarter $0.4300 7/31/20188/8/2018
3rd Quarter $0.4325 10/31/201811/8/2018

2019. The anticipated rate of increase would result in distributions for 2019 of $1.7650 per unit, which would be 2.3% higher than those paid by EPD for 2018 of $1.7250 per unit.  The payment of any quarterly cash distribution is subject to Board approval and management’s evaluation of our financial condition, results of operations and cash flows in connection with such payment.  Management currently expects to recommend to

On October 9, 2019, EPD announced that the Board declared a quarterly cash distribution of $0.4350$0.4425 per common unit with respect to the fourththird quarter of 2018.

Noncontrolling Interests
In June 2018, pursuant2019, which represents a 2.3% increase over the $0.4325 per common unit EPD declared and paid with respect to an option agreement, an affiliate of Western Gas Partners, LP (“Western”) acquired a noncontrolling 20% equity interest in our subsidiary, Whitethorn Pipeline Company LLC (“Whitethorn”), for approximately $189.6 million in cash.  Whitethorn owns the Midland-to-ECHO pipeline, which originates at our Midland, Texas terminal and extends 416 miles to our Sealy, Texas facility. This amount is a component of contributions from noncontrolling interests as presented on our Unaudited Condensed Statement of Consolidated Cash Flows for the nine months ended September 30, 2018.

In January 2018, we announced a project to construct, own and operate an ethylene export facility, the location of which was subsequently determined to be at our Morgan’s Point facility on the Houston Ship Channel. Navigator Ethylene Terminals LLC holds a noncontrolling 50% equity interest in our consolidated subsidiary, Enterprise Navigator Ethylene Terminal LLC, that owns the export facility, which is expected to be completed in the fourththird quarter of 2019.

Other
In May 2018, Apache Corporation (“Apache”) executed a long-term supply agreement2018.  The distribution with us whereby Apache would sell all of its NGL production fromrespect to the Alpine High discovery to Enterprise.  Alpine High is a major hydrocarbon resource located in the Delaware Basin that encompasses rich natural gas (i.e., gas that has a high NGL content), dry natural gas and oil-bearing horizons.  In conjunction with the long-term NGL supply agreement, we granted Apache an option to acquire up to a 33% equity interest in our subsidiary that owns the Shin Oak NGL Pipeline, which is currently under construction and expected to be placed into service during the secondthird quarter of 2019.  The option is exercisable once2019 will be paid on November 12, 2019 to unitholders of record as of the pipeline is placed into commercial service and contingent upon the executionclose of associated definitive agreements.  In August 2018, Apache announced its intent to contribute the Shin Oak option to Altus Midstream Company, which would be majority-owned by Apache.business on October 31, 2019.

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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,
 
 
2018 (1)
  
2017 (2)
  
2018 (1)
  
2017 (2)
  2019  2018  2019  2018 
NGL Pipelines & Services:                        
Sales of NGLs and related products $3,898.2  $2,415.3  $9,324.5  $7,460.5  $2,624.9  $3,898.2  $7,955.5  $9,324.5 
Midstream services  724.7   499.0   1,985.4   1,420.2 
Total  4,622.9   2,914.3   11,309.9   8,880.7 
Segment midstream services:                
Natural gas processing and fractionation  279.6   397.2   837.3   982.2 
Transportation  248.2   241.8   767.4   725.5 
Storage and terminals  99.4   85.7   291.0   277.7 
Total segment midstream services  627.2   724.7   1,895.7   1,985.4 
Total NGL Pipelines & Services  3,252.1   4,622.9   9,851.2   11,309.9 
Crude Oil Pipelines & Services:                                
Sales of crude oil  2,209.0   1,589.0   8,082.9   4,912.7   2,130.0   2,209.0   6,990.1   8,082.9 
Midstream services  285.9   207.7   764.1   590.8 
Total  2,494.9   1,796.7   8,847.0   5,503.5 
Segment midstream services:                
Transportation  209.1   187.9   598.1   490.7 
Storage and terminals  139.2   98.0   364.0   273.4 
Total segment midstream services  348.3   285.9   962.1   764.1 
Total Crude Oil Pipelines & Services  2,478.3   2,494.9   7,952.2   8,847.0 
Natural Gas Pipelines & Services:                                
Sales of natural gas  589.0   568.9  ��1,681.5   1,673.5   440.0   589.0   1,627.1   1,681.5 
Midstream services  261.2   227.7   766.3   670.5 
Total  850.2   796.6   2,447.8   2,344.0 
Segment midstream services:                
Transportation  275.5   261.2   835.2   766.3 
Total segment midstream services  275.5   261.2   835.2   766.3 
Total Natural Gas Pipelines & Services  715.5   850.2   2,462.3   2,447.8 
Petrochemical & Refined Products Services:                                
Sales of petrochemicals and refined products  1,408.9   1,194.2   4,111.6   3,519.4   1,299.0   1,408.9   3,867.3   4,111.6 
Midstream services  209.0   185.1   635.6   567.3 
Total  1,617.9   1,379.3   4,747.2   4,086.7 
Segment midstream services:                
Fractionation and isomerization  43.2   45.9   125.5   146.8 
Transportation, including marine logistics  134.4   119.2   393.2   353.0 
Storage and terminals  41.6   43.9   132.2   135.8 
Total segment midstream services  219.2   209.0   650.9   635.6 
Total Petrochemical & Refined Products Services  1,518.2   1,617.9   4,518.2   4,747.2 
Total consolidated revenues $9,585.9  $6,886.9  $27,351.9  $20,814.9  $7,964.1  $9,585.9  $24,783.9  $27,351.9 
 
(1) Revenues are accounted for under ASC 606 upon implementation at January 1, 2018.
(2) Revenues are accounted for under ASC 605 for historical periods prior to January 1, 2018.
 


Substantially all of our revenues are derived from contracts with customers as defined within ASC 606.customers.  In total, product sales and midstream services accounted for 85%82% and 15%18%, respectively, of our consolidated revenues for the three and nine months ended September 30, 2018.2019.  During the three and nine months ended September 30, 2017, 2018, product sales and midstream services accounted for 84%85% and 16%15%, respectively, of our consolidated revenues.

Apart from the following information regarding natural gas processing, the description of our significant revenue streams by business segment found under Note 3 of the 2017 Form 10-K have not changed in connection with the adoption of ASC 606.

Natural gas processing utilizes service contracts that are either fee-based, commodity-based or a combination of the two. Our commodity-based contracts include keepwhole, margin-band, percent-of-liquids, percent-of-proceeds and contracts featuring a combination of commodity and fee-based terms.  When a cash fee for natural gas processing services is stipulated by a contract, we record revenue as a producer’s natural gas has been processed.

Under ASC 605, our natural gas processing business did not recognize revenue in connection with non-cash consideration (the “equity NGL volumes”) it received under percent-of-liquids and similar arrangements. We recognized revenue when the associated NGLs were delivered and sold to downstream customers under NGL marketing product sales contracts.

Under ASC 606, our natural gas processing business recognizes the value of the equity NGL volumes it receives from customers as a form of midstream service revenue. The value assigned to this non-cash consideration and related inventory is based on the market value of the equity NGLs we are entitled to when the services are performed.  We also recognize revenue, along with a corresponding cost of sales, when the NGLs are delivered and sold to downstream customers under NGL marketing product sales contracts.
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


The additional service revenue recognized for the non-cash consideration increased our total revenues by approximately 2% for the nine months ended September 30, 2018 when compared to the amount of revenues we would have recognized under ASC 605 for the quarter.  Given the rapid turnover of our inventories of NGL products each month, we do not expect a significant change in our gross operating margin from natural gas processing and related NGL marketing activities as a result of the changes required by ASC 606.


Unbilled Revenue and Deferred Revenue

The following table provides information regarding our contract assets and contract liabilities at September 30, 2018:2019:


Contract AssetLocation Balance Location Balance 
Unbilled revenue (current amount)Prepaid and other current assets $188.6 Prepaid and other current assets $223.8 
Unbilled revenue (noncurrent)Other assets  -- 
Total  $188.6   $223.8 


Contract LiabilityLocation Balance Location Balance 
Deferred revenue (current amount)Other current liabilities $94.4 Other current liabilities $137.4 
Deferred revenue (noncurrent)Other long-term liabilities  191.2 Other long-term liabilities  192.2 
Total  $285.6   $329.6 


The following table presents significant changes in our unbilled revenue and deferred revenue balances during the nine months ended September 30, 2018:2019:


  
Unbilled
Revenue
  
Deferred
Revenue
 
Balance at January 1, 2018 (upon adoption of ASC 606) $--  $224.7 
Amount included in opening balance transferred to other accounts during period (1)  --   (83.5)
Amount recorded during period  224.1   334.3 
Amounts recorded during period transferred to other accounts (1)  (37.7)  (189.9)
Amount recorded in connection with business combination  2.2   -- 
Balance at September 30, 2018 $188.6  $285.6 
         
(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.
 

 
Unbilled
Revenue
  
Deferred
Revenue
 
Balance at December 31, 2018 $13.3  $291.2 
Amount included in opening balance transferred to other accounts during period (1)  (13.3)  (110.9)
Amount recorded during period  270.5   430.7 
Amounts recorded during period transferred to other accounts (1)  (46.7)  (278.7)
Other changes  –   (2.7)
Balance at September 30, 2019 $223.8  $329.6 


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

Remaining Performance Obligations

The following table presents estimated fixed future consideration from contracts with customers as of September 30, 2019 that contain minimum volume commitments, deficiency and similar fees, and the term of the contracts exceedscontract terms exceeding one year. These amounts represent the revenues we expect to recognize in future periods from these contracts at September 30, 2018.  For a significant portion of our revenue, we bill customers a contractual rate for the services provided multiplied by the amount of volume handled in a given period.  We have the right to invoice the customer in the amount that corresponds directly with the value of our performance completed to date.  Therefore, we are not required to disclose information about the variable consideration of remaining performance obligations as we recognize revenue equal to the amount that we have the right to invoice.


Remainder
of 2018
  2019  2020  2021  2022  Thereafter  Total 
$816.6  $3,361.4  $3,036.9  $2,528.8  $2,050.0  $8,718.0  $20,511.7 

Period Fixed Consideration 
Three Months Ended December 31, 2019 $945.0 
One Year Ended December 31, 2020  3,505.7 
One Year Ended December 31, 2021  3,075.3 
One Year Ended December 31, 2022  2,636.9 
One Year Ended December 31, 2023  2,203.9 
Thereafter  
  10,576.7 
Total $22,943.5 
Impact of Change in Accounting Policy – ASC 606 Transition Disclosures
The following information and tables are provided to summarize the material impacts of adopting ASC 606 on our consolidated financial statements for the three and nine months ended September 30, 2018.

As noted previously, additional service revenue and related inventory is now recognized in connection with the equity NGL volumes (a form of non-cash consideration) we receive under natural gas processing agreements.  When the inventory is sold through our NGL marketing activities, we reflect additional cost of sales amounts within our operating costs and expenses.

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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Unbilled revenues have historically been presented as a component of accounts receivable on our consolidated balance sheets.  Upon implementation of ASC 606, we reclassified these amounts to “Prepaid and other current assets” since these amounts represent conditional rights to consideration.  Once we have an unconditional right to consideration, the amount is transferred to accounts receivable.

Historically, amounts received from customers as CIACs related to pipeline construction activities and production well tie-ins have been netted against property, plant and equipment on our consolidated balance sheets and presented as a cash inflow within the investing activities section of our statements of consolidated cash flows. Upon implementation of ASC 606, these amounts are now recognized as a component of midstream service revenue on our statement of operations and are a component of cash provided by operating activities as presented on our statements of consolidated cash flows.

Unaudited Condensed Consolidated Balance Sheet Information at September 30, 2018

  Impact of change in accounting policy 
  
Balances without
adoption of
ASC 606
  
Impact of
adoption of
ASC 606
  
As
Reported
 
Assets         
Accounts receivable – trade, net $4,411.5  $(188.6) $4,222.9 
Prepaid and other current assets $421.3  $188.6  $609.9 
Property, plant and equipment, net $37,727.7  $75.2  $37,802.9 
Other assets $260.6  $--  $260.6 
Liabilities and Equity            
Other long-term liabilities $679.3  $67.9  $747.2 
Partners' equity $23,065.8  $7.3  $23,073.1 

The impact of adoption of ASC 606 includes the reclassification of unbilled revenue amounts of $188.6 million from accounts receivable to other current assets.

Unaudited Condensed Consolidated Statement of Operations Information
   for the Three Months Ended September 30, 2018

  Impact of change in accounting policy 
  
Balances without
adoption of
ASC 606
  
Impact of
adoption of
ASC 606
  
As
Reported
 
Revenues $9,367.6  $218.3  $9,585.9 
Costs and expenses:            
Operating costs and expenses: $7,786.1  $215.8  $8,001.9 

Unaudited Condensed Consolidated Statement of Operations Information
   for the Nine Months Ended September 30, 2018

  Impact of change in accounting policy 
  
Balances without
adoption of
ASC 606
  
Impact of
adoption of
ASC 606
  
As
Reported
 
Revenues $26,853.2  $498.7  $27,351.9 
Costs and expenses:            
Operating costs and expenses: $23,285.2  $491.4  $23,776.6 

The impact of adopting ASC 606 on revenues for the three and nine months ended September 30, 2018 includes the recognition of $215.8 million and $491.4 million, respectively, of revenues from non-cash consideration (i.e., equity NGLs) earned when providing natural gas processing services and $2.5 million and $7.3 million, respectively, recognized in connection with CIACs.  Operating costs and expenses for the three and nine months ended September 30, 2018 includes $215.8 million and $491.4 million, respectively, attributable to cost of sales recognized when the equity NGL products are sold and delivered to customers.

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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Unaudited Condensed Consolidated Statement of Cash Flows Information
   for the Nine Months Ended September 30, 2018

  Impact of change in accounting policy 
  
Balances without
adoption of
ASC 606
  
Impact of
adoption of
ASC 606
  
As
Reported
 
Operating activities:         
   Net income $2,926.0  $7.3  $2,933.3 
   Net effect of changes in operating accounts $(329.8) $67.9  $(261.9)
Investing activities:            
   Contributions in aid of construction costs $67.9  $(67.9) $-- 



Note 10.  Business Segments and Related Information


Our operations are reported under four4 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 chief operating decision makers in deciding how to allocate resources and in assessing operating and financial performance.


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.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


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


  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2018  2017  2018  2017 
Operating income $1,643.3  $879.2  $3,768.2  $2,849.5 
Adjustments to reconcile operating income to total gross operating margin:                
   Add depreciation, amortization and accretion expense in operating costs and expenses  429.4   383.9   1,249.0   1,139.3 
   Add asset impairment and related charges in operating costs and expenses  4.6   10.0   21.4   35.2 
   Subtract net gains attributable to asset sales in operating costs and expenses  (6.7)  (1.1)  (8.1)  (1.1)
   Add general and administrative costs  52.7   41.3   157.1   137.4 
Adjustments for make-up rights on certain new pipeline projects:                
   Add non-refundable payments received from shippers attributable to make-up rights (1)  6.5   (1.9)  14.8   19.7 
   Subtract the subsequent recognition of revenues attributable to make-up rights (2)  (6.2)  (7.0)  (42.4)  (22.9)
Total segment gross operating margin $2,123.6  $1,304.4  $5,160.0  $4,157.1 
                 
(1)   Since make-up rights entail a future performance obligation by the pipeline to the shipper, these receipts are recorded as deferred revenue for GAAP purposes; however, these receipts are included in gross operating margin in the period of receipt since they are nonrefundable to the shipper.
(2)   As deferred revenues attributable to make-up rights are subsequently recognized as revenue under GAAP, gross operating margin must be adjusted to remove such amounts to prevent duplication since the associated non-refundable payments were previously included in gross operating margin.
 
  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2019  2018  2019  2018 
Operating income $1,474.2  $1,643.3  $4,660.7  $3,768.2 
Adjustments to reconcile operating income to total segment gross operating margin
   (addition or subtraction indicated by sign):
                
Depreciation, amortization and accretion expense in operating costs and expenses  467.1   429.4   1,380.8   1,249.0 
Asset impairment and related charges in operating costs and expenses  39.4   4.6   51.2   21.4 
Net gains attributable to asset sales in operating costs and expenses  (0.1)  (6.7)  (2.6)  (8.1)
General and administrative costs  55.5   52.7   160.2   157.1 
Non-refundable payments received from shippers attributable to make-up rights (1)
  20.8   6.5   34.3   14.8 
Subsequent recognition of revenues attributable to make-up rights (2)  (5.5)  (6.2)  (18.6)  (42.4)
Total segment gross operating margin $2,051.4  $2,123.6  $6,266.0  $5,160.0 

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


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,
  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
 2018  2017  2018  2017  2019  2018  2019  2018 
Gross operating margin by segment:                        
NGL Pipelines & Services $1,063.1  $770.9  $2,861.7  $2,386.8  $1,008.3  $1,063.1  $2,933.8  $2,861.7 
Crude Oil Pipelines & Services  594.2   190.4   867.0   691.7   496.2   594.2   1,671.7   867.0 
Natural Gas Pipelines & Services  216.9   170.7   628.2   536.0   258.5   216.9   824.6   628.2 
Petrochemical & Refined Products Services  249.4   172.4   803.1   542.6   288.4   249.4   835.9   803.1 
Total segment gross operating margin $2,123.6  $1,304.4  $5,160.0  $4,157.1  $2,051.4  $2,123.6  $6,266.0  $5,160.0 


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

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

For information regarding our hedging activities, see Note 13.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Summarized Segment Financial Information

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


 Reportable Business Segments        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, 2019 $3,250.1  $2,467.9  $712.3  $1,518.2  $–  $7,948.5 
Three months ended September 30, 2018 $4,616.7  $2,490.7  $846.4  $1,617.9  $--  $9,571.7   4,616.7   2,490.7   846.4   1,617.9   –   9,571.7 
Three months ended September 30, 2017  2,911.1   1,790.7   793.3   1,379.3   --   6,874.4 
Nine months ended September 30, 2019  9,843.9   7,916.5   2,451.6   4,518.2   –   24,730.2 
Nine months ended September 30, 2018  11,295.1   8,777.2   2,437.9   4,747.2   --   27,257.4   11,295.1   8,777.2   2,437.9   4,747.2   –   27,257.4 
Nine months ended September 30, 2017  8,871.9   5,489.1   2,334.0   4,086.7   --   20,781.7 
Revenues from related parties:                                                
Three months ended September 30, 2019  2.0   10.4   3.2   –   –   15.6 
Three months ended September 30, 2018  6.2   4.2   3.8   --   --   14.2   6.2   4.2   3.8   –   –   14.2 
Three months ended September 30, 2017  3.2   6.0   3.3   --   --   12.5 
Nine months ended September 30, 2019  7.3   35.7   10.7   –   –   53.7 
Nine months ended September 30, 2018  14.8   69.8   9.9   --   --   94.5   14.8   69.8   9.9   –   –   94.5 
Nine months ended September 30, 2017  8.8   14.4   10.0   --   --   33.2 
Intersegment and intrasegment revenues:                                                
Three months ended September 30, 2019  4,729.3   9,479.7   141.7   558.1   (14,908.8)  – 
Three months ended September 30, 2018  6,814.9   6,278.8   186.6   844.3   (14,124.6)  --   6,814.9   6,278.8   186.6   844.3   (14,124.6)  – 
Three months ended September 30, 2017  5,055.1   2,552.9   220.1   426.4   (8,254.5)  -- 
Nine months ended September 30, 2019  14,715.5   26,818.0   500.2   1,890.4   (43,924.1)  – 
Nine months ended September 30, 2018  19,384.4   27,683.6   522.5   2,241.6   (49,832.1)  --   19,384.4   27,683.6   522.5   2,241.6   (49,832.1)  – 
Nine months ended September 30, 2017  19,572.0   9,410.6   635.2   1,230.8   (30,848.6)  -- 
Total revenues:                                                
Three months ended September 30, 2019  7,981.4   11,958.0   857.2   2,076.3   (14,908.8)  7,964.1 
Three months ended September 30, 2018  11,437.8   8,773.7   1,036.8   2,462.2   (14,124.6)  9,585.9   11,437.8   8,773.7   1,036.8   2,462.2   (14,124.6)  9,585.9 
Three months ended September 30, 2017  7,969.4   4,349.6   1,016.7   1,805.7   (8,254.5)  6,886.9 
Nine months ended September 30, 2019  24,566.7   34,770.2   2,962.5   6,408.6   (43,924.1)  24,783.9 
Nine months ended September 30, 2018  30,694.3   36,530.6   2,970.3   6,988.8   (49,832.1)  27,351.9   30,694.3   36,530.6   2,970.3   6,988.8   (49,832.1)  27,351.9 
Nine months ended September 30, 2017  28,452.7   14,914.1   2,979.2   5,317.5   (30,848.6)  20,814.9 
Equity in income (loss) of unconsolidated affiliates:                                                
Three months ended September 30, 2019  25.9   113.2   1.6   (1.4)  –   139.3 
Three months ended September 30, 2018  28.3   83.7   2.1   (2.1)  --   112.0   28.3   83.7   2.1   (2.1)  –   112.0 
Three months ended September 30, 2017  18.8   95.9   0.9   (2.2)  --   113.4 
Nine months ended September 30, 2019  82.7   348.8   4.9   (5.1)  –   431.3 
Nine months ended September 30, 2018  87.1   265.1   4.7   (6.9)  --   350.0   87.1   265.1   4.7   (6.9)  –   350.0 
Nine months ended September 30, 2017  53.3   266.3   2.8   (7.2)  --   315.2 


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, 2018 $14,847.7  $5,665.2  $8,325.2  $6,194.9  $2,769.9  $37,802.9 
At December 31, 2017  13,831.2   5,208.4   8,375.0   3,507.7   4,698.1   35,620.4 
Investments in unconsolidated affiliates:
(see Note 5)
                        
At September 30, 2018  658.2   1,859.8   22.0   63.4   --   2,603.4 
At December 31, 2017  733.9   1,839.2   20.8   65.5   --   2,659.4 
Intangible assets, net: (see Note 6)
                        
At September 30, 2018  389.2   2,119.2   989.3   156.5   --   3,654.2 
At December 31, 2017  322.3   2,186.5   1,018.4   163.1   --   3,690.3 
Goodwill: (see Note 6)
                        
At September 30, 2018  2,651.7   1,841.0   296.3   956.2   --   5,745.2 
At December 31, 2017  2,651.7   1,841.0   296.3   956.2   --   5,745.2 
Segment assets:                        
At September 30, 2018  18,546.8   11,485.2   9,632.8   7,371.0   2,769.9   49,805.7 
At December 31, 2017  17,539.1   11,075.1   9,710.5   4,692.5   4,698.1   47,715.3 
  Reportable Business Segments       
  
NGL
Pipelines
& Services
  
Crude Oil
Pipelines
& Services
  
Natural Gas
Pipelines
& Services
  
Petrochemical
& Refined
Products
Services
  
Adjustments
and
Eliminations
  
Consolidated
Total
 
Property, plant and equipment, net:
(see Note 4)
                  
At September 30, 2019 $16,212.2  $6,316.2  $8,320.5  $6,356.3  $3,558.1  $40,763.3 
At December 31, 2018  14,845.4   5,847.7   8,303.8   6,213.9   3,526.8   38,737.6 
Investments in unconsolidated affiliates:
(see Note 5)
                        
At September 30, 2019  690.9   1,877.2   31.4   61.4   –   2,660.9 
At December 31, 2018  662.0   1,867.5   22.8   62.8   –   2,615.1 
Intangible assets, net: (see Note 6)
                        
At September 30, 2019  366.7   2,023.4   951.4   147.9   –   3,489.4 
At December 31, 2018  380.1   2,094.6   979.3   154.4   –   3,608.4 
Goodwill: (see Note 6)
                        
At September 30, 2019  2,651.7   1,841.0   296.3   956.2   –   5,745.2 
At December 31, 2018  2,651.7   1,841.0   296.3   956.2   –   5,745.2 
Segment assets:                        
At September 30, 2019  19,921.5   12,057.8   9,599.6   7,521.8   3,558.1   52,658.8 
At December 31, 2018  18,539.2   11,650.8   9,602.2   7,387.3   3,526.8   50,706.3 


Segment assets consist of property, plant and equipment, investments in unconsolidated affiliates, intangible assets and goodwill.  The carrying values of such amounts are assigned to each segment based on each asset’s or investment’s principal operations and contribution to the gross operating margin of that particular segment.  Since construction-in-progress amounts (a component of property, plant and equipment) generally do not contribute to segment gross operating margin, such amounts are excluded from segment asset totals until the underlying assets are placed in service.  Intangible assets and goodwill are assigned to each segment based on the classification of the assets to which they relate.  The remainder of our consolidated total assets, which consist primarily of working capital assets, are excluded from segment assets since these amounts are not attributable to one specific segment (e.g. cash).

OtherSupplemental 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,
 
 2018  2017  2018  2017  2019  2018  2019  2018 
Consolidated revenues:                        
NGL Pipelines & Services $4,622.9  $2,914.3  $11,309.9  $8,880.7  $3,252.1  $4,622.9  $9,851.2  $11,309.9 
Crude Oil Pipelines & Services  2,494.9   1,796.7   8,847.0   5,503.5   2,478.3   2,494.9   7,952.2   8,847.0 
Natural Gas Pipelines & Services  850.2   796.6   2,447.8   2,344.0   715.5   850.2   2,462.3   2,447.8 
Petrochemical & Refined Products Services  1,617.9   1,379.3   4,747.2   4,086.7   1,518.2   1,617.9   4,518.2   4,747.2 
Total consolidated revenues $9,585.9  $6,886.9  $27,351.9  $20,814.9  $7,964.1  $9,585.9  $24,783.9  $27,351.9 
                                
Consolidated costs and expenses                                
Operating costs and expenses:                                
Cost of sales $6,838.9  $5,049.6  $20,371.2  $15,116.4  $5,276.5  $6,838.9  $16,721.5  $20,371.2 
Other operating costs and expenses (1)  735.7   637.4   2,143.1   1,853.4   790.8   735.7   2,243.4   2,143.1 
Depreciation, amortization and accretion  429.4   383.9   1,249.0   1,139.3   467.1   429.4   1,380.8   1,249.0 
Asset impairment and related charges  4.6   10.0   21.4   35.2   39.4   4.6   51.2   21.4 
Net gains attributable to asset sales
  (6.7)  (1.1)  (8.1)  (1.1)  (0.1)  (6.7)  (2.6)  (8.1)
General and administrative costs  52.7   41.3   157.1   137.4   55.5   52.7   160.2   157.1 
Total consolidated costs and expenses $8,054.6  $6,121.1  $23,933.7  $18,280.6  $6,629.2  $8,054.6  $20,554.5  $23,933.7 
 
(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.
 


(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.
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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


Note 11.   Business Combinations

On March 29, 2018, we acquired the remaining 50% member interest in our Delaware Processing joint venture for $150.6 million in cash, net of $3.9 million of cash held by the former joint venture.  As a result, Delaware Processing is now our wholly-owned consolidated subsidiary.  Delaware Processing owns a cryogenic natural gas processing facility having a capacity of 150 million cubic feet per day.  The facility is located in Reeves County, Texas and entered service in August 2016.  The acquired business serves growing production of NGL-rich natural gas from the Delaware Basin in West Texas and southern New Mexico.

The following table presents the final fair value allocation of assets acquired and liabilities assumed in the acquisition at March 29, 2018.

Purchase price for remaining 50% equity interest in Delaware Processing $154.5 
Fair value of our 50% equity interest in Delaware Processing held before the acquisition  146.4 
   Total  300.9 
Recognized amounts of identifiable assets acquired and liabilities assumed:    
   Assets acquired in business combination:    
  Current assets, including cash of $3.9 million $10.8 
  Property, plant and equipment  200.0 
  Contract-based intangible assets  82.6 
  Customer relationship intangible assets  9.9 
  Total assets acquired $303.3 
   Liabilities assumed in business combination:    
  Current liabilities $(1.8)
  Long-term liabilities  (0.6)
  Total liabilities assumed $(2.4)
Total identifiable net assets $300.9 
Goodwill $-- 

Prior to this acquisition, we accounted for our investment using the equity method.  On a historical pro forma basis, our revenues, costs and expenses, operating income, net income attributable to Enterprise Products Partners L.P. and earnings per unit amounts for the three and nine months ended September 30, 2018 and 2017 would not have differed materially from those we actually reported had the acquisition been completed on January 1, 2017 rather than March 29, 2018.

At March 29, 2018, our 50% equity investment in Delaware Processing was recorded at $107.0 million.  Upon acquisition of the remaining 50% member interest, our existing equity investment was remeasured to fair value resulting in the recognition of a non-cash $39.4 million gain, which is presented within Other Income on our Unaudited Condensed Consolidated Statement of Operations for the nine months ended September 30, 2018.

The results for this business will continue to be reported under the NGL Pipelines & Services business segment.


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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



Note 12.11.  Earnings Per Unit


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


 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
 2018  2017  2018  2017  2019  2018  2019  2018 
BASIC EARNINGS PER UNIT                        
Net income attributable to limited partners $1,313.2  $610.9  $2,887.7  $2,025.3  $1,019.2  $1,313.2  $3,494.4  $2,887.7 
Undistributed earnings allocated and cash payments on phantom unit awards (1)  (6.2)  (4.0)  (15.5)  (12.0)  (6.1)  (6.2)  (21.3)  (15.5)
Net income available to common unitholders $1,307.0  $606.9  $2,872.2  $2,013.3  $1,013.1  $1,307.0  $3,473.1  $2,872.2 
                                
Basic weighted-average number of common units outstanding  2,179.9   2,151.1   2,173.8   2,140.7   2,189.1   2,179.9   2,188.4   2,173.8 
                                
Basic earnings per unit $0.60  $0.28  $1.32  $0.94  $0.46  $0.60  $1.59  $1.32 
                                
DILUTED EARNINGS PER UNIT                                
Net income attributable to limited partners $1,313.2  $610.9  $2,887.7  $2,025.3  $1,019.2  $1,313.2  $3,494.4  $2,887.7 
                                
Diluted weighted-average number of units outstanding:                                
Distribution-bearing common units  2,179.9   2,151.1   2,173.8   2,140.7   2,189.1   2,179.9   2,188.4   2,173.8 
Phantom units (1)  10.6   9.5   10.6   9.3   13.2   10.6   13.1   10.6 
Total  2,190.5   2,160.6   2,184.4   2,150.0   2,202.3   2,190.5   2,201.5   2,184.4 
                                
Diluted earnings per unit $0.60  $0.28  $1.32  $0.94  $0.46  $0.60  $1.59  $1.32 
 
(1) Each phantom unit award includes a distribution equivalent right (“DER”), which entitles the recipient to receive cash payments equal to the product of the number of phantom unit awards and the cash distribution per unit paid to our common unitholders. Cash payments made in connection with DERs are nonforfeitable. As a result, the phantom units are considered participating securities for purposes of computing basic earnings per unit.
 


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



Note 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,
 
 2018  2017  2018  2017  2019  2018  2019  2018 
Equity-classified awards:                        
Phantom unit awards $24.2  $23.1  $74.7  $69.4  $34.7  $24.2  $99.6  $74.7 
Restricted common unit awards  --   --   --   0.5 
Profits interest awards  1.2   1.4   3.8   4.5   2.5   1.2   8.1   3.8 
Liability-classified awards  0.1   0.1   0.3   0.3   0.1   0.1   0.1   0.3 
Total $25.5  $24.6  $78.8  $74.7  $37.3  $25.5  $107.8  $78.8 


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


At September 30, 2018, all of the outstanding phantom unit awards were granted under the 2008 Plan.  The maximum number of common units authorized for issuance under the 2008 Plan was 45,000,000 at September 30, 2018.  This amount will automatically increase under the terms of the 2008 Plan by 5,000,000 common units on January 1, 2019 and will continue to automatically increase annually on each January 1 thereafter during the term of the 2008 Plan; provided, however, that in no event shall the maximum aggregate number exceed 70,000,000 common units.  After giving effect to awards granted under the 2008 Plan through September 30, 2018, a total of 19,103,563 additional common units were available for issuance under this plan.

EPCO serves as the general partner of four limited partnerships that were formed in 2016 (generally referred to as “Employee Partnerships”) to serve as incentive arrangements for key employees of EPCO by providing them a “profits interest” in an Employee Partnership.  The names of the Employee Partnerships are EPD PubCo Unit I L.P. (“PubCo I”), EPD PubCo Unit II L.P. (“PubCo II”), EPD PubCo Unit III L.P. (“PubCo III”) and EPD PrivCo Unit I L.P. (“PrivCo I”).


Phantom Unit Awards

Phantom unit awards allow recipients to acquire ourEPD common units (at no cost to the recipient apart from fulfilling service and other conditions) once a defined vesting period expires, subject to customary forfeiture provisions.  Phantom unit awards generally vest at a rate of 25% per year beginning one year after the grant date and are non-vested until the required service periods expire.

At September 30, 2018, substantially all of our phantom unit awards are expected to result in the issuance of common units upon vesting; therefore, the applicable awards are accounted for as equity-classified awards.  The grant date fair value of a phantom unit award is based on the market price per unit of our common units on the date of grant.  Compensation expense is recognized based on the grant date fair value, net of an allowance for estimated forfeitures, over the requisite service or vesting period.

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 January 1, 2018  9,289,501  $27.65 
Phantom unit awards at December 31, 2018  10,333,277  $26.97 
Granted (2)  4,988,081  $26.82   6,851,920  $27.75 
Vested  (3,437,668) $28.59   (3,810,666) $27.54 
Forfeited  (434,164) $26.89   (268,621) $27.21 
Phantom unit awards at September 30, 2018  10,405,750  $26.97 
 
(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 2018 was $133.8 million based on a grant date market price of our common units ranging from $25.40 to $29.22 per unit. An estimated annual forfeiture rate of 3.2% was applied to these awards.
 
Phantom unit awards at September 30, 2019  13,105,910  $27.21 


(1)Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued.
(2)The aggregate grant date fair value of phantom unit awards issued during 2019 was $190.2 million based on a grant date market price of EPD common units ranging from $27.75 to $29.29 per unit.  An estimated annual forfeiture rate of 3.0% was applied to these awards.

The 2008 Plan provides for the issuance of DERs in connection withEach phantom unit awards.  Aaward includes a DER, which entitles the participantrecipient to nonforfeitablereceive 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 to ourEPD’s common unitholders.  Cash payments made in connection with DERs are nonforfeitable and charged to partners’ equity when the phantom unit award is expected to result in the issuance of common units; otherwise, such amounts are expensed.


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


 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
 2018  2017  2018  2017  2019  2018  2019  2018 
Cash payments made in connection with DERs $4.6  $4.0  $13.2  $11.2  $5.9  $4.6  $16.4  $13.2 
Total intrinsic value of phantom unit awards that vested during period  4.5   1.6   89.6   67.9   7.2   4.5   108.9   89.6 


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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
For the EPCO group of companies, theThe unrecognized compensation cost associated with phantom unit awards was $130.3$172.5 million at September 30, 2018,2019, of which our share of the cost is currently estimated to be $108.3$144.2 million.  Due to the graded vesting provisions of these awards, we expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 2.1 years.


Profits Interest Awards
In 2016,
EPCO Holdings Inc. (“EPCO Holdings”has established five limited partnerships (referred to as “Employee Partnerships”), a privately held affiliate that serve as long-term incentive arrangements for key employees of EPCO contributedby providing them a portion of the Enterprise common units it owned to eachprofits interest in one or more of the Employee Partnerships.  In exchange for these contributions, EPCO Holdings was admitted as the Class A limited partner of each Employee Partnership.  Also on the applicable contribution date, certain key EPCO employees were issued Class B limited partner interests (i.e., profits interest awards) and admitted as Class B limited partners of each Employee Partnership, all without any capital contribution by such employees.  EPCO serves as the general partner of each Employee Partnership.

The following table summarizes key elements of each Employee Partnership at At September 30, 2018:

 
 
 
Employee
Partnership
 
Enterprise
Common Units
contributed to
Employee Partnership
by EPCO Holdings
 
Class A
Capital
     Base (1)
 
Class A
Preference
Return (2)
 
Expected
Vesting/
Liquidation
Date
Estimated
Grant Date
Fair Value of
Profits Interest
  Awards (3)
Unrecognized
Compensation
  Cost (4)
                 
PubCo I  2,723,052 $63.7 million $0.39 Feb. 2020$13.0 million$5.3 million
PubCo II  2,834,198 $66.3 million $0.39 Feb. 2021$14.9 million$8.1 million
PubCo III  105,000 $2.5 million $0.39 Apr. 2020$0.5 million$0.2 million
PrivCo I  1,111,438 $26.0 million $0.39 Feb. 2021$5.8 million$0.6 million
 
(1)   Represents fair market value of the Enterprise common units contributed to each Employee Partnership at the applicable contribution date.
(2)   Each quarter, the Class A limited partner in each Employee Partnership is paid a cash distribution equal to the product of (i) the number of common units owned by the Employee Partnership and (ii) the Class A Preference Return of $0.39 per unit (subject to equitable adjustment in order to reflect any equity split, equity distribution or dividend, reverse split, combination, reclassification, recapitalization or other similar event affecting such common units). To the extent that the Employee Partnership has cash remaining after making this quarterly payment to the Class A limited partner, the residual cash is distributed to the Class B limited partners on a quarterly basis.
(3)   Represents the total grant date fair value of the profits interest awards irrespective of how such costs will be allocated between us and EPCO and its privately held affiliates.
(4)   Represents our expected share of the unrecognized compensation cost at September 30, 2018. We expect to recognize our share of the unrecognized compensation cost for PubCo I, PubCo II, PubCo III and PrivCo I over a weighted-average period of 1.4 years, 2.4 years, 1.5 years and 2.4 years, respectively.

The grant date fair value of each Employee Partnership is based on (i) the estimated value (as determined using a Black-Scholes option pricing model) of such Employee Partnership’s assets that would be distributed to the Class B limited partners thereof upon liquidation and (ii) the value, based on a discounted cash flow analysis,2019, our share of the residual quarterly cash amounts that such Class B limited partners are expectedtotal unrecognized compensation cost related to receive over the life of the Employee Partnership.

The following table summarizes the assumptions we used in applying a Black-Scholes option pricing model to derive that portion of the estimated grant date fair value of the profits interest awards for each Employee Partnership:

ExpectedRisk-FreeExpectedExpected Unit
EmployeeLifeInterestDistributionPrice
Partnershipof AwardRateYieldVolatility
PubCo I4.0 years0.9% to 2.7%5.9% to 7.0%19% to 40%
PubCo II5.0 years1.1% to 2.8%5.9% to 7.0%24% to 40%
PubCo III4.0 years1.0% to 2.2%6.1% to 6.8%27% to 40%
PrivCo I5.0 years1.2% to 1.6%6.1% to 6.7%28% to 40%

Compensation expense attributable to the profits interest awards is based on the estimated grant date fair value of each award.  A portion of the fair value of these equity-based awards is allocated to us under the ASA as a non-cash expense.  We are not responsible for reimbursing EPCO for any expenses of the Employee Partnerships including the valuewas $27.3 million, which we expect to recognize over a weighted-average period of any contributions of units made by EPCO Holdings.3.4 years.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS




Note 14.13.  Derivative Instruments, Hedging Activities and Fair Value Measurements


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

On January 1, 2018, we early adopted ASU 2017-12, Derivatives and Hedging (Topic 815):  Targeted Improvements to Accounting for Hedging Activities.  Since the impact of the new guidance was not material to our consolidated financial statements, no transition adjustments were recorded. In accordance with ASU 2017-12 both the effective and ineffective portion of a cash flow hedge are initially reported as a component of accumulated other comprehensive income (loss) and reclassified into earnings when the forecasted transaction affects earnings.


Interest Rate Hedging Activities

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


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

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

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

Forward-Starting Swaps
The following table summarizes our portfolio of forward starting30-year forward-starting swaps at September 30, 2018:2019, 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
Average Rate
Locked
Accounting
Treatment
Number and Type
of Derivatives
Outstanding
Notional
Amount
Expected
Settlement
Date
Weighted-Average
Fixed Rate
Locked
Accounting
Treatment
Future long-term debt offering2 forward starting swaps$175.02/20192.56%Cash flow hedge1 forward-starting swap (1)$75.09/20202.39%Cash flow hedge
Future long-term debt offering1 forward-starting swap (1)$75.04/20212.41%Cash flow hedge
Future long-term debt offering5 forward-starting swaps (2)$500.09/20202.12%Cash flow hedge
Future long-term debt offering5 forward-starting swaps (2)$500.04/20212.13%Cash flow hedge


(1)These swaps were entered into in May 2019.
(2)These swaps were entered into in September 2019 as a result of the swaption exercise.

As a result of market conditions in January 2018, we elected to terminate $100 millionIn total, the notional amount of the forward starting swaps that were outstanding at December 31, 2017, which resulted in cash proceeds totaling $1.5 million for the first quarter of 2018.

In October 2018, we elected to terminate the remaining $175 million notional amount of forward startingforward-starting swaps outstanding at September 30, 2018 in connection with the issuance of $3.0 billion aggregate principal amount of senior notes (see Note 19). We received cash proceeds totaling $20.6 million in connection with these terminations.

We sold swaptions related to our2019 was $1.15 billion.  The weighted-average fixed interest rate hedging activities that resulted in the recognition of $7.2 million, $11.8 million and $10.4 millionthese derivative instruments is 2.16%.

27

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, 2018,2019, our predominant commodity hedging strategies consisted of (i) hedging anticipated future purchases and sales of commodity products associated with transportation, storage and blending activities, (ii) hedging natural gas processing margins and (iii) hedging the fair value of commodity products held in inventory.  

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The objective of our anticipated future commodity purchases and sales hedging program is to hedge the margins of certain transportation, storage, blending and operational activities by locking in purchase and sale prices through the use of derivative instruments and related contracts.

The objective of our natural gas processing hedging program is to hedge an amount of earnings associated with these activities.  We achieve this objective by executing fixed-price sales for a portion of our expected equity NGL production using derivative instruments and related contracts.  For certain natural gas processing contracts, the hedging of expected equity NGL production also involves the purchase of natural gas for plant thermal reduction, which is hedged using derivative instruments and related contracts.

The objective of our inventory hedging program is to hedge the fair value of commodity products currently held in inventory by locking in the sales price of the inventory through the use of derivative instruments and related contracts.


The following table summarizes our portfolio of commodity derivative instruments outstanding at September 30, 20182019 (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”))11.2n/aCash flow hedge15.2n/aCash flow hedge
Forecasted sales of NGLs (million barrels (“MMBbls”))
0.20.1Cash flow hedge1.8n/aCash flow hedge
Octane enhancement:      
Forecasted purchase of NGLs (MMBbls)1.10.2Cash flow hedge1.0n/aCash flow hedge
Forecasted sales of octane enhancement products (MMBbls)2.30.4Cash flow hedge8.11.6Cash flow hedge
Natural gas marketing:      
Natural gas storage inventory management activities (Bcf)2.0n/aFair value hedge3.2n/aFair value hedge
NGL marketing:      
Forecasted purchases of NGLs and related hydrocarbon products (MMBbls)36.80.2Cash flow hedge100.01.5Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products (MMBbls)60.00.2Cash flow hedge121.71.2Cash flow hedge
NGLs inventory management activities (MMBbls)0.2n/aFair value hedge0.3n/aFair value hedge
Refined products marketing:      
Forecasted purchase of refined products (MMBbls)0.6n/aCash flow hedge
Forecasted purchases of refined products (MMBbls)0.9n/aCash flow hedge
Forecasted sales of refined products (MMBbls)0.5n/aCash flow hedge0.9n/aCash flow hedge
Refined products inventory management activities (MMBbls)0.7n/aFair value hedge
Crude oil marketing:      
Forecasted purchases of crude oil (MMBbls)13.74.1Cash flow hedge10.4n/aCash flow hedge
Forecasted sales of crude oil (MMBbls)20.24.1Cash flow hedge13.8n/aCash flow hedge
Propylene marketing:   
Forecasted sales of NGLs for propylene marketing activities (MMBbls)0.3n/aCash flow hedge
Derivatives not designated as hedging instruments:
      
Natural gas risk management activities (Bcf) (3,4)89.72.5Mark-to-market
NGL risk management activities (MMBbls) (4)1.90.2Mark-to-market
Refined products risk management activities (MMBbls) (4)1.9n/aMark-to-market
Crude oil risk management activities (MMBbls) (4)54.217.7Mark-to-market
(1) Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes.
(2) The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is December 2020, March 2019 and December 2020, respectively.
(3) Current volumes include 33.3 Bcf of physical derivative instruments that are predominantly priced at a market-based index plus a premium or minus a discount related to location differences.
(4) Reflects the use of derivative instruments to manage risks associated with transportation, processing and storage assets.
Natural gas risk management activities (Bcf) (3)38.20.6Mark-to-market
NGL risk management activities (MMBbls) (3)2.4n/aMark-to-market
Refined products risk management activities (MMBbls) (3)7.6n/aMark-to-market
Crude oil risk management activities (MMBbls) (3)22.26.1Mark-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 January 2021, December 2019 and December 2022, respectively.
(3)Reflects the use of derivative instruments to manage risks associated with transportation, processing and storage assets.

The carrying amount of our inventories subject to fair value hedges was $53.3$21.1 million and $84.0$50.2 million at September 30, 20182019 and December 31, 2017, respectively.  These amounts, which are presented in “Inventories” on our Unaudited Condensed Consolidated Balance Sheets, are inclusive of cumulative fair value hedging adjustments of $4.8 million and $7.0 million at September 30, 2018, and December 31, 2017, respectively.


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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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


   Asset Derivatives Liability Derivatives 
   September 30, 2018 December 31, 2017 September 30, 2018 December 31, 2017 
   
Balance
Sheet
Location
 
Fair
Value
 
Balance
Sheet
Location
 
Fair
Value
 
Balance
Sheet
Location
 
Fair
Value
 
Balance
Sheet
Location
 
Fair
Value
 
Derivatives designated as hedging instruments
 
Interest rate derivatives Current assets $19.1 Current assets $-- 
Current
liabilities
 $-- 
Current
liabilities
 $1.5 
Interest rate derivatives Other assets  -- Other assets  0.1 Other liabilities  -- Other liabilities  0.2 
Total interest rate derivatives    19.1    0.1    --    1.7 
Commodity derivatives Current assets  210.5 Current assets  109.5 
Current
liabilities
  348.5 
Current
liabilities
  104.4 
Commodity derivatives Other assets  63.1 Other assets  6.4 Other liabilities  62.8 Other liabilities  6.8 
Total commodity derivatives    273.6    115.9    411.3    111.2 
Total derivatives designated as hedging instruments   $292.7   $116.0   $411.3   $112.9 
                       
Derivatives not designated as hedging instruments
 
Commodity derivatives Current assets $7.0 Current assets $43.9 
Current
liabilities
 $138.6 
Current
liabilities
 $62.3 
Commodity derivatives Other assets  2.8 Other assets  1.9 Other liabilities  10.6 Other liabilities  3.4 
Total commodity derivatives   $9.8   $45.8   $149.2   $65.7 



Asset Derivatives Liability Derivatives
 September 30, 2019 December 31, 2018 September 30, 2019 December 31, 2018
 
Balance
Sheet
Location
Fair
Value
 
Balance
Sheet
Location
Fair
Value
 
Balance
Sheet
Location
Fair
Value
 
Balance
Sheet
Location
Fair
Value
Derivatives designated as hedging instruments               
Interest rate derivativesCurrent assets$– Current assets$– 
Current
liabilities
$11.8 
Current
liabilities
$–
Interest rate derivativesOther assets – Other assets – Other liabilities 11.9 Other liabilities –
Total interest rate derivatives  –   –   23.7   –
Commodity derivativesCurrent assets 149.3 Current assets 138.5 
Current
liabilities
 139.2 
Current
liabilities
 115.0
Commodity derivativesOther assets 5.6 Other assets 5.6 Other liabilities 6.8 Other liabilities 11.1
Total commodity derivatives  154.9   144.1   146.0   126.1
Total derivatives designated as hedging instruments $154.9  $144.1  $169.7  $126.1
                
Derivatives not designated as hedging instruments               
Interest rate derivativesCurrent assets$– Current assets$– 
Current
liabilities
$47.2 
Current
liabilities
$–
Interest rate derivativesOther assets – Other assets – Other liabilities 47.7 Other liabilities –
Total interest rate derivatives  –   –   94.9   –
Commodity derivativesCurrent assets 16.7 Current assets 15.9 
Current
liabilities
 4.2 
Current
liabilities
 33.2
Commodity derivativesOther assets 1.0 Other assets 1.9 Other liabilities 0.3 Other liabilities 3.1
Total commodity derivatives  17.7   17.8   4.5   36.3
Total derivatives not designated as hedging instruments $17.7  $17.8  $99.4  $36.3

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


 Offsetting of Financial Assets and Derivative Assets 
 
Gross
Amounts of
Recognized
Assets
 
Gross
Amounts
Offset in the
Balance Sheet
 
Amounts
of Assets
Presented
in the
Balance Sheet
 
Gross Amounts Not Offset
in the Balance Sheet
 
Amounts That
Would Have
Been Presented
On Net Basis
 
Financial
Instruments
  
Cash
Collateral
Received
  
Cash
Collateral
Paid
 
 (i) (ii) (iii) = (i) – (ii) (iv) (v) = (iii) + (iv) 
As of September 30, 2018:                     
Interest rate derivatives $19.1  $--  $19.1  $--  $--  $--  $19.1 
Commodity derivatives  283.4   --   283.4   (279.7)  --   --   3.7 
As of December 31, 2017:                            
Interest rate derivatives $0.1  $--  $0.1  $(0.1) $--  $--  $-- 
Commodity derivatives  161.7   --   161.7   (157.8)  --   --   3.9 
 Offsetting of Financial Assets and Derivative Assets 
 
Gross
Amounts of
Recognized
Assets
 
Gross
Amounts
Offset in the
Balance Sheet
 
Amounts
of Assets
Presented
in the
Balance Sheet
 
Gross Amounts Not Offset
in the Balance Sheet
 
Amounts That
Would Have
Been Presented
On Net Basis
 
Financial
Instruments
 
Cash
Collateral
Received
 
Cash
Collateral
Paid
 
 (i) (ii) (iii) = (i) – (ii) (iv) (v) = (iii) + (iv) 
As of September 30, 2019:                     
Commodity derivatives $172.6  $–  $172.6  $(149.0) $–  $(22.4) $1.2 
As of December 31, 2018:                            
Commodity derivatives $161.9  $–  $161.9  $(158.6) $–  $–  $3.3 


 Offsetting of Financial Liabilities and Derivative Liabilities 
 
Gross
Amounts of
Recognized
Liabilities
 
Gross
Amounts
Offset in the
Balance Sheet
 
Amounts
of Liabilities
Presented
in the
Balance Sheet
 
Gross Amounts Not Offset
in the Balance Sheet
 
Amounts That
Would Have
Been Presented
On Net Basis
 
Financial
Instruments
  
Cash
Collateral
Received
  
Cash
Collateral
Paid
 
 (i) (ii) (iii) = (i) – (ii) (iv) (v) = (iii) + (iv) 
As of September 30, 2018:                     
Commodity derivatives $560.5  $--  $560.5  $(279.7) $--  $(279.2) $1.6 
As of December 31, 2017:                            
Interest rate derivatives $1.7  $--  $1.7  $(0.1) $--  $--  $1.6 
Commodity derivatives  176.9   --   176.9   (157.8)  --   (17.3)  1.8 
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 Offsetting of Financial Liabilities and Derivative Liabilities 
 
Gross
Amounts of
Recognized
Liabilities
 
Gross
Amounts
Offset in the
Balance Sheet
 
Amounts
of Liabilities
Presented
in the
Balance Sheet
 
Gross Amounts Not Offset
in the Balance Sheet
 
Amounts That
Would Have
Been Presented
On Net Basis
 
Financial
Instruments
  
Cash
Collateral
Received
  
Cash
Collateral
Paid
 
 (i) (ii) (iii) = (i) – (ii) (iv) (v) = (iii) + (iv) 
As of September 30, 2019:                     
Interest rate derivatives $118.6  $–  $118.6  $–  $–  $–  $118.6 
Commodity derivatives  150.5   –   150.5   (149.0)  –   0.3   1.8 
As of December 31, 2018:                            
Commodity derivatives $162.4  $–  $162.4  $(158.6) $–  $(2.3) $1.5 

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


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


Derivatives in Fair Value
Hedging Relationships
 
Location
 
Gain (Loss) Recognized in
Income on Derivative
 
 
Location
 
Gain (Loss) Recognized in
Income on Derivative
 
   
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
    
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2018  2017  2018  2017   2019  2018  2019  2018 
Interest rate derivativesInterest expense $--  $0.3  $1.3  $(0.2)Interest expense $–  $–  $–  $1.3 
Commodity derivativesRevenue  (1.4)  (37.9)  3.2   (0.3)Revenue  (0.4)  (1.4)  (2.0)  3.2 
Total  $(1.4) $(37.6) $4.5  $(0.5)  $(0.4) $(1.4) $(2.0) $4.5 


Derivatives in Fair Value
Hedging Relationships
 
Location
 
Gain (Loss) Recognized in
Income on Hedged Item
 
 
Location
 
Gain (Loss) Recognized in
Income on Hedged Item
 
   
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
    
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2018  2017  2018  2017   2019  2018  2019  2018 
Interest rate derivativesInterest expense $--  $(0.3) $(1.4) $0.3 Interest expense $–  $–  $–  $(1.4)
Commodity derivativesRevenue  3.7   51.4   1.9   22.7 Revenue  2.4   3.7   8.7   1.9 
Total  $3.7  $51.1  $0.5  $23.0   $2.4  $3.7  $8.7  $0.5 



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

Derivatives in Cash Flow
Hedging Relationships
 
Change in Value Recognized in
Other Comprehensive Income (Loss) on Derivative
 
  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2018  2017  2018  2017 
Interest rate derivatives $6.1  $(0.3) $20.7  $(4.8)
Commodity derivatives – Revenue (1)  (145.5)  (177.3)  (156.7)  1.7 
Commodity derivatives – Operating costs and expenses (1)  (0.3)  (0.5)  0.7   (4.3)
Total $(139.7) $(178.1) $(135.3) $(7.4)
  
(1)   The fair value of these derivative instruments will be reclassified to their respective locations on the Unaudited Condensed Statement of Consolidated Operations upon settlement of the underlying derivative transactions, as appropriate.
 


Derivatives in Cash Flow
Hedging Relationships
 
Change in Value Recognized in
Other Comprehensive Income (Loss) on Derivative
 
  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2019  2018  2019  2018 
Interest rate derivatives $(18.6) $6.1  $(23.8) $20.7 
Commodity derivatives – Revenue (1)  73.5   (145.5)  71.1   (156.7)
Commodity derivatives – Operating costs and expenses (1)  (1.2)  (0.3)  (12.5)  0.7 
Total $53.7  $(139.7) $34.8  $(135.3)

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

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Derivatives in Cash Flow
Hedging Relationships
Location 
Gain (Loss) Reclassified from
Accumulated Other Comprehensive Income (Loss) to Income
 Location 
Gain (Loss) Reclassified from
Accumulated Other Comprehensive Income (Loss) to Income
 
   
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
    
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2018  2017  2018  2017   2019  2018  2019  2018 
Interest rate derivativesInterest expense $(9.1) $(10.3) $(29.0) $(29.9)Interest expense $(9.4) $(9.1) $(27.8) $(29.0)
Commodity derivativesRevenue  53.9   10.6   28.5   49.1 Revenue  93.6   53.9   161.4   28.5 
Commodity derivativesOperating costs and expenses  (0.4)  (0.5)  0.3   (0.1)Operating costs and expenses  (2.1)  (0.4)  (9.4)  0.3 
Total  $44.4  $(0.2) $(0.2) $19.1   $82.1  $44.4  $124.2  $(0.2)


Over the next twelve months, we expect to reclassify $37.4$39.1 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 $194.5$66.3 million of lossesgains attributable to commodity derivative instruments from accumulated other comprehensive lossincome to earnings, $192.4$68.1 million as a decreasean increase in revenue and $2.1$1.8 million as an increase in operating costs and expenses.


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


Derivatives Not Designated
as Hedging Instruments
Location 
Gain (Loss) Recognized in
Income on Derivative
 Location 
Gain (Loss) Recognized in
Income on Derivative
 
   
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
    
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2018  2017  2018  2017   2019  2018  2019  2018 
Interest rate derivativesInterest expense $(94.9) $–  $(94.9) $– 
Commodity derivativesRevenue $21.8  $(15.5) $(538.0) $18.9 Revenue  21.8   21.8   96.7   (538.0)
Commodity derivativesOperating costs and expenses  (2.7)  (4.0)  (4.2)  (0.3)Operating costs and expenses  (1.6)  (2.7)  (6.3)  (4.2)
Total  $19.1  $(19.5) $(542.2) $18.6   $(74.7) $19.1  $(4.5) $(542.2)


The $542.2$4.5 million loss recognized during the 2018 earnings from derivatives not designated as hedging instruments reflects $288.2 million of realized losses on such instruments.  In the aggregate, our unrealized mark-to-market losses for the nine months ended September 30, 2018 were $259.72019 (as noted in the preceding table) from designated as hedging instruments consists of (i) $0.7 million inclusive of all derivative instrument types.   The following table summarizes the impactrealized losses and $91.1 million of net unrealized mark-to-market gains attributable to commodity derivatives and (ii) $94.9 million of unrealized mark-to-market losses on our gross operating margin by segmentattributable to interest rate derivatives.

In total and inclusive of both fair value hedges and derivatives not designated as hedging instruments, we recognized a net $2.0 million mark-to-market loss for the nine months ended September 30, 2018:2019 consisting of (i) $92.9 million of net unrealized mark-to-market gains attributable to commodity derivatives and (ii) $94.9 million of unrealized mark-to-market losses attributable to interest rate derivatives.

Unrealized mark-to-market gains (losses) by segment:   
NGL Pipelines & Services $8.0 
Crude Oil Pipelines & Services  (267.4)
Natural Gas Pipelines & Services  0.9 
Petrochemical & Refined Products Services  (1.2)
Total $(259.7)


Fair Value Measurements

The following tables set forth, by level within the Level 1, 2 and 3 fair value hierarchy, the carrying values of our financial assets and liabilities at the dates indicated.  These assets and liabilities are measured on a recurring basis and are classified based on the lowest level of input used to estimate their fair value.  Our assessment of the relative significance of such inputs requires judgment.
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The values for commodity derivatives are presented before and after the application of Rule 814 of the Chicago Mercantile Exchange (“CME”), Rule 814, which deems that financial instruments cleared by the CME are settled daily in connection with variation margin payments.  As a result of this exchange rule, CME-related derivatives are considered to have no fair value at the balance sheet date for financial reporting purposes; however, the derivatives remain outstanding and subject to future commodity price fluctuations until they are settled in accordance with their contractual terms.  Derivative transactions cleared on exchanges other than the CME (e.g., the Intercontinental Exchange or ICE) continue to be reported on a gross basis.


 
At September 30, 2018
Fair Value Measurements Using
     
At September 30, 2019
Fair Value Measurements Using
    
 
Quoted Prices
in Active
Markets for
Identical Assets
and Liabilities
(Level 1)
  
Significant
Other
Observable
Inputs
(Level 2)
  
Significant
Unobservable
Inputs
(Level 3)
  Total  
Quoted Prices
in Active
Markets for
Identical Assets
and Liabilities
(Level 1)
  
Significant
Other
Observable
Inputs
(Level 2)
  
Significant
Unobservable
Inputs
(Level 3)
  Total 
Financial assets:                        
Commodity derivatives:            
Value before application of CME Rule 814 $54.0  $365.4  $14.5  $433.9 
Impact of CME Rule 814  (44.8)  (206.3)  (10.2)  (261.3)
Total commodity derivatives  9.2   159.1   4.3   172.6 
Total $9.2  $159.1  $4.3  $172.6 
                
Financial liabilities:                
Liquidity Option Agreement (see Note 15) $–  $–  $513.1  $513.1 
Interest rate derivatives $--  $19.1  $--  $19.1   –   118.6   –   118.6 
Commodity derivatives:                                
Value before application of CME Rule 814  140.5   284.0   5.9   430.4   39.8   268.3   47.9   356.0 
Impact of CME Rule 814 change  (11.5)  (135.5)  --   (147.0)
Impact of CME Rule 814  (31.0)  (138.5)  (36.0)  (205.5)
Total commodity derivatives  129.0   148.5   5.9   283.4   8.8   129.8   11.9   150.5 
Total financial assets $129.0  $167.6  $5.9  $302.5 
                
Financial liabilities:                
Liquidity Option Agreement (see Note 16) $--  $--  $368.8  $368.8 
Interest rate derivatives  --   --   --   -- 
Commodity derivatives:                
Value before application of CME Rule 814  183.7   827.5   3.3   1,014.5 
Impact of CME Rule 814 change  (55.5)  (398.5)  --   (454.0)
Total commodity derivatives  128.2   429.0   3.3   560.5 
Total financial liabilities $128.2  $429.0  $372.1  $929.3 
Total $8.8  $248.4  $525.0  $782.2 


 
At December 31, 2017
Fair Value Measurements Using
     
At December 31, 2018
Fair Value Measurements Using
    
 
Quoted Prices
in Active
Markets for
Identical Assets
and Liabilities
(Level 1)
  
Significant
Other
Observable
Inputs
(Level 2)
  
Significant
Unobservable
Inputs
(Level 3)
  Total  
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 $--  $0.1  $--  $0.1 
Commodity derivatives:                            
Value before application of CME Rule 814  47.1   184.9   2.9   234.9  $172.3  $282.4  $2.2  $456.9 
Impact of CME Rule 814 change  (47.1)  (26.1)  --   (73.2)
Impact of CME Rule 814  (134.8)  (159.3)  (0.9)  (295.0)
Total commodity derivatives  --   158.8   2.9   161.7   37.5   123.1   1.3   161.9 
Total financial assets $--  $158.9  $2.9  $161.8 
Total $37.5  $123.1  $1.3  $161.9 
                                
Financial liabilities:                                
Liquidity Option Agreement (see Note 16) $--  $--  $333.9  $333.9 
Interest rate derivatives  --   1.7   --   1.7 
Liquidity Option Agreement (see Note 15) $–  $–  $390.0  $390.0 
Commodity derivatives:                                
Value before application of CME Rule 814  118.4   270.6   1.7   390.7   85.5   291.2   21.4   398.1 
Impact of CME Rule 814 change  (118.4)  (95.4)  --   (213.8)
Impact of CME Rule 814  (48.6)  (172.9)  (14.2)  (235.7)
Total commodity derivatives  --   175.2   1.7   176.9   36.9   118.3   7.2   162.4 
Total financial liabilities $--  $176.9  $335.6  $512.5 
Total $36.9  $118.3  $397.2  $552.4 



In the aggregate, the fair value of our commodity hedging portfolios at September 30, 2019 was a net derivative asset of $77.9million prior to the impact of CME Rule 814.

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

    
For the Nine Months
Ended September 30,
 
 Location  2018  2017 
Financial asset (liability) balance, net, January 1  $(332.7) $(268.2)
Total gains (losses) included in:         
Net income (1)Revenue  (0.5)  0.7 
Net incomeOther expense, net  (7.5)  (5.5)
Other comprehensive incomeCommodity derivative instruments – changes in fair value of cash flow hedges  --   -- 
Settlements (1)Revenue  (1.2)  (1.4)
Transfers out of Level 3   --   -- 
Financial asset (liability) balance, net, March 31   (341.9)  (274.4)
Total gains (losses) included in:         
Net income (1)Revenue  1.3   0.1 
Net incomeOther expense, net  (8.9)  (18.6)
Other comprehensive incomeCommodity derivative instruments – changes in fair value of cash flow hedges  --   0.1 
Settlements (1)Revenue  0.5   (0.7)
Transfers out of Level 3   --   -- 
Financial asset (liability) balance, net, June 30   (349.0)  (293.5)
Total gains (losses) included in:         
Net income (1)Revenue  (0.2)  0.3 
Net incomeOther expense, net  (18.5)  (8.9)
Other comprehensive incomeCommodity derivative instruments – changes in fair value of cash flow hedges  2.8   -- 
Settlements (1)Revenue  (1.3)  (0.1)
Transfers out of Level 3   --   -- 
Financial asset (liability) balance, net, September 30  $(366.2) $(302.2)
  
(1)   There were $1.5 million and $1.4 million of unrealized losses included in these amounts for the three and nine months ended September 30, 2018, respectively. There were unrealized gains of $0.2 million and unrealized losses of $1.1 million included in these amounts for the three and nine months ended September 30, 2017.
 

The followingtable provides quantitative information regarding our recurring Level 3 fair value measurements for commodity derivatives at September 30, 2018:2019:


 Fair Value      Fair Value     
 
Financial
Assets
  
Financial
Liabilities
 
Valuation
Techniques
Unobservable
Input
Range 
Financial
Assets
  
Financial
Liabilities
 
Valuation
Techniques
Unobservable
Input
Range
Commodity derivatives – Crude oil $1.5  $1.5 Discounted cash flowForward commodity prices$59.41-$73.56/barrel $0.5  $0.2 Discounted cash flowForward commodity prices$54.11-$54.78/barrel
Commodity derivatives – Propane  1.5   1.5 Discounted cash flowForward commodity prices$0.91-$0.94/gallon  1.2   3.7 Discounted cash flowForward commodity prices$0.43-$0.49/gallon
Commodity derivatives – Natural gasoline  –   4.3 Discounted cash flowForward commodity prices$0.96-$1.04/gallon
Commodity derivatives – Ethane  0.1   0.3 Discounted cash flowForward commodity prices$0.38-$0.51/gallon  1.5   1.3 Discounted cash flowForward commodity prices$0.18-$0.19/gallon
Commodity derivatives – Normal Butane  2.8   -- Discounted cash flowForward commodity prices$1.06-$1.27/gallon  0.5   2.2 Discounted cash flowForward commodity prices$0.48-$0.56/gallon
Commodity derivatives – Isobutane  0.6   0.2 Discounted cash flowForward commodity prices$0.53-$0.64/gallon
Total $5.9  $3.3      $4.3  $11.9     


With respect to commodity derivatives, we believe forward commodity prices are the most significant unobservable inputs in determining our Level 3 recurring fair value measurements at September 30, 2018.2019.  In general, changes in the price of the underlying commodity increases or decreases the fair value of a commodity derivative depending on whether the derivative was purchased or sold.  We generally expect changes in the fair value of our derivative instruments to be offset by corresponding changes in the fair value of our hedged exposures.

39The following table sets forth a reconciliation of changes in the fair values of our recurring Level 3 financial assets and liabilities on a combined basis for the periods indicated:

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

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

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Nonrecurring Fair Value Measurements
The following table summarizes our non-cash
Non-cash asset impairment charges for long-livedthe nine months ended September 30, 2019 were $51.3 million compared to $21.4 million for the nine months ended September 30, 2018. Charges for 2019 primarily relate to assets by segmentretired during each of the periods indicated:

  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2018  2017  2018  2017 
NGL Pipelines & Services $1.3  $5.4  $13.7  $8.4 
Crude Oil Pipelines & Services  --   1.8   0.3   2.4 
Natural Gas Pipelines & Services  1.0   1.9   3.5   11.8 
Petrochemical & Refined Products Services  1.6   0.6   3.1   0.6 
Total $3.9  $9.7  $20.6  $23.2 

quarter whose operations have ceased.  Impairment charges are primarily a component of “Operating costs and expenses” on our Unaudited Condensed Statements of Consolidated Operations.

Total asset impairment and related charges during the nine months ended September 30, 2018 and 2017 include impairment charges attributable to the write-down of spare parts classified as current assets of $0.8 million and $12.0 million, respectively.


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 $23.84$31.01 billion and $23.47$25.97 billion at September 30, 20182019 and December 31, 2017,2018, respectively.  The aggregate carrying value of these debt obligations was $23.15$27.95 billion and $21.48$26.15 billion at September 30, 20182019 and December 31, 2017,2018, respectively.  These values are primarily based on quoted market prices for such debt or debt of similar terms and maturities (Level 2), and our credit standing and the credit standing of our counterparties.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,
 
 2018  2017  2018  2017  2019  2018  2019  2018 
Revenues – related parties:                        
Unconsolidated affiliates $14.2  $12.5  $94.5  $33.2  $15.6  $14.2  $53.7  $94.5 
Costs and expenses – related parties:                                
EPCO and its privately held affiliates $285.9  $262.2  $802.8  $752.7  $297.8  $285.9  $837.9  $802.8 
Unconsolidated affiliates  110.0   74.1   351.4   167.2   94.7   110.0   313.3   351.4 
Total $395.9  $336.3  $1,154.2  $919.9  $392.5  $395.9  $1,151.2  $1,154.2 

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


 
September 30,
2018
  
December 31,
2017
  
September 30,
2019
  
December 31,
2018
 
Accounts receivable - related parties:            
Unconsolidated affiliates $1.6  $1.8  $2.0  $3.5 
                
Accounts payable - related parties:                
EPCO and its privately held affiliates $95.2  $99.3  $106.6  $116.3 
Unconsolidated affiliates  41.0   28.0   18.9   23.9 
Total $136.2  $127.3  $125.5  $140.2 


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


Relationship with EPCO and Affiliates

We have an extensive and ongoing relationship with EPCO and its privately held affiliates (including Enterprise GP, our general partner), which are not a part of our consolidated group of companies.  


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At September 30, 2018,2019, EPCO and its privately held affiliates (including Dan Duncan LLC and certain Duncan family trusts) beneficially owned the following limited partner interests in us:


Total Number
of Units
Percentage of
Total Units
Outstanding
Percentage of
Total Units
Outstanding
697,260,37832%
698,313,13731.9%


Of the total number of units held by EPCO and its privately held affiliates, 108,222,618 have been pledged as security under the credit facilities of EPCO and its privately held affiliates at September 30, 2018.2019.  These credit facilities contain customary and other events of default, including defaults by us and other affiliates of EPCO.  An event of default, followed by a foreclosure on the pledged collateral, could ultimately result in a change in ownership of these units and affect the market price of ourEPD’s common units.


We and Enterprise GP are both separate legal entities apart from each other and apart from EPCO and its other affiliates, with assets and liabilities that are also separate from those of EPCO and its other affiliates.  EPCO and its privately held affiliates depend on the cash distributions they receive from us and other investments to fund their other activities and to meet their debt obligations.  During the nine months ended September 30, 20182019 and 2017,2018, we paid EPCO and its privately held affiliates cash distributions totaling $867.4$893.1 million and $835.5$867.4 million, respectively.


From time-to-time, EPCO and its privately held affiliates elect to purchase additional common units under ourEPD’s DRIP and ATM program.  During the nine months ended September 30, 2018,2019, privately held affiliates of EPCO reinvested $206$21.6 million through the DRIP.  See Note 8 for additional information regarding ourthe DRIP.


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


 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
 2018  2017  2018  2017  2019  2018  2019  2018 
Operating costs and expenses $246.6  $230.1  $697.6  $657.6  $259.3  $246.6  $732.0  $697.6 
General and administrative expenses  35.0   27.6   92.6   81.5   34.2   35.0   92.9   92.6 
Total costs and expenses $281.6  $257.7  $790.2  $739.1  $293.5  $281.6  $824.9  $790.2 



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TableWe lease office space from privately held affiliates of Contents
ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
EPCO.  The rental rates in these lease agreements approximate market rates.  For the three and nine months ended September 30, 2019, we recognized $3.8 million and $11.1million, respectively, of related party operating lease expense in connection with these office space leases. For the three and nine months ended September 30, 2018, we recognized $3.8 million and $10.7million, respectively, of related party operating lease expense for these leases.  



Note 16.15.  Commitments and Contingencies


Litigation

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


Management has regular quarterly litigation reviews, including updates from legal counsel, to assess the possible need for accounting recognition and disclosure of these contingencies.  We accrue an undiscounted liability for those contingencies where the loss is probable and the amount can be reasonably estimated.  If a range of probable loss amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum amount in the range is accrued.

We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote.  For contingencies where an unfavorable outcome is reasonably possible and the impact would be material to our consolidated financial statements, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss.  Based on a consideration of all relevant known facts and circumstances, we do not believe that the ultimate outcome of any currently pending litigation directed against us will have a material impact on our consolidated financial statements either individually at the claim level or in the aggregate.

At September 30, 2018 and December 31, 2017, ourOur accruals for litigation contingencies were $0.5 million at September 30, 2019 and $4.5 million, respectively,December 31, 2018 and recorded in our Unaudited Condensed Consolidated Balance Sheets as a component of “Other current liabilities.”  Our evaluation
35


Energy Transfer Matter. 
In connection with a proposed pipeline project, we and ETP signed a non-binding letter of intent in April 2011 that disclaimed any partnership or joint venture related to such project absent executed definitive documents and board approvals of the respective companies.  Definitive agreements were never executed and board approval was never obtained for the potential pipeline project.  In August 2011, the proposed pipeline project was cancelled due to a lack of customer support.


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


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

We have not recorded a provision for this matter as management continues to believe that payment of damages by us in this case is not probable. We continue to monitor developments involving this matter.


PDH Litigation. 
In July 2013, we executed a contract with Foster Wheeler USA Corporation (“Foster Wheeler”) pursuant to which Foster Wheeler was to serve as the general contractor responsible for the engineering, procurement, construction and installation of our propane dehydrogenation (“PDH”) facility.  In November 2014, Foster Wheeler was acquired by an affiliate of AMEC plc to form Amec Foster Wheeler plc, and Foster Wheeler is now known as Amec Foster Wheeler USA Corporation (“AFW”).  In December 2015, Enterprise and AFW entered into a transition services agreement under which AFW was partially terminated from the PDH project.  In December 2015, Enterprise engaged a second contractor, Optimized Process Designs LLC (“OPD”), to complete the construction and installation of the PDH facility.


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


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Contractual Obligations

Scheduled Maturities of Debt. 
We have long-term and short-term payment obligations under debt agreements.  In total, the principal amount of our consolidated debt obligations were $28.20 billion and $26.42 billion at September 30, 2019 and December 31, 2018, respectively.  See Note 7 for additional information regarding our scheduled future maturities of debt principal.


Operating Lease Obligations.  ConsolidatedAccounting Matters
The following table presents information regarding our operating leases where we are the lessee at September 30, 2019:

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

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

The following table disaggregates our operating lease and rentalexpense for the periods indicated:

 
For the Three Months
Ended September 30, 2019
  
For the Nine Months
Ended September 30, 2019
 
Long-term operating leases:      
   Fixed lease expense $12.8  $39.3 
   Variable lease expense  1.6   4.5 
Subtotal operating lease expense  14.4   43.8 
Short-term lease expense  12.4   35.9 
Total operating lease expense $26.8  $79.7 

In total, operating lease expense was $26.8 million and $27.6 million and $26.0 million duringfor the three months ended September 30, 2019 and 2018, and 2017, respectively.  ForDuring the nine months ended September 30, 2019 and 2018 and 2017, consolidatedoperating lease and rental expense was $79.7 million and $79.0 million, respectively. Operating lease expense represents less than 1% of “Operating costs and $78.1expenses” as presented on our consolidated statements of operations.  Fixed lease expense is charged to earnings on a straight-line basis over the contractual term, with any variable lease payments expensed as incurred.  Short-term lease expense is expensed as incurred.

We recognized $246.1 million respectively.  in ROU assets and lease liabilities for long-term operating leases at January 1, 2019 in connection with the adoption of ASC 842.  These amounts represented less than 1% of our total consolidated assets and liabilities, respectively, at the adoption date. On an undiscounted basis, our long-term operating lease obligations aggregated to $314.4 million at January 1, 2019.

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

Our operating lease commitments at September 30, 20182019 did not differ materially from those reported in our 20172018 Form 10-K.


Purchase Obligations. 
During the first nine months of 2018,ended September 30, 2019, we entered into additional long-term product purchase commitments for crude oilNGLs with third party suppliers in order to meet future physical delivery obligations on our various systems.third-party suppliers.  On a combined basis, these new agreements increased our estimated long-term purchase obligations by approximately $1.2$3.6 billion, with $1.3 billion committed over the next five years and $1.8$2.3 billion overall.  Apart from these new agreements, there have been no other material changes inthereafter.  At September 30, 2019, our consolidatedestimated long-term purchase obligations sincetotaled $12.7 billion after reflecting the agreements added during the first nine months of 2019 and those reported in commitments that expired during the year.  At December 31, 2018, our 2017 Form 10-K. estimated long-term purchase obligations totaled $10.8 billion.


Liquidity Option Agreement

We entered into a put option agreement (the “Liquidity Option Agreement” or “Liquidity Option”) with Oiltanking Holding Americas, Inc. (“OTA”) and Marquard & Bahls AG (“M&B”), a German corporation and the ultimate parent company of OTA, (“M&B”), in connection with the first step of the Oiltanking acquisition in 2014 (“Step 1”).  Under the Liquidity Option Agreement, we granted M&B the option to sell to us 100% of the issued and outstanding capital stock of OTA at any time within a 90-day period commencing on February 1, 2020.  If the Liquidity Option is exercised during this period, we would indirectly acquire the EnterpriseEPD common units then owned by OTA, currently 54,807,352 units,  and assume all future income tax obligations of OTA associated with (i) owning common units encumbered by the entity-level taxes of a U.S. corporation and (ii) any associated net deferred taxes.  If we assume net deferred tax liabilities that exceed the then currentthen-current book value of the Liquidity Option liability at the exercise date, we will recognize expense for the difference.
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The carrying value of the Liquidity Option Agreement, which is a component of “Other long-term liabilities” on our Unaudited Condensed Consolidated Balance Sheet, was $368.8$513.1 million and $333.9$390.0 million at September 30, 20182019 and December 31, 2017,2018, respectively.  The fair value of the Liquidity Option, at any measurement date, represents the present value of estimated federal and state income tax payments that we believe a market participant would incur on the future taxable income of OTA. We expect that OTA’s taxable income would, in turn, be based on an allocation of our partnership’s taxable income to the common units then held by OTA and reflect anycertain tax planning strategies we believe could be employed.


Our valuation estimate for the Liquidity Option at September 30, 2018 is based on several inputs that are not observable in the market (i.e., Level 3 inputs) such as the following:

OTA remains in existence (i.e., is not dissolved and its assets sold) between one and 30 years following exercise of the Liquidity Option, depending on the liquidity preference of its owner. An equal probability that OTA would be dissolved was assigned to each year in the 30-year forecast period;

Forecasted annual growth rates of Enterprise’s taxable earnings before interest, taxes, depreciation and amortization ranging from 2.1% to 7.2%;

OTA’s ownership interest in Enterprise common units is assumed to be diluted over time in connection with Enterprise’s issuance of equity for general company reasons.  For purposes of the valuation at September 30, 2018, we used ownership interests ranging from 1.8% to 2.5%;

OTA pays an aggregate federal and state income tax rate of 24% on its taxable income; and

A discount rate of 7.9% based on our weighted-average cost of capital at September 30, 2018.

Furthermore, our valuation estimate incorporates probability-weighted scenarios reflecting the likelihood that M&B may elect to divest a portion of the Enterprise common units held by OTA prior to exercise of the option.  At September 30, 2018, based on these scenarios, we expect that OTA would own approximately 93% of the 54,807,352 Enterprise common units it received in Step 1 when the option period begins in February 2020.  If our valuation estimate assumed that OTA owned all of the Enterprise common units it received in Step 1 at the time of exercise (and all other inputs remained the same), the estimated fair value of the Liquidity Option liability at September 30, 2018 would have increased by $27.2 million.

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



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



Note 17.16.  Supplemental Cash Flow Information


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


 
For the Nine Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
 2018  2017  2019  2018 
Decrease (increase) in:            
Accounts receivable – trade $123.1  $(137.3) $(578.0) $123.1 
Accounts receivable – related parties  (0.3)  (2.2)  1.6   (0.3)
Inventories  (474.2)  (92.7)  (44.2)  (474.2)
Prepaid and other current assets  (124.7)  284.3   (305.3)  (124.7)
Other assets  (9.9)  (89.3)  (18.3)  (9.9)
Increase (decrease) in:                
Accounts payable – trade  213.1   3.5   (55.4)  213.1 
Accounts payable – related parties  47.4   37.7   31.0   47.4 
Accrued product payables  356.9   98.7   666.6   356.9 
Accrued interest  (167.5)  (134.3)  (158.4)  (167.5)
Other current liabilities  (261.7)  (481.5)  133.6   (261.7)
Other liabilities  35.9   1.0   (82.2)  35.9 
Net effect of changes in operating accounts $(261.9) $(512.1) $(409.0) $(261.9)


We incurred liabilities for construction in progress that had not been paid at September 30, 20182019 and December 31, 20172018 of $510.5$490.5 million and $373.0$567.6 million, respectively.  Such amounts are not included under the caption “Capital expenditures” on the Unaudited Condensed Statements of Consolidated Cash Flows.


Capital expendituresAcquisition of Delaware Processing

In March 2018, we acquired the remaining 50% member interest in our Delaware Basin Gas Processing LLC (“Delaware Processing”) joint venture for $150.6 million.  As a result, Delaware Processing became our wholly-owned consolidated subsidiary.  Upon acquisition of the nine months ended September 30, 2017 reflectremaining 50% member interest, our existing equity investment was remeasured to fair value resulting in the receiptrecognition of $36.2a non-cash $39.4 million of CIACs from third parties.gain during 2018.


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



Note 18.17.  Condensed Consolidating Financial Information


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


EPO has issued publicly traded debt securities.  As the parent company of EPO, Enterprise Products Partners L.P.EPD guarantees substantially all of the debt obligations of EPO.  If EPO were to default on any of its guaranteed debt, Enterprise Products Partners L.P.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 Enterprise Products Partners L.P.EPD.  



Enterprise Products Partners L.P.
Unaudited Condensed Consolidating Balance Sheet
September 30, 20182019


 EPO and Subsidiaries           EPO and Subsidiaries          
 
Subsidiary
Issuer
(EPO)
  
Other
Subsidiaries
(Non-
guarantor)
  
EPO and
Subsidiaries
Eliminations
and
Adjustments
  
Consolidated
EPO and
Subsidiaries
  
Enterprise
Products
Partners
L.P.
(Guarantor)
  
Eliminations
and
Adjustments
  
Consolidated
Total
  
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 $249.1  $92.5  $(62.5) $279.1  $--  $--  $279.1  $1,004.2  $235.7  $(32.1) $1,207.8  $–  $–  $1,207.8 
Accounts receivable – trade, net  1,644.3   2,579.9   (1.3)  4,222.9   --   --   4,222.9   1,223.0   3,039.4   (0.7)  4,261.7   –   –   4,261.7 
Accounts receivable – related parties  203.0   1,472.0   (1,672.0)  3.0   --   (1.4)  1.6   190.8   905.5   (1,086.2)  10.1   –   (8.1)  2.0 
Inventories  1,822.2   514.4   (0.8)  2,335.8   --   --   2,335.8   1,078.5   566.5   (0.3)  1,644.7   –   –   1,644.7 
Derivative assets  165.1   71.5   --   236.6   --   --   236.6   138.1   27.9   –   166.0   –   –   166.0 
Prepaid and other current assets  176.5   450.9   (17.7)  609.7   0.2   --   609.9   275.0   402.4   (46.2)  631.2   0.3   0.1   631.6 
Total current assets  4,260.2   5,181.2   (1,754.3)  7,687.1   0.2   (1.4)  7,685.9   3,909.6   5,177.4   (1,165.5)  7,921.5   0.3   (8.0)  7,913.8 
Property, plant and equipment, net  6,034.7   31,767.1   1.1   37,802.9   --   --   37,802.9   6,285.6   34,522.8   (45.1)  40,763.3   –   –   40,763.3 
Investments in unconsolidated affiliates  42,909.8   4,124.2   (44,430.6)  2,603.4   23,442.2   (23,442.2)  2,603.4   44,827.7   4,174.0   (46,340.8)  2,660.9   25,016.0   (25,016.0)  2,660.9 
Intangible assets, net  663.4   3,004.3   (13.5)  3,654.2   --   --   3,654.2   642.0   2,860.6   (13.2)  3,489.4   –   –   3,489.4 
Goodwill  459.5   5,285.7   --   5,745.2   --   --   5,745.2   459.5   5,285.7   –   5,745.2   –   –   5,745.2 
Other assets  292.2   189.7   (222.2)  259.7   0.9   --   260.6   373.5   290.7   (222.4)  441.8   0.9   –   442.7 
Total assets $54,619.8  $49,552.2  $(46,419.5) $57,752.5  $23,443.3  $(23,443.6) $57,752.2  $56,497.9  $52,311.2  $(47,787.0) $61,022.1  $25,017.2  $(25,024.0) $61,015.3 
                                                        
LIABILITIES AND EQUITY                                                        
Current liabilities:                                                        
Current maturities of debt $3,405.4  $0.1  $--  $3,405.5  $--  $--  $3,405.5  $2,300.0  $–  $–  $2,300.0  $–  $–  $2,300.0 
Accounts payable – trade  434.0   781.7   (62.5)  1,153.2   --   --   1,153.2   297.1   792.8   (32.1)  1,057.8   –   –   1,057.8 
Accounts payable – related parties  1,602.8   219.3   (1,685.9)  136.2   1.4   (1.4)  136.2   1,042.3   182.7   (1,099.5)  125.5   8.1   (8.1)  125.5 
Accrued product payables  2,646.8   2,505.5   (2.5)  5,149.8   --   --   5,149.8   1,490.3   2,709.6   (1.1)  4,198.8   –   –   4,198.8 
Accrued interest  190.4   3.2   (3.1)  190.5   --   --   190.5   237.1   3.2   (3.1)  237.2   –   –   237.2 
Derivative liabilities  286.0   201.1   --   487.1   --   --   487.1   194.3   8.1   –   202.4   –   –   202.4 
Other current liabilities  43.5   370.3   (14.0)  399.8   --   0.2   400.0   121.3   469.5   (43.0)  547.8   –   –   547.8 
Total current liabilities  8,608.9   4,081.2   (1,768.0)  10,922.1   1.4   (1.2)  10,922.3   5,682.4   4,165.9   (1,178.8)  8,669.5   8.1   (8.1)  8,669.5 
Long-term debt  22,493.9   14.6   --   22,508.5   --   --   22,508.5   25,624.5   14.7   –   25,639.2   –   –   25,639.2 
Deferred tax liabilities  11.1   56.0   (1.0)  66.1   --   2.3   68.4   21.0   68.9   (1.2)  88.7   –   2.7   91.4 
Other long-term liabilities  59.2   541.1   (221.9)  378.4   368.8   --   747.2   195.5   603.0   (221.9)  576.6   513.1   –   1,089.7 
Commitments and contingencies                                                        
Equity:                                                        
Partners’ and other owners’ equity  23,446.7   44,787.3   (44,815.9)  23,418.1   23,073.1   (23,418.1)  23,073.1   24,974.5   47,392.8   (47,381.8)  24,985.5   24,496.0   (24,985.5)  24,496.0 
Noncontrolling interests  --   72.0   387.3   459.3   --   (26.6)  432.7   –   65.9   996.7   1,062.6   –   (33.1)  1,029.5 
Total equity  23,446.7   44,859.3   (44,428.6)  23,877.4   23,073.1   (23,444.7)  23,505.8   24,974.5   47,458.7   (46,385.1)  26,048.1   24,496.0   (25,018.6)  25,525.5 
Total liabilities and equity $54,619.8  $49,552.2  $(46,419.5) $57,752.5  $23,443.3  $(23,443.6) $57,752.2  $56,497.9  $52,311.2  $(47,787.0) $61,022.1  $25,017.2  $(25,024.0) $61,015.3 


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

Enterprise Products Partners L.P.
Unaudited Condensed Consolidating Balance Sheet
December 31, 20172018


 EPO and Subsidiaries           EPO and Subsidiaries          
 
Subsidiary
Issuer
(EPO)
  
Other
Subsidiaries
(Non-
guarantor)
  
EPO and
Subsidiaries
Eliminations
and
Adjustments
  
Consolidated
EPO and
Subsidiaries
  
Enterprise
Products
Partners
L.P.
(Guarantor)
  
Eliminations
and
Adjustments
  
Consolidated
Total
  
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 $65.2  $31.5  $(26.4) $70.3  $--  $--  $70.3  $393.4  $50.3  $(33.6) $410.1  $–  $–  $410.1 
Accounts receivable – trade, net  1,382.3   2,976.6   (0.5)  4,358.4   --   --   4,358.4   1,303.1   2,356.8   (0.8)  3,659.1   –   –   3,659.1 
Accounts receivable – related parties  110.3   1,182.1   (1,289.3)  3.1   --   (1.3)  1.8   141.8   1,423.7   (1,530.1)  35.4   0.8   (32.7)  3.5 
Inventories  1,038.9   572.3   (1.4)  1,609.8   --   --   1,609.8   889.3   633.2   (0.4)  1,522.1   –   –   1,522.1 
Derivative assets  110.0   43.4   --   153.4   --   --   153.4   105.0   49.1   0.3   154.4   –   –   154.4 
Prepaid and other current assets  136.3   189.0   (12.6)  312.7   --   --   312.7   166.0   155.1   (10.2)  310.9   –   0.6   311.5 
Total current assets  2,843.0   4,994.9   (1,330.2)  6,507.7   --   (1.3)  6,506.4   2,998.6   4,668.2   (1,574.8)  6,092.0   0.8   (32.1)  6,060.7 
Property, plant and equipment, net  5,622.6   29,996.3   1.5   35,620.4   --   --   35,620.4   6,112.7   32,628.7   (3.8)  38,737.6   –   –   38,737.6 
Investments in unconsolidated affiliates  41,616.6   4,298.0   (43,255.2)  2,659.4   22,881.5   (22,881.5)  2,659.4   43,962.6   4,170.6   (45,518.1)  2,615.1   24,273.6   (24,273.6)  2,615.1 
Intangible assets, net  675.5   3,028.6   (13.8)  3,690.3   --   --   3,690.3   659.2   2,963.0   (13.8)  3,608.4   –   –   3,608.4 
Goodwill  459.5   5,285.7   --   5,745.2   --   --   5,745.2   459.5   5,285.7   –   5,745.2   –   –   5,745.2 
Other assets  296.4   110.0   (211.0)  195.4   1.0   --   196.4   292.1   131.9   (222.1)  201.9   0.9   –   202.8 
Total assets $51,513.6  $47,713.5  $(44,808.7) $54,418.4  $22,882.5  $(22,882.8) $54,418.1  $54,484.7  $49,848.1  $(47,332.6) $57,000.2  $24,275.3  $(24,305.7) $56,969.8 
                                                        
LIABILITIES AND EQUITY                                                        
Current liabilities:                                                        
Current maturities of debt $2,854.6  $0.4  $--  $2,855.0  $--  $--  $2,855.0  $1,500.0  $0.1  $–  $1,500.1  $–  $–  $1,500.1 
Accounts payable – trade  290.2   537.8   (26.4)  801.6   0.1   --   801.7   404.0   734.3   (35.5)  1,102.8   –   –   1,102.8 
Accounts payable – related parties  1,320.3   112.0   (1,305.0)  127.3   1.3   (1.3)  127.3   1,557.3   127.5   (1,543.9)  140.9   31.9   (32.6)  140.2 
Accrued product payables  1,825.9   2,741.7   (1.3)  4,566.3   --   --   4,566.3   1,574.7   1,902.3   (1.2)  3,475.8   –   –   3,475.8 
Accrued interest  358.0   --   --   358.0   --   --   358.0   395.5   0.9   (0.8)  395.6   –   –   395.6 
Derivative liabilities  115.2   53.0   --   168.2   --   --   168.2   86.2   61.7   0.3   148.2   –   –   148.2 
Other current liabilities  108.9   320.1   (10.8)  418.2   --   0.4   418.6   87.9   326.3   (9.4)  404.8   –   –   404.8 
Total current liabilities  6,873.1   3,765.0   (1,343.5)  9,294.6   1.4   (0.9)  9,295.1   5,605.6   3,153.1   (1,590.5)  7,168.2   31.9   (32.6)  7,167.5 
Long-term debt  21,699.0   14.7   --   21,713.7   --   --   21,713.7   24,663.4   14.7   –   24,678.1   –   –   24,678.1 
Deferred tax liabilities  6.7   50.2   (0.5)  56.4   --   2.1   58.5   17.0   62.0   (0.9)  78.1   –   2.3   80.4 
Other long-term liabilities  60.4   396.5   (212.4)  244.5   333.9   --   578.4   65.2   518.4   (221.9)  361.7   389.9   –   751.6 
Commitments and contingencies                                                        
Equity:                                                        
Partners’ and other owners’ equity  22,874.4   43,412.0   (43,433.3)  22,853.1   22,547.2   (22,853.1)  22,547.2   24,133.5   46,031.8   (45,917.9)  24,247.4   23,853.5   (24,247.4)  23,853.5 
Noncontrolling interests  --   75.1   181.0   256.1   --   (30.9)  225.2   –   68.1   398.6   466.7   –   (28.0)  438.7 
Total equity  22,874.4   43,487.1   (43,252.3)  23,109.2   22,547.2   (22,884.0)  22,772.4   24,133.5   46,099.9   (45,519.3)  24,714.1   23,853.5   (24,275.4)  24,292.2 
Total liabilities and equity $51,513.6  $47,713.5  $(44,808.7) $54,418.4  $22,882.5  $(22,882.8) $54,418.1  $54,484.7  $49,848.1  $(47,332.6) $57,000.2  $24,275.3  $(24,305.7) $56,969.8 


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


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


 EPO and Subsidiaries           EPO and Subsidiaries          
 
Subsidiary
Issuer
(EPO)
  
Other
Subsidiaries
(Non-
guarantor)
  
EPO and
Subsidiaries
Eliminations
and
Adjustments
  
Consolidated
EPO and
Subsidiaries
  
Enterprise
Products
Partners
L.P.
(Guarantor)
  
Eliminations
and
Adjustments
  
Consolidated
Total
  
Subsidiary
Issuer
(EPO)
  
Other
Subsidiaries
(Non-
guarantor)
  
EPO and
Subsidiaries
Eliminations
and
Adjustments
  
Consolidated
EPO and
Subsidiaries
  
EPD
(Guarantor)
  
Eliminations
and
Adjustments
  
Consolidated
Total
 
Revenues $11,395.5  $6,039.5  $(7,849.1) $9,585.9  $--  $--  $9,585.9  $11,395.5  $6,039.5  $(7,849.1) $9,585.9  $–  $–  $9,585.9 
Costs and expenses:                                                        
Operating costs and expenses  11,086.5   4,764.8   (7,849.4)  8,001.9   --   --   8,001.9   11,086.5   4,764.8   (7,849.4)  8,001.9   –   –   8,001.9 
General and administrative costs  8.0   43.6   0.8   52.4   0.3   --   52.7   8.0   43.6   0.8   52.4   0.3   –   52.7 
Total costs and expenses  11,094.5   4,808.4   (7,848.6)  8,054.3   0.3   --   8,054.6   11,094.5   4,808.4   (7,848.6)  8,054.3   0.3   –   8,054.6 
Equity in income of unconsolidated affiliates  1,313.4   146.8   (1,348.2)  112.0   1,332.0   (1,332.0)  112.0   1,313.4   146.8   (1,348.2)  112.0   1,332.0   (1,332.0)  112.0 
Operating income  1,614.4   1,377.9   (1,348.7)  1,643.6   1,331.7   (1,332.0)  1,643.3   1,614.4   1,377.9   (1,348.7)  1,643.6   1,331.7   (1,332.0)  1,643.3 
Other income (expense):                                                        
Interest expense  (279.8)  (2.5)  2.8   (279.5)  --   --   (279.5)  (279.8)  (2.5)  2.8   (279.5)  –   –   (279.5)
Other, net  2.6   0.5   (2.8)  0.3   (18.5)  --   (18.2)  2.6   0.5   (2.8)  0.3   (18.5)  –   (18.2)
Total other expense, net  (277.2)  (2.0)  --   (279.2)  (18.5)  --   (297.7)  (277.2)  (2.0)  –   (279.2)  (18.5)  –   (297.7)
Income before income taxes  1,337.2   1,375.9   (1,348.7)  1,364.4   1,313.2   (1,332.0)  1,345.6   1,337.2   1,375.9   (1,348.7)  1,364.4   1,313.2   (1,332.0)  1,345.6 
Provision for income taxes  (5.9)  (4.8)  --   (10.7)  --   (0.3)  (11.0)  (5.9)  (4.8)  –   (10.7)  –   (0.3)  (11.0)
Net income  1,331.3   1,371.1   (1,348.7)  1,353.7   1,313.2   (1,332.3)  1,334.6   1,331.3   1,371.1   (1,348.7)  1,353.7   1,313.2   (1,332.3)  1,334.6 
Net income attributable to noncontrolling interests  --   (2.4)  (20.5)  (22.9)  --   1.5   (21.4)  –   (2.4)  (20.5)  (22.9)  –   1.5   (21.4)
Net income attributable to entity $1,331.3  $1,368.7  $(1,369.2) $1,330.8  $1,313.2  $(1,330.8) $1,313.2  $1,331.3  $1,368.7  $(1,369.2) $1,330.8  $1,313.2  $(1,330.8) $1,313.2 


42

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


Enterprise Products Partners L.P.
Unaudited Condensed Consolidating Statement of Operations
For the ThreeNine Months Ended September 30, 20172019


 EPO and Subsidiaries           EPO and Subsidiaries          
 
Subsidiary
Issuer
(EPO)
  
Other
Subsidiaries
(Non-
guarantor)
  
EPO and
Subsidiaries
Eliminations
and
Adjustments
  
Consolidated
EPO and
Subsidiaries
  
Enterprise
Products
Partners
L.P.
(Guarantor)
  
Eliminations
and
Adjustments
  
Consolidated
Total
  
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 $8,199.3  $4,354.2  $(5,666.6) $6,886.9  $--  $--  $6,886.9  $25,664.8  $16,618.5  $(17,499.4) $24,783.9  $–  $–  $24,783.9 
Costs and expenses:                                                        
Operating costs and expenses  8,019.6   3,727.0   (5,666.8)  6,079.8   --   --   6,079.8   24,670.6   13,216.2   (17,492.5)  20,394.3   –   –   20,394.3 
General and administrative costs  8.0   32.9   0.1   41.0   0.3   --   41.3   22.6   133.4   2.3   158.3   1.9   –   160.2 
Total costs and expenses  8,027.6   3,759.9   (5,666.7)  6,120.8   0.3   --   6,121.1   24,693.2   13,349.6   (17,490.2)  20,552.6   1.9   –   20,554.5 
Equity in income of unconsolidated affiliates  692.5   141.4   (720.5)  113.4   620.1   (620.1)  113.4   3,606.9   496.8   (3,672.4)  431.3   3,619.4   (3,619.4)  431.3 
Operating income  864.2   735.7   (720.4)  879.5   619.8   (620.1)  879.2   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  (244.1)  (2.4)  2.6   (243.9)  --   --   (243.9)  (950.9)  (7.8)  8.5   (950.2)  –   –   (950.2)
Other, net  2.3   0.6   (2.6)  0.3   (8.9)  --   (8.6)  16.0   4.2   (8.5)  11.7   (123.1)  –   (111.4)
Total other expense, net  (241.8)  (1.8)  --   (243.6)  (8.9)  --   (252.5)  (934.9)  (3.6)  –   (938.5)  (123.1)  –   (1,061.6)
Income before income taxes  622.4   733.9   (720.4)  635.9   610.9   (620.1)  626.7   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  (3.2)  (1.8)  --   (5.0)  --   (0.4)  (5.4)  (18.2)  (18.3)  –   (36.5)  –   (0.9)  (37.4)
Net income  619.2   732.1   (720.4)  630.9   610.9   (620.5)  621.3   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  --   (1.5)  (10.1)  (11.6)  --   1.2   (10.4)  –   (4.9)  (66.5)  (71.4)  –   4.1   (67.3)
Net income attributable to entity $619.2  $730.6  $(730.5) $619.3  $610.9  $(619.3) $610.9  $3,625.4  $3,738.9  $(3,748.1) $3,616.2  $3,494.4  $(3,616.2) $3,494.4 

48
Table of Contents
ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


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


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




Enterprise Products Partners L.P.
Unaudited Condensed Consolidating Statement of Operations
For the Nine Months Ended September 30, 2017

  EPO and Subsidiaries          
  
Subsidiary
Issuer
(EPO)
  
Other
Subsidiaries
(Non-
guarantor)
  
EPO and
Subsidiaries
Eliminations
and
Adjustments
  
Consolidated
EPO and
Subsidiaries
  
Enterprise
Products
Partners
L.P.
(Guarantor)
  
Eliminations
and
Adjustments
  
Consolidated
Total
 
Revenues $29,273.1  $12,936.8  $(21,395.0) $20,814.9  $--  $--  $20,814.9 
Costs and expenses:                            
Operating costs and expenses  28,590.7   10,947.9   (21,395.4)  18,143.2   --   --   18,143.2 
General and administrative costs  23.5   112.5   (0.1)  135.9   1.5   --   137.4 
Total costs and expenses  28,614.2   11,060.4   (21,395.5)  18,279.1   1.5   --   18,280.6 
Equity in income of unconsolidated affiliates  2,137.4   417.1   (2,239.3)  315.2   2,059.8   (2,059.8)  315.2 
Operating income  2,796.3   2,293.5   (2,238.8)  2,851.0   2,058.3   (2,059.8)  2,849.5 
Other income (expense):                            
Interest expense  (736.7)  (9.4)  7.1   (739.0)  --   --   (739.0)
Other, net  6.8   1.2   (7.1)  0.9   (33.0)  --   (32.1)
Total other expense, net  (729.9)  (8.2)  --   (738.1)  (33.0)  --   (771.1)
Income before income taxes  2,066.4   2,285.3   (2,238.8)  2,112.9   2,025.3   (2,059.8)  2,078.4 
Provision for income taxes  (9.4)  (9.4)  --   (18.8)  --   (1.3)  (20.1)
Net income  2,057.0   2,275.9   (2,238.8)  2,094.1   2,025.3   (2,061.1)  2,058.3 
Net income attributable to noncontrolling interests  --   (4.8)  (32.0)  (36.8)  --   3.8   (33.0)
Net income attributable to entity $2,057.0  $2,271.1  $(2,270.8) $2,057.3  $2,025.3  $(2,057.3) $2,025.3 


43
49
Table of Contents
ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Enterprise Products Partners L.P.
Unaudited Condensed Consolidating Statement of Comprehensive Income
For the Three Months Ended September 30, 20182019


 EPO and Subsidiaries           EPO and Subsidiaries          
 
Subsidiary
Issuer
(EPO)
  
Other
Subsidiaries
(Non-
guarantor)
  
EPO and
Subsidiaries
Eliminations
and
Adjustments
  
Consolidated
EPO and
Subsidiaries
  
Enterprise
Products
Partners
L.P.
(Guarantor)
  
Eliminations
and
Adjustments
  
Consolidated
Total
  
Subsidiary
Issuer
(EPO)
  
Other
Subsidiaries
(Non-
guarantor)
  
EPO and
Subsidiaries
Eliminations
and
Adjustments
  
Consolidated
EPO and
Subsidiaries
  
EPD
(Guarantor)
  
Eliminations
and
Adjustments
  
Consolidated
Total
 
Comprehensive income $1,177.1  $1,340.7  $(1,348.2) $1,169.6  $1,129.1  $(1,148.2) $1,150.5  $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  --   (2.4)  (20.5)  (22.9)  --   1.5   (21.4)  –   (1.5)  (25.4)  (26.9)  –   1.3   (25.6)
Comprehensive income attributable to entity $1,177.1  $1,338.3  $(1,368.7) $1,146.7  $1,129.1  $(1,146.7) $1,129.1  $1,038.7  $1,175.3  $(1,185.2) $1,028.8  $990.8  $(1,028.8) $990.8 


Unaudited Condensed Consolidating Statement of Comprehensive Income
For the Three Months Ended September 30, 20172018


 EPO and Subsidiaries           EPO and Subsidiaries          
 
Subsidiary
Issuer
(EPO)
  
Other
Subsidiaries
(Non-
guarantor)
  
EPO and
Subsidiaries
Eliminations
and
Adjustments
  
Consolidated
EPO and
Subsidiaries
  
Enterprise
Products
Partners
L.P.
(Guarantor)
  
Eliminations
and
Adjustments
  
Consolidated
Total
  
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 $480.2  $693.3  $(720.4) $453.1  $433.0  $(442.7) $443.4  $1,177.1  $1,340.7  $(1,348.2) $1,169.6  $1,129.1  $(1,148.2) $1,150.5 
Comprehensive income attributable to noncontrolling interests  --   (1.5)  (10.1)  (11.6)  --   1.2   (10.4)  –   (2.4)  (20.5)  (22.9)  –   1.5   (21.4)
Comprehensive income attributable to entity $480.2  $691.8  $(730.5) $441.5  $433.0  $(441.5) $433.0  $1,177.1  $1,338.3  $(1,368.7) $1,146.7  $1,129.1  $(1,146.7) $1,129.1 

Unaudited Condensed Consolidating Statement of Comprehensive Income
For the Nine Months Ended September 30, 2019
 
  EPO and Subsidiaries          
  
Subsidiary
Issuer
(EPO)
  
Other
Subsidiaries
(Non-
guarantor)
  
EPO and
Subsidiaries
Eliminations
and
Adjustments
  
Consolidated
EPO and
Subsidiaries
  
EPD
(Guarantor)
  
Eliminations
and
Adjustments
  
Consolidated
Total
 
Comprehensive income $3,628.6  $3,650.6  $(3,681.6) $3,597.6  $3,404.4  $(3,530.3) $3,471.7 
Comprehensive income attributable to noncontrolling interests
  –   (4.9)  (66.5)  (71.4)  –   4.1   (67.3)
Comprehensive income attributable to entity $3,628.6  $3,645.7  $(3,748.1) $3,526.2  $3,404.4  $(3,526.2) $3,404.4 

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


 EPO and Subsidiaries           EPO and Subsidiaries          
 
Subsidiary
Issuer
(EPO)
  
Other
Subsidiaries
(Non-
guarantor)
  
EPO and
Subsidiaries
Eliminations
and
Adjustments
  
Consolidated
EPO and
Subsidiaries
  
Enterprise
Products
Partners
L.P.
(Guarantor)
  
Eliminations
and
Adjustments
  
Consolidated
Total
  
Subsidiary
Issuer
(EPO)
  
Other
Subsidiaries
(Non-
guarantor)
  
EPO and
Subsidiaries
Eliminations
and
Adjustments
  
Consolidated
EPO and
Subsidiaries
  
EPD
(Guarantor)
  
Eliminations
and
Adjustments
  
Consolidated
Total
 
Comprehensive income $2,791.2  $2,943.9  $(2,899.7) $2,835.4  $2,752.1  $(2,789.8) $2,797.7  $2,791.2  $2,943.9  $(2,899.7) $2,835.4  $2,752.1  $(2,789.8) $2,797.7 
Comprehensive income attributable to noncontrolling interests
  --   (6.1)  (43.6)  (49.7)  --   4.1   (45.6)
Comprehensive income attributable to noncontrolling interests  –   (6.1)  (43.6)  (49.7)  –   4.1   (45.6)
Comprehensive income attributable to entity $2,791.2  $2,937.8  $(2,943.3) $2,785.7  $2,752.1  $(2,785.7) $2,752.1  $2,791.2  $2,937.8  $(2,943.3) $2,785.7  $2,752.1  $(2,785.7) $2,752.1 


Unaudited Condensed Consolidating Statement of Comprehensive Income
For the Nine Months Ended September 30, 2017

  EPO and Subsidiaries          
  
Subsidiary
Issuer
(EPO)
  
Other
Subsidiaries
(Non-
guarantor)
  
EPO and
Subsidiaries
Eliminations
and
Adjustments
  
Consolidated
EPO and
Subsidiaries
  
Enterprise
Products
Partners
L.P.
(Guarantor)
  
Eliminations
and
Adjustments
  
Consolidated
Total
 
Comprehensive income $2,011.6  $2,294.8  $(2,238.8) $2,067.6  $1,998.7  $(2,034.6) $2,031.7 
Comprehensive income attributable to noncontrolling interests  --   (4.8)  (32.0)  (36.8)  --   3.8   (33.0)
Comprehensive income attributable to entity $2,011.6  $2,290.0  $(2,270.8) $2,030.8  $1,998.7  $(2,030.8) $1,998.7 

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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   –   –   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 on earnings from unconsolidated affiliates  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)  –   –   (3,302.1)
Cash used for business combination, net of cash received  –   –   –   –   –   –   – 
Proceeds from asset sales  0.9   15.9   –   16.8   –   –   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   –   –   44,629.6   –   –   44,629.6 
Repayments of debt  (42,855.2)  (0.1)  –   (42,855.3)  –   –   (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  –   –   –   –   (16.4)  –   (16.4)
Cash distributions paid to noncontrolling interests  –   (7.0)  (63.4)  (70.4)  –   0.7   (69.7)
Cash contributions from noncontrolling interests  –   –   590.8   590.8   –   –   590.8 
Net cash proceeds from issuance of common units  –   –   –   –   82.2   –   82.2 
Common units acquired in connection with buyback program  –   –   –   –   (81.1)  –   (81.1)
Cash contributions from owners  119.3   2,320.3   (2,320.3)  119.3   –   (119.3)  – 
Other financing activities  (26.3)  (5.6)  –   (31.9)  (32.8)  –   (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   –   –   797.7 
Cash and cash equivalents, including
   restricted cash, at beginning of period
  393.4   50.3   (33.6)  410.1   –   –   410.1 
Cash and cash equivalents, including
   restricted cash, at end of period
 $1,004.2  $235.7  $(32.1) $1,207.8  $–  $–  $1,207.8 

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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, 2018


 EPO and Subsidiaries           EPO and Subsidiaries          
 
Subsidiary
Issuer
(EPO)
  
Other
Subsidiaries
(Non-
guarantor)
  
EPO and
Subsidiaries
Eliminations
and
Adjustments
  
Consolidated
EPO and
Subsidiaries
  
Enterprise
Products
Partners
L.P.
(Guarantor)
  
Eliminations
and
Adjustments
  
Consolidated
Total
  
Subsidiary
Issuer
(EPO)
  
Other
Subsidiaries
(Non-
guarantor)
  
EPO and
Subsidiaries
Eliminations
and
Adjustments
  
Consolidated
EPO and
Subsidiaries
  
EPD
(Guarantor)
  
Eliminations
and
Adjustments
  
Consolidated
Total
 
Operating activities:                                          
Net income $2,921.1  $2,950.7  $(2,900.8) $2,971.0  $2,887.7  $(2,925.4) $2,933.3  $2,921.1  $2,950.7  $(2,900.8) $2,971.0  $2,887.7  $(2,925.4) $2,933.3 
Reconciliation of net income to net cash flows provided by operating activities:                                                        
Depreciation, amortization and accretion  237.0   1,123.8   (0.3)  1,360.5   --   --   1,360.5   207.3   1,123.8   (0.3)  1,330.8   –   –   1,330.8 
Equity in income of unconsolidated affiliates  (2,812.1)  (437.8)  2,899.9   (350.0)  (2,924.6)  2,924.6   (350.0)  (2,812.1)  (437.8)  2,899.9   (350.0)  (2,924.6)  2,924.6   (350.0)
Distributions received on earnings from unconsolidated affiliates  915.1   191.5   (760.9)  345.7   2,834.5   (2,834.5)  345.7   915.1   191.5   (760.9)  345.7   2,834.5   (2,834.5)  345.7 
Net effect of changes in operating accounts and other operating activities  2,295.4   (2,344.0)  (35.0)  (83.6)  69.4   --   (14.2)  2,325.1   (2,344.0)  (35.0)  (53.9)  69.4   –   15.5 
Net cash flows provided by operating activities  3,556.5   1,484.2   (797.1)  4,243.6   2,867.0   (2,835.3)  4,275.3   3,556.5   1,484.2   (797.1)  4,243.6   2,867.0   (2,835.3)  4,275.3 
Investing activities:                                                        
Capital expenditures  (605.8)  (2,343.2)  --   (2,949.0)  (55.2)  --   (3,004.2)  (605.8)  (2,343.2)  –   (2,949.0)  (55.2)  –   (3,004.2)
Cash used for business combination, net of cash received  --   (150.6)  --   (150.6)  --   --   (150.6)  –   (150.6)  –   (150.6)  –   –   (150.6)
Proceeds from asset sales  11.4   12.7   --   24.1   --   --   24.1   11.4   12.7   –   24.1   –   –   24.1 
Other investing activities  (1,701.1)  180.6   1,468.4   (52.1)  (438.1)  438.1   (52.1)  (1,701.1)  180.6   1,468.4   (52.1)  (438.1)  438.1   (52.1)
Cash used in investing activities  (2,295.5)  (2,300.5)  1,468.4   (3,127.6)  (493.3)  438.1   (3,182.8)  (2,295.5)  (2,300.5)  1,468.4   (3,127.6)  (493.3)  438.1   (3,182.8)
Financing activities:                                                        
Borrowings under debt agreements  67,086.3   11.5   (11.5)  67,086.3   --   --   67,086.3   67,086.3   11.5   (11.5)  67,086.3   –   –   67,086.3 
Repayments of debt  (65,741.7)  (0.4)  --   (65,742.1)  --   --   (65,742.1)  (65,741.7)  (0.4)  –   (65,742.1)  –   –   (65,742.1)
Cash distributions paid to owners  (2,834.5)  (1,003.6)  1,003.6   (2,834.5)  (2,782.9)  2,834.5   (2,782.9)  (2,834.5)  (1,003.6)  1,003.6   (2,834.5)  (2,782.9)  2,834.5   (2,782.9)
Cash payments made in connection with DERs  --   --   --   --   (13.2)  --   (13.2)  –   –   –   –   (13.2)  –   (13.2)
Cash distributions paid to noncontrolling interests  --   (6.8)  (44.9)  (51.7)  --   0.8   (50.9)  –   (6.8)  (44.9)  (51.7)  –   0.8   (50.9)
Cash contributions from noncontrolling interests  --   --   222.0   222.0   --   --   222.0   –   –   222.0   222.0   –   –   222.0 
Net cash proceeds from issuance of common units  --   --   --   --   449.4   --   449.4   –   –   –   –   449.4   –   449.4 
Cash contributions from owners  438.1   1,876.6   (1,876.6)  438.1   --   (438.1)  --   438.1   1,876.6   (1,876.6)  438.1   –   (438.1)  – 
Other financing activities  (25.3)  --   --   (25.3)  (27.0)  --   (52.3)  (25.3)  –   –   (25.3)  (27.0)  –   (52.3)
Cash provided by (used in) financing activities  (1,077.1)  877.3   (707.4)  (907.2)  (2,373.7)  2,397.2   (883.7)  (1,077.1)  877.3   (707.4)  (907.2)  (2,373.7)  2,397.2   (883.7)
Net change in cash and cash equivalents,
including restricted cash
  183.9   61.0   (36.1)  208.8   --   --   208.8   183.9   61.0   (36.1)  208.8   –   –   208.8 
Cash and cash equivalents, including
restricted cash, at beginning of period
  65.2   31.5   (26.4)  70.3   --   --   70.3   65.2   31.5   (26.4)  70.3   –   –   70.3 
Cash and cash equivalents, including
restricted cash, at end of period
 $249.1  $92.5  $(62.5) $279.1  $--  $--  $279.1  $249.1  $92.5  $(62.5) $279.1  $–  $–  $279.1 




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


ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
Enterprise Products Partners L.P.RESULTS OF OPERATIONS.
Unaudited Condensed Consolidating Statement of Cash Flows
For the Nine Months Ended September 30, 2017

  EPO and Subsidiaries          
  
Subsidiary
Issuer
(EPO)
  
Other
Subsidiaries
(Non-
guarantor)
  
EPO and
Subsidiaries
Eliminations
and
Adjustments
  
Consolidated
EPO and
Subsidiaries
  
Enterprise
Products
Partners
L.P.
(Guarantor)
  
Eliminations
and
Adjustments
  
Consolidated
Total
 
Operating activities:                     
Net income $2,057.0  $2,275.9  $(2,238.8) $2,094.1  $2,025.3  $(2,061.1) $2,058.3 
Reconciliation of net income to net cash flows provided by operating activities:                            
Depreciation, amortization and accretion  158.9   1,062.8   (0.3)  1,221.4   --   --   1,221.4 
Equity in income of unconsolidated affiliates  (2,137.4)  (417.1)  2,239.3   (315.2)  (2,059.8)  2,059.8   (315.2)
Distributions received on earnings from unconsolidated affiliates  802.6   202.2   (688.6)  316.2   2,664.2   (2,664.2)  316.2 
Net effect of changes in operating accounts and other operating activities  1,662.3   (2,157.4)  (27.5)  (522.6)  61.2   0.6   (460.8)
Net cash flows provided by operating activities  2,543.4   966.4   (715.9)  2,793.9   2,690.9   (2,664.9)  2,819.9 
Investing activities:                            
Capital expenditures  (625.8)  (1,492.4)  --   (2,118.2)  --   --   (2,118.2)
Cash used for business combination, net of cash received  (7.3)  (191.4)  --   (198.7)  --   --   (198.7)
Proceeds from asset sales  1.6   4.6   --   6.2   --   --   6.2 
Other investing activities  (1,447.2)  (33.5)  1,487.5   6.8   (867.5)  867.5   6.8 
Cash used in investing activities  (2,078.7)  (1,712.7)  1,487.5   (2,303.9)  (867.5)  867.5   (2,303.9)
Financing activities:                            
Borrowings under debt agreements  53,184.4   --   (34.0)  53,150.4   --   --   53,150.4 
Repayments of debt  (52,133.1)  (0.1)  --   (52,133.2)  --   --   (52,133.2)
Cash distributions paid to owners  (2,664.2)  (734.0)  734.0   (2,664.2)  (2,660.4)  2,664.2   (2,660.4)
Cash payments made in connection with DERs  --   --   --   --   (11.2)  --   (11.2)
Cash distributions paid to noncontrolling interests  --   (7.2)  (28.9)  (36.1)  --   0.7   (35.4)
Cash contributions from noncontrolling interests  --   0.1   0.3   0.4   --   --   0.4 
Net cash proceeds from issuance of common units  --   --   --   --   877.2   --   877.2 
Cash contributions from owners  867.5   1,470.2   (1,470.2)  867.5   --   (867.5)  -- 
Other financing activities  7.3   --   --   7.3   (29.0)  --   (21.7)
Cash provided by (used in) financing activities  (738.1)  729.0   (798.8)  (807.9)  (1,823.4)  1,797.4   (833.9)
Net change in cash and cash equivalents,
   including restricted cash
  (273.4)  (17.3)  (27.2)  (317.9)  --   --   (317.9)
Cash and cash equivalents, including
   restricted cash, at beginning of period
  366.2   58.9   (7.5)  417.6   --   --   417.6 
Cash and cash equivalents, including
   restricted cash, at end of period
 $92.8  $41.6  $(34.7) $99.7  $--  $--  $99.7 


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

Note 19.  Subsequent Events

Issuance of $3.0 Billion of Senior Notes in October 2018
In October 2018, EPO issued $3.0 billion aggregate principal amount of senior notes comprised of (i) $750 million principal amount of senior notes due February 2022 (“Senior Notes VV”), (ii) $1.00 billion principal amount of senior notes due October 2028 (“Senior Notes WW”) and (iii) $1.25 billion principal amount of senior notes due February 2049 (“Senior Notes XX”).  Net proceeds from this offering were used by EPO for the temporary repayment of amounts outstanding under its commercial paper program and for general company purposes, including for growth capital expenditures.

Senior Notes VV were issued at 99.985% of their principal amount and have a fixed-rate interest rate of 3.50% per year.  Senior Notes WW were issued at 99.764% of their principal amount and have a fixed-rate interest rate of 4.15% per year.  Senior Notes XX were issued at 99.390% of their principal amount and have a fixed-rate interest rate of 4.80% per year.  Enterprise Products Partners L.P. has guaranteed the senior notes through an unconditional guarantee on an unsecured and unsubordinated basis.

Sale of Red River System in October 2018
On October 1, 2018, we closed on the sale of our Red River System and associated crude oil linefill for approximately $135 million, of which $10.5 million was received as a deposit in the third quarter of 2018.   The Red River System gathers and transports crude oil from North Texas and southern Oklahoma for delivery to local refineries and pipeline interconnects for further transportation to the Cushing hub and Gulf Coast.   As of September 30, 2018, the carrying value of these assets totaled $109.6 million, which was classified as held-for-sale primarily within other current assets on our Unaudited Consolidated Balance Sheet.


53
Item 2.                 Management’s Discussion and Analysis of Financial Condition and Results of Operations.


For the Three and Nine Months Ended September 30, 20182019 and 20172018


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, 20172018 (the “2017“2018 Form 10-K”), as filed on February 28, 2018March 1, 2019 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,”“our” or “Enterprise” or “Enterprise Products Partners” are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries.  References to “EPD” mean Enterprise Products Partners L.P. on a standalone basis.  References to “EPO” mean Enterprise Products Operating LLC, which is aan indirect wholly owned subsidiary of Enterprise,EPD, and its consolidated subsidiaries, through which Enterprise Products Partners L.P.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.Cunningham, who is also an advisory director of Enterprise GP.  Ms. Duncan Williams and Mr. Bachmann also currently serve as managers of Dan Duncan LLC along with W. Randall Fowler, who is also a director and the President and Chief Financial Officer of Enterprise GP.


References to “EPCO” mean Enterprise Products Company, a privately held Texas corporation, and its privately held affiliates.  A majority of the outstanding voting capital stock of EPCO is owned by a voting trust, the current trustees (“EPCO Trustees”) of which are:  (i) Ms. Duncan Williams, who serves as Chairman of EPCO; (ii) Dr. Cunningham, who serves as Vice Chairman of EPCO; and (iii) Mr. Bachmann, who serves as the President and Chief Executive Officer of EPCO.  Ms. Duncan Williams and Mr. Bachmann also currently serve as directors of EPCO along with Mr. Fowler, who is also the Executive Vice President and Chief AdministrativeFinancial Officer of EPCO. EPCO, together with its privately held affiliates, owned approximately 32%31.9% of ourEPD’s limited partner interestscommon units at September 30, 2018.2019.


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 20182019 compared to the third quarter of 2017.2018.  Likewise, the phrase “period-to-period” means the nine months ended September 30, 20182019 compared to the nine months ended September 30, 2017.2018.
47
54


Cautionary Statement Regarding Forward-Looking InformationCAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION


This quarterly report on Form 10-Q contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us.  When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “seek,” “goal,” “estimate,” “forecast,” “intend,” “could,” “should,” “would,” “will,” “believe,” “may,” “potential” and similar expressions and statements regarding our plans and objectives for future operations are intended to identify forward-looking statements.  Although we and our general partner believe that our expectations reflected in such forward-looking statements are reasonable, neither we nor our general partner can give any assurances that such expectations will prove to be correct.  Forward-looking statements are subject to a variety of risks, uncertainties and assumptions as described in more detail under Part I, Item 1A of our 20172018 Form 10-K and within Part II, Item 1A of this quarterly report.  If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected.  You should not put undue reliance on any forward-looking statements.  The forward-looking statements in this quarterly report speak only as of the date hereof.  Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason.


Overview of Business


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


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


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


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


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


Significant Recent Commercial Developments


Enterprise Increasing NGL Fractionation Capacity in Texas and Louisianato Expand Appalachia-to-Texas (“ATEX”) Pipeline
The demand for NGL fractionation capacity continues to expand as producers in domestic shale plays like the Permian Basin, the Eagle Ford and Denver-Julesburg (“DJ”) Basin seek market access and end users require supply assurance.


In lightOctober 2019, we announced an expansion of this ongoing trend, we will constructour ATEX ethane pipeline based on customer commitments received during a new NGL fractionation facility located adjacentrecent 30-day binding open season. The 1,192-mile ATEX pipeline transports ethane from the Marcellus/Utica Basin of Pennsylvania, West Virginia and Ohio to our existing NGL fractionationstorage complex atin Mont Belvieu, Texas.   The current capacity of ATEX is approximately 145 MBPD, which would be expanded to 190 MBPD in connection with this expansion project. The incremental capacity is expected to be achieved through improvements and modifications to existing infrastructure.  We anticipate that this expansion project will be completed in 2022.

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

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

When placed into service, the Midland-to-ECHO 4 pipeline will consistallow our shippers with crude oil and condensate production in both the Permian Basin and the Eagle Ford shale to maximize the value of two fractionation trains capabletheir contracted pipeline capacity by allowing shippers to source barrels from the Permian Basin and/or the Eagle Ford shale.  This unmatched flexibility will allow shippers and producers to dynamically match their pipeline capacity to their allocation of processing 300 MBPD of NGLs.  The first ofcapital and respective production profiles between the two fractionation trainsbasins.  Their production will have a nameplate capacity of 150 MBPDbe delivered into our integrated storage, pipeline, distribution and is scheduledmarine terminal system that has access to be completedboth domestic and begin service in the first quarter of 2020. international markets.

The second of these fractionation trains will also have a nameplate capacity of 150 MBPDMidland-to-ECHO 4 pipeline complements our Midland-to-ECHO 1 and is scheduled to be completed and begin2 pipelines, which entered service in the second quarter of 2020.2018 and first quarter of 2019, respectively, as well as an expansion project we announced in July 2019 (which we refer to as the “Midland-to-ECHO 3” project).  The Midland-to-ECHO 3 and Midland-to-ECHO 4 projects are expected to begin service during the third quarter of 2020 and first half of 2021, respectively.  Similar to the Midland-to-ECHO 4 project, the Midland-to-ECHO 3 pipeline is expected to add an incremental 450 MBPD of transportation capacity.  Together, these four projects (Midland-to-ECHO 1, 2, 3 and 4) comprise our Midland-to-ECHO crude oil pipeline network, which supports crude oil production growth from the Permian Basin (and Eagle Ford shale, as applicable) by providing producers and other shippers with transportation solutions that are both cost-efficient and operationally flexible.  The Midland-to-ECHO network is expected to include 6 MMBbls of storage at our Midland terminal and access to more than 45 MMBbls of storage and approximately 4 MMBPD of export capacity at partnership assets along the Texas Gulf Coast.  The network connects to every refinery in the Houston, Texas City and Beaumont/Port Arthur area, representing approximately 4.5 MMBPD of refining capacity.


In January 2019, we converted the Midland-to-Sealy segment of one of our two Seminole NGL pipelines from NGL service to crude oil service, thus creating the major segment of the Midland-to-ECHO 2 pipeline.  In April 2019, our Midland-to-ECHO 2 pipeline, which provides us with approximately 200 MBPD of incremental crude oil transportation capacity, was placed into full service after being in limited service since February 2019.  Following the in-service date of the Midland-to-ECHO 4 pipeline, we plan to convert the Midland-to-Sealy segment of the Midland-to-ECHO 2 pipeline back to NGL service (as part of our Seminole NGL Pipeline) based upon our expectation that NGL production from the Permian Basin will increase by over 50 percent by 2025.  The reconversion project is expected to take less than sixty days and be completed during the second half of 2021. We will retain the flexibility to convert the Midland-to-Sealy segment back into crude oil service should market conditions support the need for additional crude oil transportation capacity in the future.

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Enterprise to Build Second Propane Dehydrogenation (“PDH”) Plant

In November 2018,September 2019, we announced the execution of long-term contracts with affiliates of LyondellBasell Industries N.V. (“LyondellBasell”) that support construction of our second propane dehydrogenation plant (referred to as “PDH 2”).  The new plant is expected to have the capacity to consume up to 35 MBPD of propane and produce up to 1.65 billion pounds per year of polymer grade propylene (“PGP”).  PDH 2 will be located at our complex in the Mont Belvieu, Texas area.  PDH 2 is scheduled to begin service in the first half of 2023.

The anchor contracts with LyondellBasell provide for us to process LyondellBasell-provided propane into PGP for a seriesfixed fee.  This fee-based model leverages our integrated value chain by providing sourcing and storage from our NGL storage facilities in Mont Belvieu, and delivers PGP into our storage hub and network of projects designedPGP pipeline infrastructure.  Our network of PGP assets includes more than 300 miles of delivery pipelines, 5 MMBbls of storage capacity, and an export facility at our Enterprise Hydrocarbons Terminal (“EHT”) located on the Houston Ship Channel.  We are currently expanding our PGP refrigeration facilities at EHT, which will enable us to provide us with an additional 55load more than 5,000 barrels per hour of PGP, as well as co-load PGP and LPG on very large gas carriers.

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

Enterprise to Expand and Extend Acadian Gas System

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

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

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

Enterprise Announces Final Investment Decision Regarding Sea Port Oil Terminal

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

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The SPOT project consists of onshore and offshore facilities, including a fixed platform located in Nuecesapproximately 30 nautical miles off the Brazoria County, Texas by expanding and repurposing a portioncoast in approximately 115 feet of our South Texas pipelines.  This project would entail the constructionwater.  SPOT is designed to load Very Large Crude Carriers (“VLCCs”) at rates of approximately 21 miles of new pipeline along85,000 barrels per hour. We believe that SPOT’s design meets or exceeds federal requirements for such facilities and, unlike existing and other proposed offshore terminals, is designed with the conversion of approximately 65 miles of existing natural gas pipelinea vapor control system to NGL service, which will allow us to supply Shoupminimize emissions.  SPOT would provide customers with an integrated export solution that leverages our extensive supply, storage and distribution network along the Gulf Coast, with access to approximately 6 MMBbls of crude oil supply and more than 300 MMBbls of storage.

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

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

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

Shin Oak is a 658-mile pipeline that transports NGLs from the Permian Basin to our Mont Belvieu NGL fractionation and storage complex.  In February 2019, the 24-inch diameter mainline segment of Shin Oak from Orla, Texas to Mont Belvieu was placed into limited commercial service with an initial transportation capacity of 250 MBPD.  In June 2019, an additional 25 MBPDpipeline segment, the 20-inch diameter Waha lateral, was placed into service. Shin Oak’s transportation capacity by the end of NGL volumes.  The expanded pipeline capacity is expected to be available in the third quarter of 2019.2019 was 350 MBPD. When fully complete in the fourth quarter of 2019, Shin Oak is expected to have up to 550 MBPD of transportation capacity.

Enterprise Begins Service at Orla III; Update on Mentone Plant

In Louisiana,July 2019, we plan to restartannounced that the third processing train (“Orla III”) at our Tebone NGL fractionator located in Ascension Parish. Tebone has a fractionation capacity of 30 MBPD and is connected by pipeline to each of our LouisianaOrla cryogenic natural gas processing plants, as well asplant had commenced operations. Completion of Orla III increased our natural gas processing capacity at Orla to 900 MMcf/d and our equity NGL fractionationproduction rate in excess of 140 MBPD.  Overall, we now have the capability to process up to 1.3 Bcf/d of natural gas and storage hub in Mont Belvieu.  The resumptionproduce approximately 200 MBPD of service at Tebone, which is expectedNGLs in the first quarter of 2019, will complement our Norco and Promix NGL fractionators and provide another option for NGLs delivered to Mont Belvieu.Delaware Basin.

The construction of our new 300 MBPD NGL fractionation facility at Mont Belvieu, the optimization of our Shoup facility and restart of our Tebone fractionator highlights the flexibility of our integrated midstream network and provides a timely, efficient and cost-effective solution for accommodating growing production from domestic shale basins.  Once these projects are complete and service begins, our NGL fractionation capacity would increase to an aggregate 1 MMBPD in the Mont Belvieu area, and approximately 1.5 MMBPD company-wide.

Enterprise Begins Construction of Seventh Natural Gas Processing Plant in Delaware Basin;
   Second Train at Orla Natural Gas Processing Plant Begins Service
In October 2018, we announced that construction of our Mentone cryogenic natural gas processing plant had commenced.  The Mentone plant, which is located in Loving County, Texas, is expected to have the capacity to process 300 MMcf/d of natural gas and extract in excess ofmore than 40 MBPD of NGLs.  The project is scheduled to be completedon schedule for completion in the first quarter of 2020 and is supported by a long-term acreage dedication agreement.  The Mentone plant further extends our presence in the growing Delaware Basin and provides access to our fully integrated midstream asset network serving domestic and international markets. To support the development of Mentone,In addition, we are constructing approximately 70 miles of gathering and residue pipelines and expanding compression capabilities.  These projects will allowactively negotiating contracts with producers to underwrite additional capacity at Mentone. When the Mentone plant to link to our NGL system, including the Shin Oak pipeline scheduled for completion in the second quarter of 2019, as well as our Texas Intrastate natural gas pipeline network.  We will ownis completed and operate the Mentone facility and related infrastructure.

The Mentone plant will complement our existing cryogenic natural gas processing plant located near Orla, Texas in Reeves County.   In May 2018 and October 2018, we commenced operations of the first and second processing trains (Orla I and Orla II), respectively, at the facility.  A third processing train (Orla III) is scheduled to be completed in the third quarter of 2019.  We own and operate the Orla facility.  In conjunction with the start-up of Orla I, we placed into service, approximately 70 miles of natural gas pipelines that connect the Orla facilitywe expect to our Texas Intrastate System.   We also placed into service a 30-mile extension of our NGL system that provides producers at the Orla facility with NGL takeaway capacity and direct access to our integrated network of downstream NGL assets.

When fully completed, the Orla and Mentone plants will provide us withhave an aggregate 1.31.6 Bcf/d of natural gas processing capacity and 195approximately 250 MBPD of NGL production from our processing plants in the Delaware Basin.


CME Group Launches Physical West Texas Intermediate (“WTI”) Houston Crude Oil Futures ContractExpansion Projects at EHT
In September 2018, the CME Group, a leading derivatives marketplace, announced
We estimate that suppliers, refiners and end usersexports of U.S. crude oil have awill increase from 3 MMBPD to 8 MMBPD and that LPG exports will double from 1.4 MMBPD to 2.8 MMBPD by 2025. Much of this growth is being driven by increasing production from the Permian Basin.  In response to these trends, we announced in July 2019 three new way to price and hedge WTI light sweet crude oil (“WTI Light”) in Houston, Texas.  Participants will haveexpansion projects at EHT, located on the flexibility to make or take delivery of WTI Light at our ECHO terminal, Enterprise Hydrocarbons Terminal (“EHT”) or pipeline interconnect at Genoa Junction. The new futures contracts received regulatory approval in October 2018 and are listed with and subject to the rules of the New York Mercantile Exchange (“NYMEX”), beginning with the January 2019 contract month.

Enterprise Expanding LPG Capacity at Houston Ship Channel, Terminalthat will increase our capacity to load LPG, PGP and crude oil at the terminal.
In September 2018, we announced a project
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We are adding an eighth deep-water ship dock at EHT that is expected to increase our crude oil loading capacity by 840 MBPD, thereby increasing our overall nameplate crude oil loading capacity at EHT to 2.75 MMBPD, or nearly 83 MMBbls per month.  The new dock is designed to accommodate a Suezmax vessel, which is the largest ship class that can navigate the Houston Ship Channel, and is scheduled to be placed into service during the fourth quarter of 2020.

Our current nameplate loading capacity for LPG at EHT is approximately 835 MBPD, with 175 MBPD of this loading capacity placed into service during the third quarter of 2019. The expansion project announced in July 2019 is expected to increase our LPG loading capacity at EHT by 175an additional 260 MBPD or approximately 5 MMBbls per month.  The expansion will bring our total LPG export capacity at EHT to 720 MBPD, or approximately 21 MMBbls per month. Upon completion of this expansion project, EHT will have the capability to load up to six Very Large Gas Carrier (“VLGC”) vessels simultaneously, while maintaining the option to switch between loading propane and butane. Once operational, the expansion will allow EHT to load a single VLGC in less than 24 hours, creating greater efficiencies and cost savings for our customers. The incremental loading capacity is expected to be available in the third quarter of 2019.

Enterprise to Develop Offshore Texas Crude Oil Export Terminal
In July 2018, management announced that we are in the planning stage to develop a crude oil export terminal located offshore along the Texas Gulf Coast.  The terminal would be capable of fully loading Very Large Crude Carrier (“VLCC”) marine tankers, which have capacities of approximately 2 MMBbls and provide the most efficient and cost-effective solution to export crude oil to the largest international markets in Asia and Europe.   We have started front-end engineering and design work for the terminal and preparing applications for regulatory permitting.   Based on initial designs, the project could include approximately 80 miles of 42-inch diameter pipeline extending from onshore facilities to an offshore terminal loading crude oil for export at approximately 85 thousand barrels per hour.   A final investment decision for the project will be subject to receiving state and federal permits and customer demand.

Seaway Commences Loading Services for VLCC Tankers
In June 2018, we commenced the loading of VLCC tankers using a combination of our jointly owned Seaway marine terminal located in Texas City, Texas and lightering operations in the Gulf of Mexico.  Approximately 1.1 MMBbls of crude oil were loaded onto the FPMC C Melody at the Texas City marine terminal and the remainder of the crude oil shipment was loaded on the VLCC in a lightering zone in the Gulf of Mexico.  The FPMC C Melody, chartered by Vitol, Inc., was the first VLCC to be loaded at a Texas port.  The Seaway marine terminal features two docks, a 45-foot draft, an overall length of 1,125 feet, a 220-foot beam (width) and the capacity to load crude oil at a rate of 35 thousand barrels per hour.

In July 2018, we completed a second partial loading of a VLCC tanker at the Seaway terminal. The Eagle Victoria loaded approximately 1.1 MMBbls at the terminal, with the balance completed using lightering vessels in the Gulf of Mexico.  Additional VLCC tankers are expected to be loadedplaced into service during the fourth quarter of 2018.2020.  When this latest expansion project is completed, EHT will have a nameplate LPG loading capacity of approximately 1.1 MMBPD, or 33 MMBbls per month.


Affiliate of Western Gas Acquires 20% Ownership Interest in Midland-to-ECHO Pipeline
In June 2018, pursuant to an option agreement, an affiliate of Western Gas Partners, LP (“Western”) acquired a noncontrolling 20% equity interest in our subsidiary, Whitethorn Pipeline Company LLC (“Whitethorn”),Our current loading capacity at EHT for PGP is approximately $189.6 million in cash.  Whitethorn owns the Midland-to-ECHO Pipeline, which originates at our Midland, Texas terminal and extends 416 miles to our Sealy, Texas facility. Volumes arriving at Sealy are then transported to our ECHO terminal using our Rancho II pipeline, which is a component of our South Texas Crude Oil Pipeline System. Once all infrastructure is complete, the Midland-to-ECHO Pipeline will provide Permian Basin producers with the ability to transport multiple grades of crude oil, including WTI, Light WTI, West Texas Sour and condensate, to Gulf Coast markets. As a result of infrastructure completed in the second quarter of 2018 as well as operating enhancements, the pipeline’s transportation capacity is now approximately 575 MBPD.  We report the pipeline’s transportation volumes on a net basis that reflects our 80% interest.

Upon closing of the transaction whereby Western acquired its 20% equity interest in Whitethorn, we credited Western for 20% of the pipeline’s earnings since it was placed into service in November 2017.  We paid Western $45.7 million in June 2018 to settle this obligation.

Apache Dedicates Alpine High NGLs to Enterprise
In May 2018, Apache Corporation (“Apache”) executed a long-term supply agreement with us whereby Apache would sell all of its NGL production from the Alpine High discovery to us.  Alpine High is a major hydrocarbon resource located in the Delaware Basin that encompasses rich natural gas (i.e., gas that has a high NGL content), dry natural gas and oil-bearing horizons.  Apache holds approximately 336,000 net acres in the Alpine High discovery.  Enterprise has committed to purchase up to 2052,500 barrels per hour, or 60 MBPD, of NGLs from Apache oversemi-refrigerated product.  In response to record international demand for PGP, we will expand our export capabilities at EHT to accommodate an incremental 2,800 barrels per hour, or approximately 67 MBPD, of semi- or fully-refrigerated PGP.  With the initial ten year termaddition of fully refrigerated volumes, this expansion project will enable EHT to co-load fully refrigerated PGP and LPG volumes onto the supply agreement, the term of which may be extended at the consent of the parties.

In conjunction with the long-term NGL supply agreement, we granted Apache an option to acquire up to a 33% equity interest in our subsidiary that owns the Shin Oak NGL Pipeline, whichsame vessel.  Our PGP export expansion project is currently under construction and expected to be placed into service during the secondfourth quarter of 2019.  The option is exercisable once the pipeline is placed into commercial service. The Shin Oak NGL2020.

Enterprise to Extend Ethylene Pipeline is designed to transport growing NGL production from the Permian Basin, which includes the Alpine High discovery, to our NGL fractionation and storage complex located in Mont Belvieu, Texas.  The Shin Oak NGL Pipeline is expected to have an initial design capacity of 550 MBPD.  In August 2018, Apache announced its intent to contribute the Shin Oak option to Altus Midstream Company, which would be majority-owned by Apache.Network

Construction Begins on Ethylene Export Dock
In May 2018,2019, we announced plans to expand our ethylene pipeline and logistics system by constructing the Baymark ethylene pipeline in South Texas, which is a leading growth area for new ethylene crackers and related facilities.  The Baymark pipeline will originate in the Bayport, Texas area of southeast Harris County and extend approximately 90 miles to Markham, Texas in Matagorda County.  The pipeline is supported by long-term customer commitments and is scheduled to begin service in the fourth quarter of 2020.  We will be the majority owner and operator of the new pipeline.

The Baymark pipeline will feature access to a high-capacity ethylene storage well that construction ofis under development at our Mont Belvieu complex, along with connectivity to our ethylene export terminal locatedcurrently under construction at Morgan’s Point onPoint. The storage well is expected to be completed in the Houston Ship Channel had commenced.  Thefourth quarter of 2019 and have a capacity of 600 million pounds of ethylene. Our ethylene export terminal at Morgan’s Point will have the capacity to export approximately 2.2 billion pounds of ethylene per year. Refrigerated storage for 66 million pounds of ethylene is being constructed on-siteyear and will provide the capability to load ethylene at rates of 2.2 million pounds per hour. The project, which is underwritten by long-term contracts with customers, is expected to be completedbegin service in the fourth quarter of 2019.


Enterprise and Energy Transfer form Joint Venture to Restore Service on Old Ocean PipelineAnnounces $2 Billion Unit Buyback Program

In May 2018,January 2019, we announced that the formationBoard of Enterprise GP had approved a 50/50 joint venture$2.0 billion multi-year unit buyback program (the “2019 Buyback Program”), which provides EPD with Energy Transfer Partners, L.P. (“Energy Transfer” or “ETP”)an additional method to resume full servicereturn capital to investors. The 2019 Buyback Program authorizes EPD to repurchase its common units from time to time, including through open market purchases and negotiated transactions.  The timing and pace of buy backs under the program will be determined by a number of factors including (i) our financial performance and flexibility, (ii) organic growth and acquisition opportunities with higher potential returns on the Old Ocean natural gas pipeline owned by ETP.  The 24-inch diameter Old Ocean Pipeline originates in Maypearl, Texas in Ellis Countyinvestment, (iii) EPD’s unit price and extends southimplied 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 240 miles to Sweeny, Texas in Brazoria County.  ETP serves as operator3.5 times.  No time limit has been set for completion of the pipeline.program, and it may be suspended or discontinued at any time.


The Old Ocean Pipeline resumed limited service in
EPD repurchased 2,909,128 common units under the second quarter of 2018.  If fully reconstituted,2019 Buyback Program through open market purchases during the Old Ocean Pipeline is expected to provide natural gas transportation capacity of up to 160 MMcf/d by the end of 2018. In addition, both parties are expanding their jointly owned North Texas 36-inch diameter pipeline, which is a component of our Texas Intrastate System, to provide additional natural gas takeaway capacity of 150 MMcf/d from West Texas, including deliveries into the Old Ocean Pipeline.  The North Texas Pipeline expansion project is expected to be complete by late fourth quarter of 2018.

The resumption of full service on the Old Ocean Pipeline and expansion of the North Texas Pipeline are expected to provide producers with additional takeaway capacity to accommodate growing natural gas production from the Delaware and Midland Basins.

Expansions of our Front Range and Texas Express Pipelines
In May 2018, we conducted open commitment periods to determine shipper interest in expansions of the Front Range Pipeline (“Front Range”) and Texas Express Pipeline (“Texas Express”).  Given the positive responses we received from shippers, we will proceed with the proposed expansions.   We own a 33.3% equity interest in Front Range and a 35.0% equity interest in Texas Express.   We operate both pipelines.

The expansions are designed to facilitate growing production of NGLs from domestic shale basins, including the DJ Basin in Colorado, by providing DJ Basin producers with flow assurance and greater access to the Gulf Coast markets.  The expansions are expected to increase the transportation capacity of Front Range and Texas Express by 100 MBPD and 90 MBPD, respectively.  We anticipate the expansion projects will be placed into servicenine months ended September 30, 2019 (no repurchases were made during the third quarter of 2019.2019).  The total purchase price of these repurchases was $81.1 million, excluding commissions and fees. The repurchased units were cancelled immediately upon acquisition.  At September 30, 2019, the remaining available capacity under the 2019 Buyback Program was $1.92 billion.

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Enterprise Expands Marine Terminal on the Houston Ship ChannelProvides 2019 Distribution Guidance
In April 2018, we acquired 65-acres of waterfront property on the Houston Ship Channel for approximately $85.2 million, all of which was recorded as land.  The purchase price consisted of $55.2 million in cash with the remaining balance funded through 1,223,242 newly-issued Enterprise common units.  The land is located immediately to the east of EHT and is expected to facilitate future expansion projects at the terminal.

Acquisition of Remaining 50% Ownership Interest in Delaware Processing
In March 2018, we acquired the remaining 50% member interest in our Delaware Basin Gas Processing LLC (“Delaware Processing”) joint venture for $150.6 million in cash, net of $3.9 million of cash held by the former joint venture.  Delaware Processing owns a cryogenic natural gas processing facility (our “Waha” gas plant) having a capacity of 150 MMcf/d.  The Waha plant is located in Reeves County, Texas and entered service in August 2016. The acquired business serves growing production of NGL-rich natural gas from the Delaware Basin in West Texas and southern New Mexico. For information regarding this acquisition, see Note 11 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

Enterprise to Expand Butane Isomerization Facility
In January 2018, we2019, management announced plans to expandrecommend to the Board an increase of $0.0025 per unit per quarter in our butane isomerization facility by upcash distribution rate with respect to 30 MBPD2019. The anticipated rate of incremental capacity.   This expansionincrease would result in distributions for 2019 of $1.7650 per unit, which would be 2.3% higher than those paid for 2018 of $1.7250 per unit.  The payment of any quarterly cash distribution is supported by new long-term agreements, including a 20-year, 35 MBPD fee-based, tolling arrangement,subject to provide butane isomerization, storageBoard approval and pipeline services.

Resultsmanagement’s evaluation of Operations

Summarized Consolidated Income Statement Data
The following table summarizes the key components of our financial condition, results of operations forand cash flows in connection with such payment.

On October 9, 2019, we announced that the periods indicated (dollars in millions):

  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2018  2017  2018  2017 
Revenues $9,585.9  $6,886.9  $27,351.9  $20,814.9 
Costs and expenses:                
Operating costs and expenses:                
Cost of sales  6,838.9   5,049.6   20,371.2   15,116.4 
Other operating costs and expenses  735.7   637.4   2,143.1   1,853.4 
Depreciation, amortization and accretion expenses  429.4   383.9   1,249.0   1,139.3 
Net gains attributable to asset sales  (6.7)  (1.1)  (8.1)  (1.1)
Asset impairment and related charges  4.6   10.0   21.4   35.2 
Total operating costs and expenses  8,001.9   6,079.8   23,776.6   18,143.2 
General and administrative costs  52.7   41.3   157.1   137.4 
Total costs and expenses  8,054.6   6,121.1   23,933.7   18,280.6 
Equity in income of unconsolidated affiliates  112.0   113.4   350.0   315.2 
Operating income  1,643.3   879.2   3,768.2   2,849.5 
Interest expense  (279.5)  (243.9)  (806.2)  (739.0)
Change in fair market value of Liquidity Option Agreement  (18.5)  (8.9)  (34.9)  (33.0)
Other, net  0.3   0.3   40.7   0.9 
Provision for income taxes  (11.0)  (5.4)  (34.5)  (20.1)
Net income  1,334.6   621.3   2,933.3   2,058.3 
Net income attributable to noncontrolling interests  (21.4)  (10.4)  (45.6)  (33.0)
Net income attributable to limited partners $1,313.2  $610.9  $2,887.7  $2,025.3 


Consolidated Revenues
We classify our revenues into sales$0.4425 per common unit with respect to the third quarter of products and midstream services.  Product sales relate primarily2019.  This distribution will be paid on November 12, 2019 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 (netunitholders of eliminations, dollars in millions):

  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2018  2017  2018  2017 
NGL Pipelines & Services:            
Sales of NGLs and related products $3,898.2  $2,415.3  $9,324.5  $7,460.5 
Midstream services  724.7   499.0   1,985.4   1,420.2 
Total  4,622.9   2,914.3   11,309.9   8,880.7 
Crude Oil Pipelines & Services:                
Sales of crude oil  2,209.0   1,589.0   8,082.9   4,912.7 
Midstream services  285.9   207.7   764.1   590.8 
Total  2,494.9   1,796.7   8,847.0   5,503.5 
Natural Gas Pipelines & Services:                
Sales of natural gas  589.0   568.9   1,681.5   1,673.5 
Midstream services  261.2   227.7   766.3   670.5 
Total  850.2   796.6   2,447.8   2,344.0 
Petrochemical & Refined Products Services:                
Sales of petrochemicals and refined products  1,408.9   1,194.2   4,111.6   3,519.4 
Midstream services  209.0   185.1   635.6   567.3 
Total  1,617.9   1,379.3   4,747.2   4,086.7 
Total consolidated revenues $9,585.9  $6,886.9  $27,351.9  $20,814.9 

For periods through December 31, 2017, we accounted for our revenue streams using Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 605, Revenue Recognition.  Effective January 1, 2018, we adopted FASB ASC 606, Revenue from Contracts with Customers, using a modified retrospective approach that applied the new revenue recognition standard to existing contracts at the implementation date and any future revenue contracts.   For information regarding this change in accounting principle (including various transition disclosures), see Notes 2 and 9record as of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1close of this quarterly report.business on October 31, 2019.




Selected Energy Commodity Price Data

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


                   Polymer  Refinery      PolymerRefineryIndicative Gas
 Natural        Normal     Natural  Grade  Grade Natural  Normal NaturalGradeGradeProcessing
 Gas,  Ethane,  Propane,  Butane,  Isobutane,  Gasoline,  Propylene,  Propylene, Gas,Ethane,Propane,Butane,Isobutane,Gasoline,Propylene,Propylene,Gross Spread
 $/MMBtu  $/gallon  $/gallon  $/gallon  $/gallon  $/gallon  $/pound  $/pound $/MMBtu$/gallon$/gallon$/gallon$/gallon$/pound$/pound$/gallon
 (1)  (2)  (2)  (2)  (2)  (2)  (3)  (3) (1)(2)(2)(2)(2)(3)(3)(4)
2017 by quarter:                                
2018 by quarter:        
1st Quarter $3.32  $0.23  $0.71  $0.98  $0.94  $1.10  $0.47  $0.32 $3.01$0.25$0.85$0.96$1.00$1.41$0.53$0.33$0.40
2nd Quarter $3.19  $0.25  $0.63  $0.76  $0.75  $1.07  $0.41  $0.28 $2.80$0.29$0.87$1.00$1.20$1.53$0.52$0.37$0.47
3rd Quarter $2.99  $0.26  $0.77  $0.91  $0.92  $1.10  $0.42  $0.28 $2.91$0.43$0.99$1.21$1.25$1.54$0.60$0.45$0.58
4th Quarter $2.93  $0.25  $0.96  $1.04  $1.04  $1.32  $0.49  $0.35 $3.65$0.35$0.79$0.91$0.94$1.22$0.51$0.35$0.34
2017 Averages $3.11  $0.25  $0.77  $0.92  $0.91  $1.15  $0.45  $0.31 
2018 Averages$3.09$0.33$0.88$1.02$1.10$1.43$0.54$0.38$0.45
                                        
2018 by quarter:                                
2019 by quarter:        
1st Quarter $3.01  $0.25  $0.85  $0.96  $1.00  $1.41  $0.53  $0.33 $3.15$0.30$0.67$0.82$0.85$1.16$0.38$0.24$0.31
2nd Quarter $2.80  $0.29  $0.87  $1.00  $1.20  $1.53  $0.52  $0.37 $2.64$0.21$0.55$0.63$0.65$1.21$0.37$0.24$0.25
3rd Quarter $2.91  $0.43  $0.99  $1.21  $1.25  $1.54  $0.60  $0.45 $2.23$0.17$0.44$0.51$0.66$1.06$0.38$0.23$0.21
2018 Averages $2.91  $0.32  $0.90  $1.06  $1.15  $1.49  $0.55  $0.38 
                                
(1) Natural gas prices are based on Henry-Hub Inside FERC commercial index prices as reported by Platts, which is a division of McGraw Hill Financial, Inc.
(2) NGL prices for ethane, propane, normal butane, isobutane and natural gasoline are based on Mont Belvieu Non-TET commercial index prices as reported by Oil Price Information Service.
(3) Polymer grade propylene prices represent average contract pricing for such product as reported by IHS Chemical, a division of IHS Inc. (“IHS Chemical”). Refinery grade propylene prices represent weighted-average spot prices for such product as reported by IHS Chemical.
 
2019 Averages$2.67$0.23$0.55$0.65$0.72$1.14$0.38$0.24$0.26


(1)Natural gas prices are based on Henry-Hub Inside FERC commercial index prices as reported by Platts, which is a division of McGraw Hill Financial, Inc.
(2)NGL prices for ethane, propane, normal butane, isobutane and natural gasoline are based on Mont Belvieu Non-TET commercial index prices as reported by Oil Price Information Service.
(3)Polymer grade propylene prices represent average contract pricing for such product as reported by IHS Chemical, a division of IHS Inc. (“IHS Chemical”).  Refinery grade propylene prices represent weighted-average spot prices for such product as reported by IHS Chemical.
(4)The “Indicative Gas Processing Gross Spread” represents a generic estimate of the gross economic benefit from extracting NGLs from natural gas production based on certain pricing assumptions.  Specifically, it is the amount by which the assumed economic value of a composite gallon of NGLs at Mont Belvieu, Texas exceeds the value of the equivalent amount of energy in natural gas at Henry Hub, Louisiana (as presented in the table above). The indicative spread does not consider the operating costs incurred by a natural gas processing plant to extract the NGLs nor the transportation and fractionation costs to deliver the NGLs to market.   In addition, the actual gas processing spread earned at each plant is determined by regional pricing and extraction dynamics.   As presented in the table above, the indicative spread assumes that a gallon of NGLs is comprised of 47% ethane, 28% propane, 9% normal butane, 6% isobutane and 10% natural gasoline.  The value of an equivalent amount of energy in natural gas to one gallon of NGLs is assumed to be 8.4% of the price of a MMBtu of natural gas at Henry Hub.

53


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


            WTIMidlandHoustonLLS
 WTI  Midland  Houston  LLS Crude Oil,Crude OilCrude Oil,
 Crude Oil,  Crude Oil,  Crude Oil  Crude Oil, $/barrel
 $/barrel  $/barrel  $/barrel  $/barrel 
 (1)  (2)  (2)  (3) 
2017 by quarter:                
1st Quarter $51.91  $51.72  $53.27  $53.52 
2nd Quarter $48.28  $47.29  $49.77  $50.31 
3rd Quarter $48.20  $47.37  $50.84  $51.62 
4th Quarter $55.40  $55.47  $59.84  $61.07 
2017 Averages $50.95  $50.44  $53.41  $54.13 
                (1)(2)(3)
2018 by quarter:                 
1st Quarter $62.87  $62.51  $65.47  $65.79 $62.87$62.51$65.47         $65.79
2nd Quarter $67.88  $59.93  $72.38  $72.97 $67.88$59.93$72.38$72.97
3rd Quarter $69.50  $55.28  $73.67  $74.28 $69.50$55.28$73.67$74.28
4th Quarter$58.81$53.64$66.34          $66.20
2018 Averages $66.75  $59.24  $70.51  $71.01 $64.77$57.84$69.47$69.81
                 
(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.
 
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
2019 Averages$57.05$55.81$62.47$63.35


(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.

Fluctuations in our consolidated revenues and cost of sales amounts are explained in large part by changes in energy commodity prices.  Energy commodity prices, which fluctuate for a variety of reasons including supply and demand imbalances and geopolitical tensions.  The weighted-average indicative market price for NGLs was $0.94 $0.39 per gallon in the third quarter of 20182019 versus $0.68$0.82 per gallon during the third quarter of 2017.2018.  Likewise, the weighted-average indicative market price for NGLs was $0.84$0.48 per gallon during the nine months ended September 30, 20182019 compared to $0.65$0.72 per gallon during the same period in 2017.2018.

An increaseA decrease in our consolidated marketing revenues due to higherlower energy commodity sales prices may not result in an increasea decrease  in gross operating margin or cash available for distribution, since our consolidated cost of sales amounts would also be higherdecrease due to comparable increasesdecreases in the purchase prices of the underlying energy commodities.  The same type of correlation would be true in the case of lowerhigher 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 for information regarding our commodity hedging activities.


Consolidated
54


Income Statement Highlights

The following information highlights significant changestable summarizes the key components of our consolidated results of operations for the periods indicated (dollars in our comparative income statement amounts andmillions):

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

Revenues

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

  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2019  2018  2019  2018 
NGL Pipelines & Services:            
Sales of NGLs and related products $2,624.9  $3,898.2  $7,955.5  $9,324.5 
Midstream services  627.2   724.7   1,895.7   1,985.4 
Total  3,252.1   4,622.9   9,851.2   11,309.9 
Crude Oil Pipelines & Services:                
    Sales of crude oil  2,130.0   2,209.0   6,990.1   8,082.9 
    Midstream services  348.3   285.9   962.1   764.1 
        Total  2,478.3   2,494.9   7,952.2   8,847.0 
Natural Gas Pipelines & Services:                
    Sales of natural gas  440.0   589.0   1,627.1   1,681.5 
    Midstream services  275.5   261.2   835.2   766.3 
       Total  715.5   850.2   2,462.3   2,447.8 
Petrochemical & Refined Products Services:                
    Sales of petrochemicals and refined products  1,299.0   1,408.9   3,867.3   4,111.6 
    Midstream services  219.2   209.0   650.9   635.6 
       Total  1,518.2   1,617.9   4,518.2   4,747.2 
Total consolidated revenues $7,964.1  $9,585.9  $24,783.9  $27,351.9 


55

Revenues
Third Quarter of 20182019 Compared to Third Quarter of 20172018.  Total revenues for the third quarter of 2018 increased $2.72019 decreased $1.62 billion when compared to the third quarter of 20172018 primarily due to a $2.34net $1.61 billion increasedecrease in marketing revenues. Revenues from the marketing of NGLs, increased $1.48petrochemicals and refined products decreased a combined net $1.38 billion quarter-to-quarter primarily due to higherlower sales prices, which accounted for a $760.8 million increase, and$2.04 billion decrease, partially offset by the effects of higher sales volumes, which accounted for an additional $722.1resulted in a $657.3 million increase.  Revenues from the marketing of crude oil, petrochemicals and refined products increased a net $834.7natural gas decreased $149.0 million quarter-to-quarter primarily due to higherlower sales prices.  Revenues from the marketing of crude oil decreased a net $79.0 million quarter-to-quarter primarily due to lower sales prices, which accounted for a $1.4 billion increase,$429.9 million decrease, partially offset by higher sales volumes, which resulted in a $570.0$350.9 million decrease due to lower sales volumes.increase.


Revenues from midstream services for the third quarter of 2018 increased $361.32019 decreased $10.6 million when compared to the third quarter of 2017.  As a result of adopting ASC 606 on January 1, 2018, we recognized $215.8 million of revenues during the third quarter of 2018 in connection with the receipt of non-cash consideration (in the form of equity NGLs) for providing2018.  Revenues from our natural gas processing services. plants decreased $125.5 million quarter-to-quarter primarily due to lower market values for the equity NGLs we receive as non-cash consideration for providing processing services to certain customers, which accounted for a $151.1 million decrease, partially offset by contributions from our recently completed Orla facility, which accounted for a $22.7 million increase.  We recognize revenues related to the equity NGLs we receive under commodity-based contracts (once the processing service has been performed and we are entitled to such volumes) at market value.

Midstream service revenues from our pipeline assets increased $118.1$48.5 million quarter-to-quarter primarily due to strong demand for transportation servicescontributions from our Midland-to-ECHO 2 pipeline, which commenced operations in TexasFebruary 2019.  Revenues from our terminal assets increased $39.5 million quarter-to-quarter primarily due to an increase in loading volumes at EHT.

Lastly, revenues from our Mont Belvieu storage complex increased a combined $27.7 million quarter-to-quarter primarily due to higher storage, throughput and on the Appalachia-to-Texas Express (“ATEX”) pipeline.other fees.


Nine Months Ended September 30, 20182019 Compared to Nine Months Ended September 30, 20172018.  Total revenues for the nine months ended September 30, 2018 increased $6.542019 decreased $2.57 billion when compared to the nine months ended September 30, 20172018 primarily due to a $5.63$2.76 billion increasedecrease in marketing revenues.  Revenues from the marketing of crude oil increased $3.17 billion period-to-period primarily due to higher sales volumes, which accounted for a $1.63 billion increase, and higher sales prices, which accounted for an additional $1.54 billion increase.  Revenues from the marketing of NGLs, petrochemicals and refined products increaseddecreased a combined net $2.46$1.61 billion period-to-period primarily due to higherlower sales prices, which accounted for a $2.9$3.15 billion increase,decrease, partially offset by higher sales volumes, which resulted in a $441.5 million decrease$1.54 billion increase.  Revenues from the marketing of crude oil decreased $1.09 billion period-to-period primarily due to lower sales volumes.volumes, which accounted for a $906.0 million decrease, and lower sales prices, which resulted in an additional $186.8 million decrease.


Revenues from midstream services for the nine months ended September 30, 20182019 increased $902.6$192.5 million when compared to the nine months ended September 30, 2017.  As a result of adopting ASC 606, we recognized $491.4 million in connection with the receipt of non-cash consideration for providing natural gas processing services during the nine months ended September 30, 2018.  Midstream service revenuesRevenues from our pipeline assets increased $312.1$234.9 million period-to-period primarily due to strong demand for transportation services in TexasTexas. Our Midland-to-ECHO 1 and on the ATEX Pipeline.

For additional information regarding our consolidated revenues, including the adoption of ASC 606, see Note 9 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 12 pipelines accounted for a combined $160.2 million of this quarterly report.increase.  Revenues from our Mont Belvieu storage complex increased a combined $76.2 million period-to-period primarily due to higher storage, throughput and other fees. In addition, revenues from our terminal assets increased $56.6 million period-to-period primarily due to an increase in loading volumes at EHT. These increases were partially offset by lower revenues from our natural gas processing plants of $188.3 million period-to-period primarily due to lower market values for the equity NGLs we receive as non-cash consideration, which accounted for a $275.3 million decrease, partially offset by contributions from our recently completed Orla facility, which accounted for a $131.8 million increase.


62

Operating costs and expenses

Third Quarter of 20182019 Compared to Third Quarter of 20172018.  Total operating costs and expenses for the third quarter of 2018 increased $1.922019 decreased $1.43 billion when compared to the third quarter of 20172018 primarily due to a $1.79 billion increase in cost of sales.  The cost of sales associated with our NGL marketing activities increased $1.54 billion quarter-to-quarter primarily due to higher sales volumes, which accounted for a $785.6 million increase, and higher purchase prices, which accounted for an additional $538.1 million increase. In addition, cost of sales attributable to our NGL marketing activities for the third quarter of 2018 includes $215.8 million resulting from the adoption of ASC 606 and attributable to the sale and delivery of equity NGL products to customers.  The cost of sales associated with our marketing of crude oil increased a net $225.7 million quarter-to-quarter primarily due to higher purchase prices, which accounted for a $494.0 million increase, partially offset by lower sales volumes, which accounted for a $268.3 million decrease.

Other operating costs and expenses for the third quarter of 2018 increased $98.3 million when compared to the third quarter of 2017 primarily due to higher maintenance, power and employee compensation costs. Depreciation, amortization and accretion expense increased $45.5 million quarter-to-quarter primarily due to assets we constructed and placed into service since the third quarter of 2017 (e.g., our Midland-to-ECHO Pipeline and propane dehydrogenation (“PDH”) facility).

Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017.  Total operating costs and expenses for the nine months ended September 30, 2018 increased $5.63 billion when compared to the nine months ended September 30, 2017 primarily due to a $5.25 billion increase in cost of sales. The cost of sales associated with our marketing of crude oil increased $3.05NGLs, petrochemicals and refined products decreased a combined $1.47 billion period-to-periodquarter-to-quarter primarily due to higherlower purchase prices, which accounted for a $1.54$2.06 billion increase, anddecrease, partially offset by higher sales volumes, which accounted for an additional $1.5a $590.4 million increase. Other operating costs and expenses increased a net $55.1 million quarter-to-quarter primarily due to higher maintenance, power, chemical and employee compensation costs, which accounted for a combined $50.9 million increase.

56


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

Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018.  Total operating costs and expenses for the nine months ended September 30, 2019 decreased $3.38 billion when compared to the nine months ended September 30, 2018 primarily due to lower cost of sales. The cost of sales associated with our marketing of NGLs, petrochemicals and refined products decreased a combined net $1.77 billion period-to-period primarily due to lower purchase prices, which accounted for a $3.25 billion decrease, partially offset by higher sales volumes, which accounted for a $1.48 billion increase.  The cost of sales associated with our NGL marketing activities increased $2.27of crude oil decreased $1.69 billion period-to-period primarily due to higher sales price,lower purchase prices, which accounted for a $4.31 billion increase, partially offset by$947.3 million decrease, and lower sales volumes, which accounted for a $2.53 billionan additional $744.7 million decrease. In addition, cost of sales attributable to our NGL marketing activities for 2018 includes $491.4 million resulting from the adoption of ASC 606 and attributable to the sale and delivery of equity NGL products to customers.


Other operating costs and expenses for the nine months ended September 30, 2019 increased a net $100.3 million period-to-period primarily due to higher maintenance and chemical expenses, ad valorem taxes, and employee compensation costs, which accounted for a combined $124.0 million increase. These costs were partially offset by $33.9 million of expense recognized in the nine months ended September 30, 2018 increased $289.7 million when compared to the nine months ended September 30, 2017 primarily due to higher maintenance, power and employee compensation costs.  In addition, we recorded $33.9 million of expense in 2018 in connection with theour earnings allocation arrangement with an affiliate of Western which ended May 31, 2018, Midstream Partners, LP (“Western”) involving ourthe Midland-to-ECHO crude oil1 pipeline.

Depreciation, amortization and accretion expense increased $109.7$131.8 million period-to-period primarily due to assets we constructed and placed into full or limited service since the third quarter of 2017.2018.  Non-cash asset impairment charges increased $29.8 million period-to-period primarily due to the planned shutdown of certain natural gas processing assets in Texas and Louisiana (as noted previously).


General and administrative costs

General and administrative costs for the three and nine months ended September 30, 20182019 increased $11.4 $2.8 million and $19.7 $3.1 million, respectively, when compared to the same periods in 20172018 primarily due to higher employee compensation and legalemployee-related costs.


Equity in income of unconsolidated affiliates

Equity income from our unconsolidated affiliates for the third quarter ofthree and nine months ended September 30, 2019 increased $27.3 million and $81.3 million, respectively, when compared to the same periods in 2018 decreased $1.4 million quarter-to-quarter primarily due to lowerincreases in earnings from our investments in crude oil pipelines, which accounted for a combined $12.2 million decrease, partially offset by higher earnings from investments in NGL pipelines, which increased a combined $9.4 million.  Equity income from our unconsolidated affiliates for the nine months ended September 30, 2018 increased $34.8 million when compared to the same period in 2017 primarily due to an increase in earnings from our investments in NGL pipelines.


Operating income

Operating income for the three and nine months ended September 30, 2018 increased $764.1 2019 decreased $169.1 million and $918.7increased $892.5 million, respectively, when compared to the same periods in 20172018 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.




57
63

Interest expense
Interest expense for the three and nine months ended September 30, 2018 increased $35.6 million and $67.2 million, respectively, when compared to the same periods in 2017.  

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,
 
 2018  2017  2018  2017  2019  2018  2019  2018 
Interest charged on debt principal outstanding $296.5  $281.0  $886.3  $826.7  $319.3  $296.5  $934.2  $886.3 
Impact of interest rate hedging program, including related amortization (1)  (1.7)  10.1   (0.5)  28.1   90.3   (1.7)  97.9   (0.5)
Interest costs capitalized in connection with construction projects (2)  (28.1)  (53.6)  (113.4)  (137.7)  (33.9)  (28.1)  (102.9)  (113.4)
Other (3)  12.8   6.4   33.8   21.9   7.2   12.8   21.0   33.8 
Total $279.5  $243.9  $806.2  $739.0  $382.9  $279.5  $950.2  $806.2 
 
(1) Amount presented for three and nine months ended September 30, 2018 includes $10.4 million and $29.4 million, respectively, of swaption premium income.
(2) We capitalize interest costs incurred on funds used to construct property, plant and equipment while the asset is in its construction phase. Capitalized interest amounts become part of the historical cost of an asset and are charged to earnings (as a component of depreciation expense) on a straight-line basis over the estimated useful life of the asset once the asset enters its intended service. When capitalized interest is recorded, it reduces interest expense from what it would be otherwise. Capitalized interest amounts fluctuate based on the timing of when projects are placed into service, our capital spending levels and the interest rates charged on borrowings.
(3) Primarily reflects facility commitment fees charged in connection with our revolving credit facilities and amortization and write-off of debt issuance costs. Amount presented for the three and nine months ended September 30, 2018 includes $6.4 million and $14.2 million, respectively, of debt issuance costs that were written off in connection with the redemption of junior subordinated notes.
 


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

Interest charged on debt principal outstanding, which is the primarya key driver of interest expense, increased a net $15.5 $22.8 million quarter-to-quarter primarily due to increased debt principal amounts outstanding during the third quarter of 2018,2019, which accounted for a $21.2 $24.1 million increase, partially offset by the effect of lower overall interest rates during the third quarter of 2018,2019, which accounted for a $5.7 $1.3 million decrease.  Our weighted-average debt principal balance for the third quarter of 20182019 was $26.08 $27.93 billion compared to $24.20$26.08 billion for the third quarter of 2017.

2018.  For the nine months ended September 30, 2018,2019, interest charged on debt principal outstanding increased a net $59.6 $47.9 million period-to-period primarily due to increased debt principal amounts outstanding during the nine months ended September 30, 2018,2019, which accounted for a $67.3 $53.8 million increase, partially offset by the effect of lower overall interest rates during the nine months ended September 30, 2018,2019, which accounted for a $7.7 $5.9 million decrease.  Our weighted-average debt principal balance for the nine months ended September 30, 20182019 was $25.76 $27.29 billion compared to $23.87$25.76 billion for the nine months ended September 30, 2017.

Our2018.  In general, our debt principal balances have increased over time due to the partial debt financing of our capital spending program.  Forinvestments.

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

Due to declining interest rates, the counterparties to the swaptions sold in July 2019 exercised their right to put us into ten forward-starting swaps on September 30, 2019 having an aggregate notional value of our consolidated$1.0 billion. Forward-starting swaps hedge the risk of an increase in underlying benchmark interest rates during the period of time between the inception date of the swap agreement and the future date of debt obligationsissuance. Under the terms of the forward-starting swaps, we will pay to the counterparties (at the expected settlement dates of the instruments) amounts based on a 30-year fixed interest rate applied to the notional amount and capital spending program, see “Liquidityreceive from the counterparties an amount equal to a 30-year variable interest rate on the same notional amount.  On September 30, 2019, the weighted-average fixed interest rate of the ten forward-starting swaps was 2.12%, which was 0.41% higher than the then applicable variable interest rate.  As a result, we incurred an unrealized, mark-to-market loss at inception totaling $94.9 million that is reflected as an increase in interest expense for the three and Capital Resources”nine months ended September 30, 2019.  Prospectively, we will account for the forward-starting swaps as cash flow hedges, with any subsequent gains or losses on these derivative instruments reflected as a component of other comprehensive income and “Capital Spending” within this Part I, Item 2.be amortized to earnings (through interest expense) over the 30-year period of the associated future debt issuance.

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

Change in fair value of Liquidity Option Agreement
The change in fair value of the Liquidity Option Agreement reflects
We recognize non-cash expense attributable toassociated with accretion and changes in management estimates regarding inputs tothat affect our valuation of the valuation model.Liquidity Option Agreement. For the three and nine months ended September 30, 2018,2019, expense resulting from changesattributable to increases in the fair value of the Liquidity Option Agreement increased $9.6$20.2 million and $1.9$88.2 million, respectively, when compared to the same periods in 2017.2018.   Expense recognized during the three and nine months ending September 30, 2019 is primarily due to decreases in the applicable midstream industry weighted-average cost of capital, which is used as a discount factor in determining the present value of the liability, since June 30, 2019 and December 31, 2018, respectively.  For additional information regarding the Liquidity Option Agreement, see Note 1615 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.


Gain on step acquisition of unconsolidated affiliate
We recognized
Upon our acquisition of the remaining 50% member interest in Delaware Basin Gas Processing LLC (“Delaware Processing”) in March 2018, our existing equity investment in Delaware Processing was remeasured to fair value resulting in the recognition of a non-cash gain of $39.4 million duringfor the nine months ended September 30, 2018 related to the step acquisition of Delaware Processing.  For information regarding this acquisition, see Note 11 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.2018.


Income taxes
Income taxes

Provision for income taxes primarily reflectreflects our state tax obligations under the Revised Texas Franchise Tax.  Tax (the “Texas Margin Tax”).  Our provision for income taxes for the three and nine months ended September 30, 20182019 increased $5.6 $4.4 million and $14.4 $2.9 million, respectively, when compared to the same periods in 2017.2018.  Our partnership is not subject to U.S. federal income tax; however, our partners are individually responsible for paying federal income tax on their share of our taxable income.


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Business Segment Highlights

The following information highlights significant changes in our quarter-to-quarter and period-to-period segment results (i.e., our gross operating margin by segment amounts) and the primary drivers of such changes. The volume statistics presented for each segment are reported on a net basis, taking into account our ownership interests, and reflect the periods in which we owned an interest in such operations.

Total 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. 


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


 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
 2018  2017  2018  2017  2019  2018  2019  2018 
Gross operating margin by segment:                        
NGL Pipelines & Services $1,063.1  $770.9  $2,861.7  $2,386.8  $1,008.3  $1,063.1  $2,933.8  $2,861.7 
Crude Oil Pipelines & Services  594.2   190.4   867.0   691.7   496.2   594.2   1,671.7   867.0 
Natural Gas Pipelines & Services  216.9   170.7   628.2   536.0   258.5   216.9   824.6   628.2 
Petrochemical & Refined Products Services  249.4   172.4   803.1   542.6   288.4   249.4   835.9   803.1 
Total segment gross operating margin (1)  2,123.6   1,304.4   5,160.0   4,157.1   2,051.4   2,123.6   6,266.0   5,160.0 
Net adjustment for shipper make-up rights  (0.3)  8.9   27.6   3.2   (15.3)  (0.3)  (15.7)  27.6 
Total gross operating margin (non-GAAP) $2,123.3  $1,313.3  $5,187.6  $4,160.3  $2,036.1  $2,123.3  $6,250.3  $5,187.6 
                
(1) Within the context of this table, total segment gross operating margin represents a subtotal and corresponds to measures similarly titled within our business segment disclosures found in Note 10 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report. 


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

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.

Gross  Our calculation of gross operating margin may or may not be comparable to similarly titled measures used by segmentother 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.
In late August and early September 2017, the Gulf Coast region of Texas, including its critical energy infrastructure, was impacted by the cumulative effects of Hurricane Harvey.  Impacts on the energy industry included, but were not limited to, severe flooding and limited access to facilities, disruptions to energy demand from area refineries and petrochemical facilities and the closure of all ports on the Texas Gulf Coast, which limited access to export markets.  Although operating at reduced rates, many of our plant, pipeline and storage assets along the Texas Gulf Coast remained operational during the storm.  We estimate that Hurricane Harvey reduced our gross operating margin for the third quarter of 2017 by approximately $35 million, of which $25 million was attributable to our Petrochemical & Refined Products Services business segment and $7 million to our NGL Pipelines & Services business segment.



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 “Consolidated Income“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,
 
  2018  2017  2018  2017 
Operating income (GAAP) $1,643.3  $879.2  $3,768.2  $2,849.5 
Adjustments to reconcile operating income to total gross operating margin:                
Add depreciation, amortization and accretion expense in operating costs and expenses  429.4   383.9   1,249.0   1,139.3 
Add asset impairment and related charges in operating costs and expenses  4.6   10.0   21.4   35.2 
Subtract net gains attributable to asset sales in operating costs and expenses  (6.7)  (1.1)  (8.1)  (1.1)
     Add general and administrative costs  52.7   41.3   157.1   137.4 
Total gross operating margin (non-GAAP) $2,123.3  $1,313.3  $5,187.6  $4,160.3 
  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2019  2018  2019  2018 
Operating income (GAAP) $1,474.2  $1,643.3  $4,660.7  $3,768.2 
Adjustments to reconcile operating income to total gross operating margin
   (addition or subtraction indicated by sign):
                
Depreciation, amortization and accretion expense in operating costs and expenses  467.1   429.4   1,380.8   1,249.0 
Asset impairment and related charges in operating costs and expenses  39.4   4.6   51.2   21.4 
Net gains attributable to asset sales in operating costs and expenses  (0.1)  (6.7)  (2.6)  (8.1)
General and administrative costs  55.5   52.7   160.2   157.1 
Total gross operating margin (non-GAAP) $2,036.1  $2,123.3  $6,250.3  $5,187.6 


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

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NGL Pipelines & Services


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


 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
 2018  2017  2018  2017  2019  2018  2019  2018 
Segment gross operating margin:                        
Natural gas processing and related NGL marketing activities $396.8  $203.2  $955.0  $685.8  $288.0  $396.8  $829.3  $955.0 
NGL pipelines, storage and terminals  513.5   435.4   1,488.2   1,326.6   593.4   513.5   1,739.4   1,488.2 
NGL fractionation  152.8   132.3   418.5   374.4   126.9   152.8   365.1   418.5 
Total $1,063.1  $770.9  $2,861.7  $2,386.8  $1,008.3  $1,063.1  $2,933.8  $2,861.7 
                                
Selected volumetric data:                                
Equity NGL production (MBPD) (1)  139   166   156   160   111   139   138   156 
Fee-based natural gas processing (MMcf/d) (2)  5,080   4,753   4,751   4,650   5,291   5,080   5,275   4,751 
NGL pipeline transportation volumes (MBPD)  3,487   3,052   3,396   3,131   3,557   3,487   3,532   3,396 
NGL marine terminal volumes (MBPD)  606   456   592   499   602   606   590   592 
NGL fractionation volumes (MBPD)  989   815   942   818   1,003   989   990   942 
 
(1) Represents the NGL volumes we earn and take title to in connection with our processing activities.
(2) Volumes reported correspond to the revenue streams earned by our gas plants.
 


(1)Represents the NGL volumes we earn and take title to in connection with our processing activities.
(2)Volumes reported correspond to the revenue streams earned by our gas plants.

Natural gas processing and related NGL marketing activities
Third Quarter of 20182019 Compared to Third Quarter of 2017. 2018.  Gross operating margin from natural gas processing and related NGL marketing activities for the third quarter of 2018 increased $193.6 2019 decreased $108.8 million when compared to the third quarter of 2017.

2018.  Gross operating margin from our NGL marketing activities increased $86.9Rockies natural gas processing plants (including Meeker, Pioneer and Chaco) decreased a combined $50.4 million quarter-to-quarter primarily due to higher average sales margins.  The results from marketing strategies that optimize our transportation and plant assets increased a combined $92.7 million quarter-to-quarter primarily due to higher basis spreads during the third quarter of 2018, partially offset by an $8.0 million decrease in earnings from export-related strategies.

Results from our NGL marketing strategies for the third quarter of 2018 benefited from strong commodity prices and wide basis spreads resulting from constrained takeaway pipeline capacity due to increased production from major producing areas such as the Permian Basin and Midcontinent regions and tightness in downstream NGL fractionation capacity.  Ethane demand from ethylene crackers is currently at peak levels of 1.5 MMBPD (a 37% increase versus one year ago) as several new large ethylene plants along the U.S. Gulf Coast have commenced operations during 2018. From a pricing perspective, average ethane prices increased 48% quarter-to-quarter from $0.29 per gallon in the second quarter of 2018 to $0.43 per gallon in the third quarter of 2018, with daily highs of approximately $0.60 per gallon in late September 2018.  Based on current trends, we expect basis differentials and overall commodity prices to be lower in the fourth quarter of 2018.

Gross operating margin from our Meeker, Pioneer and Chaco natural gas processing plants increased a net $58.7 million quarter-to-quarter primarily due to higher average processing margins (including the impact of hedging activities), which accounted for an increase of $87.3 million, partially offset by the effects of lower equity NGL production volumes of 19 MBPD, which accounted for a $31.0 million decrease.  On a combined basis for these plants, fee-based natural gas processing volumes increased 164 MMcf/d quarter-to-quarter.  Likewise, gross operating margin from our South Texas natural gas processing plants increased a net $18.4 million quarter-to-quarter primarily due to higher average processing margins (including the impact of hedging activities), which accounted for a $40.2$43.0 million increase, partially offset by lowerdecrease, and higher maintenance and other operating costs, which accounted for an additional $5.9 million decrease.  On a combined basis, fee-based natural gas processing volumes at these plants increased 47 MMcf/d and equity NGL production volumes of 25decreased 16 MBPD quarter-to-quarter.

Gross operating margin from our NGL marketing activities decreased a net $27.4 million quarter-to-quarter primarily due to lower average sales margins, which accounted for a $23.5$91.0 million decrease, partially offset by higher sales volumes, which accounted for a $63.1 million increase.  Results from marketing strategies that optimize our transportation and plant assets decreased $44.8 million quarter-to-quarter, partially offset by a $21.8 million increase in earnings related to the optimization of our storage and export assets.  In addition, results from NGL marketing decreased $4.4 million quarter-to-quarter due to non-cash, mark-to-market activity.

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

Gross operating margin from our South Texas natural gas processing plants decreased $11.9 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $4.7 million decrease, and lower deficiency fees, which accounted for an additional $4.4 million decrease.  Fee-based natural gas processing volumes and equity NGL production at our South Texas plants decreased 103 45 MMcf/d and increased 1 MBPD, respectively, quarter-to-quarter. We elected to reduce our overall equity NGL production volumes during the third quarter

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Gross operating margin from our Permian Basin natural gas processing plants (South Eddy, Orla and Waha) increased a net $19.4 million quarter-to-quarter.  Our Orla gas plant, which commenced commercial operations during the second quarter of 2018, contributed gross operating margin of $11.3 million and fee-based natural gas processing volumes of 198 MMcf/d for the quarter.  Gross operating margin from our Waha gas plant increased $10.8 million quarter-to-quarter and fee-based natural gas processing volumes increased 111 MMcf/d quarter-to-quarter primarily due to our acquisition of the remaining 50% equity interest in the Delaware Basin joint venture in March 2018.  Gross operating margin from our South Eddy gas plant decreased $2.7 million quarter-to-quarter primarily due to lower natural gas processing volumes of 62 MMcf/d.

Gross operating margin from our natural gas processing plants in Louisiana and Mississippi increased $10.1 million quarter-to-quarter primarily due to higher equity NGL production volumes of 15 MBPD, which accounted for a $7.5 million increase, and higher average processing margins, which accounted for an additional $3.6 million increase.   Fee-based natural gas processing volumes for these plants decreased 21 MMcf/d quarter-to-quarter.

Nine Months Ended September 30, 20182019 Compared to Nine Months Ended September 30, 20172018.  Gross operating margin from natural gas processing and related NGL marketing activities for the nine months ended September 30, 2018 increased $269.2 2019 decreased $125.7 million when compared to the nine months ended September 30, 2017.

2018.  Gross operating margin from our Meeker, Pioneer and ChacoRockies natural gas processing plants increased $133.3 decreased a combined $111.2 million period-to-period primarily due to higherlower average processing margins (including the impact of hedging activities)., which accounted for an $80.7 million decrease, lower processing and other fees, which accounted for a $20.0 million decrease, and lower equity NGL sales volumes, which accounted for an additional $9.9 million decrease.  On a combined basis, for these plants, fee-based natural gas processing volumes at these plants increased 117 95 MMcf/d and equity NGL production volumes decreased 16 MBPD period-to-period.

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

Gross operating margin from our Louisiana and Mississippi natural gas processing plants increaseddecreased a net $41.4$16.4 million period-to-period primarily due to higherlower average processing margins (including the impact of hedging activities), which accounted for a $52.8$26.5 million decrease, partially offset by higher fee-based natural gas processing volumes, which accounted for an $8.0 million increase.  Net to our interest, fee-based natural gas processing volumes and equity NGL production volumes increased 239 MMcf/d and 7 MBPD, respectively, period-to-period.

Gross operating margin from our Permian Basin natural gas processing plants increased $21.6 million period-to-period primarily due to higher fee-based natural gas processing volumes, which accounted for a $46.3 million increase, partially offset by lower equity NGL production volumes of 10 MBPD, which accounted for a $9.4 million decrease.  Fee-based natural gas processing volumes for these plants decreased 112 MMcf/d period-to-period.

Gross operating margin from our natural gas processing plants in the Permian Basin increased $36.8 million period-to-period.  Gross operating margin from our Waha gas plant increased $20.3 million period-to-period and fee-based natural gas processing volumes increased 72 MMcf/d period-to-period.  In addition, our Orla gas plant contributed $14.9 million of gross operating margin and 167 MMcf/d of fee-based processing volumes during the period that it was in service.  Gross operating margin from our South Eddy gas plant increased a net $1.6 million period-to-period primarily due to higher average processing fees, which accounted for a $9.5$17.5 million increase, partially offset by lower fee-baseddecrease.  Fee-based processing volumes at our Permian Basin natural gas processing plants increased 361 MMcf/d period-to-period primarily due to the start-up of 40 MMcf/d,our Orla natural gas processing facility.  The first, second and third processing trains at this facility commenced operations in May 2018, October 2018 and July 2019, respectively.

NGL pipelines, storage and terminals
Third Quarter of 2019 Compared to Third Quarter of 2018.  Gross operating margin from our NGL pipelines, storage and terminal assets during the third quarter of 2019 increased $79.9 million when compared to the third quarter of 2018. The Shin Oak pipeline generated $37.7 million of gross operating margin for the third quarter of 2019 on direct tariff movements of 113 MBPD (net to our interest) and 152 MBPD of offload volumes from affiliate pipelines.  Gross operating margin from our underground storage facilities at the Mont Belvieu hub increased $25.8 million quarter-to-quarter primarily due to higher throughput and handling fees, which accounted for a $5.0$19.4 million decrease.increase, and higher storage fees, which accounted for an additional $5.9 million increase.


Gross operating margin from our natural gas processing plants in Louisiana and MississippiAegis Pipeline increased a net $7.7 million period-to-period primarily due to a higher equity NGL production volumes of 5 MBPD, which accounted for a $7.6 million increase, higher average processing margins (including the impact of hedging activities), which accounted for a $6.1 million increase, partially offset by a decrease in fee-based natural gas processing volumes and average processing fees, which accounted for decreases of $2.6 million and $2.5 million, respectively.  Fee-based natural gas processing volumes decreased 119 MMcf/d period-to-period.

Gross operating margin from our NGL marketing activities increased a net $48.0 million period-to-period primarily due to higher average sales margins, which accounted for a $226.0 million increase, partially offset by a $179.0 million decrease due to lower sales volumes.  Results from marketing strategies that optimize our transportation and plant assets increased a combined $142.1 million period-to-period, partially offset by a $102.3 million decrease in earnings related to the optimization of our storage and export assets.

NGL pipelines, storage and terminals
Third Quarter of 2018 Compared to Third Quarter of 2017.  Gross operating margin from NGL pipelines, storage and terminal assets for the third quarter of 2018 increased a net $78.1 million when compared to the third quarter of 2017.

On a combined basis, gross operating margin from our Seminole, Chaparral and affiliated pipelines increased a net $20.4$15.8 million quarter-to-quarter primarily due to higher transportation volumes of 162 MBPD, which accounted for a $27.6 million increase, higher average transportation fees, which accounted for a $6.3 million increase, partially offset by higher offloading, power and other operating costs of $13.6 million.

Gross operating margin at EHT increased $12.2 million quarter-to-quarter primarily due to a 107 MBPD increase in LPG volumes.  Gross operating margin at our Morgan’s Point Ethane Export Terminal increased a net $4.7 million quarter-to-quarter primarily due to an increase in loading volumes of 44 MBPD, which accounted for a $7.7 million increase, partially offset by an increase in ad valorem taxes and other operating costs, which accounted for a $2.4 million decrease.143 MBPD.  Gross operating margin from theour Dixie Pipeline and related Channel Pipelineterminals increased $5.5 million quarter-to-quarter primarily due to a 162 MBPD increase in transportation volumes.

Gross operating margin from ATEX increased $11.5combined $7.9 million quarter-to-quarter primarily due to higher transportation volumes of 1640 MBPD quarter-to-quarter.resulting from a capacity expansion project.  Gross operating margin from our Mid-America Pipeline System and related terminalsEHT increased a net $8.8$5.2 million quarter-to-quarter primarily due to higher transportationexport volumes, of 83 MBPD, which accounted for an $11.7 million increase, and higher exchange and product blending revenues, which accounted for a $5.8 million increase, partially offset by higher offloading, storage and other operating costs of $8.7 million.  increased 21 MBPD.

Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018.Gross operating margin from our South Texas NGL Pipeline Systempipelines, storage and terminal assets during the nine months ended September 30, 2019 increased a net $5.3$251.2 million quarter-to-quarterwhen compared to the nine months ended September 30, 2018.  Gross operating margin from our Mont Belvieu storage facility increased $92.0 million period-to-period primarily due to higher capacity reservation revenues, which accounted for a $10.1 million increase, partially offset by a decrease in average transportationthroughput and handling fees, which accounted for a $5.6$67.7 million decrease.  Grossincrease, and higher storage fees, which accounted for an additional $22.2 million increase.  The Shin Oak pipeline contributed $80.8 million of gross operating margin from our equity investment in the Texas Express Pipeline increased $3.9 million quarter-to-quarter primarily due to higher2019 period on year-to-date transportation volumes of 22111 MBPD of direct tariff movements (net to our interest). and 145 MBPD of offload volumes from affiliate pipelines.


Gross operating margin from our underground storage complexes in Mont Belvieu and South Louisiana increased a combined $10.2 million quarter-to-quarter primarily due to higher throughput volumes.
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Gross operating margin from our Dixie Pipeline and related terminals decreased $4.0increased a combined $22.8 million quarter-to-quarterperiod-to-period primarily due to higherlower maintenance and other operating costs, which accounted for a $2.8an $11.6 million decrease,increase, and lowerhigher transportation volumes of 1425 MBPD, which accounted for an additional $1.1$8.8 million decrease.

Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017.  Gross operating margin from NGL pipelines, storage and terminal assets for the nine months ended September 30, 2018 increased a net $161.6 million when compared to the nine months ended September 30, 2017.

increase.  Gross operating margin from our Seminole, Chaparral and affiliated pipelinesAegis Pipeline increased a combined net $67.6$20.8 million period-to-period primarily due to higher transportation volumes of 10850 MBPD.  Gross operating margin from our South Louisiana NGL Pipeline System increased $12.6 million period-to-period primarily due to a 62 MBPD increase in transportation volumes.

Gross operating margin from LPG activities at EHT increased $11.1 million period-to-period primarily due to higher export volumes of 12 MBPD, which accounted for a $50.5$4.6 million increase, and higher average transportationloading fees, which accounted for an additional $33.6$3.9 million increase, partially offset by higher offloading, power and other operating costs of $16.3 million.   Gross operating margin from our equity investment in the Texas Express Pipeline increased $10.6 million period-to-period primarily due to higher transportation volumes of 15 MBPD (net to our interest).increase.


Gross operating margin from our underground storage complexes in Mont Belvieu and South Louisiana increased a combined $23.5 million period-to-period primarily due to higher throughput volumes.  Gross operating margin from our Morgan’s Point Ethane Export Terminal increased a net $32.3 million period-to-period primarily due to higher loading volumes of 73 MBPD.  Likewise, gross operating margin from our Channel Pipeline increased $7.2 million period-to-period primarily due to higher transportation volumes of 99 MBPD, which in turn is attributable to ethane exports.

Gross operating margin from ATEX increased $43.0 million period-to-period primarily due to higher transportation volumes, which increased 28 MBPD period-to-period. Gross operating margin from our Dixie Pipeline and related terminals decreased $14.3 million period-to-period primarily due to higher maintenance costs.

NGL fractionation
Third Quarter of 20182019 Compared to Third Quarter of 2017.  2018.  Gross operating margin from NGL fractionation for the third quarter of 2018 increased $20.52019 decreased $25.9 million when compared to the third quarter of 2017.2018.  Gross operating margin from our Mont Belvieu NGL fractionation complex increased $19.6decreased $19.1 million quarter-to-quarter primarily due to lower product blending revenues, which accounted for a $15.8 million decrease, and higher fractionationutility and other operating costs, which accounted for an additional $2.7 million decrease.  Fractionation volumes of 139 increased 13 MBPD (net to our interest).   We placed quarter-to-quarter.  Gross operating margin from our ninthSouth Texas NGL fractionators decreased $4.1 million quarter-to-quarter primarily due to major maintenance activities completed at our Shoup fractionator into service in May 2018, which accounted for 93 during the third quarter of 2019.  NGL fractionation volumes at our South Texas NGL fractionators decreased 5 MBPD of the quarter-to-quarter increase in volumes.quarter-to-quarter.


Nine Months Ended September 30, 20182019 Compared to Nine Months Ended September 30, 20172018.Gross operating margin from NGL fractionation for the nine months ended September 30, 2018 increased $44.12019 decreased $53.4 million when compared to the nine months ended September 30, 2017.  2018.  Gross operating margin at our Hobbs NGL fractionator decreased $26.0 million period-to-period primarily due to the costs of major maintenance activities completed in February 2019, which accounted for a $12.8 million decrease, lower product blending revenues, which accounted for a $7.6 million decrease, and lower fractionation volumes, which accounted for an additional $5.6 million decrease.  NGL fractionation volumes at Hobbs decreased 11 MBPD period-to-period.

Gross operating margin from our Mont Belvieu NGL fractionators increased $31.3fractionation complex decreased $12.0 million period-to-period primarily due to higher fractionation volumes of 111 MBPD (net to our interest) resulting from the start-up of our ninth NGL fractionator.  Gross operating margin from our Hobbs NGL fractionator increased $10.7 million period-to-period primarily due to higherlower product blending revenues, which accounted for a $4.9$33.2 million increase,decrease, and lower maintenance and otherhigher operating costs, which accounted for an additional $3.6$17.4 million decrease, partially offset by higher fractionation volumes, which accounted for a $43.5 million increase.  Fractionation volumes increased 29 MBPD (net to our interest) period-to-period primarily due to the start-up of our ninth NGL fractionator in May 2018.


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


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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,
 
  2018  2017  2018  2017 
Segment gross operating margin:            
Midland-to-ECHO Pipeline and related business activities,
   excluding associated non-cash mark-to-market results
 $94.8  $(0.1) $242.7  $(0.1)
Mark-to-market gain (loss) attributable to the Midland-to-ECHO
   Pipeline
  186.7   --   (237.3)  -- 
Total Midland-to-ECHO Pipeline and related business activities $281.5  $(0.1) $5.4  $(0.1)
Other crude oil pipelines, terminals and related marketing results  312.7   190.5   861.6   691.8 
Total $594.2  $190.4  $867.0  $691.7 
                 
Selected volumetric data:                
Crude oil pipeline transportation volumes (MBPD)  1,961   1,458   2,015   1,430 
Crude oil marine terminal volumes (MBPD)  632   452   690   472 
  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2019  2018  2019  2018 
Midland-to-ECHO pipeline network:            
   Midland-to-ECHO 1 pipeline and related business activities,
      excluding associated non-cash mark-to-market results
 $89.3  $94.8  $298.6  $242.7 
   Non-cash mark-to-market gain (loss) attributable to the
      Midland-to-ECHO 1 pipeline
  10.0   186.7   91.2   (237.3)
   Total Midland-to-ECHO 1 pipeline and related business activities  99.3   281.5   389.8   5.4 
   Midland-to-ECHO 2 pipeline  27.0   –   72.5   – 
   Total Midland-to-ECHO pipeline network  126.3   281.5   462.3   5.4 
Other crude oil pipelines, terminals and related marketing results  369.9   312.7   1,209.4   861.6 
Segment gross operating margin $496.2  $594.2  $1,671.7  $867.0 
                 
Selected volumetric data:                
Crude oil pipeline transportation volumes (MBPD)  2,321   1,914   2,315   1,971 
Crude oil marine terminal volumes (MBPD)  987   632   972   690 


Third Quarter of 2019 Compared to Third Quarter of 2018.  Gross operating margin from our Crude Oil Pipelines & Services segment for the third quarter of 2019 decreased $98.0 million when compared to the third quarter of 2018.
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Midland-to-ECHO Pipeline and related business activities
Gross operating margin from our Midland-to-ECHO Pipeline1 pipeline and related business activities wasdecreased $182.2 million quarter-to-quarter primarily due to changes in non-cash mark-to-market earnings, which were a combined $281.5$10.0 million forgain in the third quarter of 2018 and $5.42019 compared to a $186.7 million forgain in the nine months ended September 30,third quarter of 2018. Transportation volumes for the Midland-to-ECHO Pipeline, which entered limited service in November 2017 and full service in April 2018, averaged 453 1 pipeline increased 36 MBPD and 429 MBPD during the three and nine months ended September 30, 2018, respectivelyquarter-to-quarter (net to our interest).

Gross operating margin for this business forfrom our Midland-to-ECHO 2 pipeline, which commenced full commercial service during the three and nine months ended September 30, 2018 reflects a non-cash mark-to-market gainsecond quarter of $186.72019, was $27.0 million and losson transportation volumes of $237.3 million, respectively,211 MBPD.

Mark-to-market earnings attributable to the Midland-to-ECHO 1 pipeline are associated with the hedging of crude oil commoditymarket price differentials (basis spreads) between the Midland and Houston area markets.markets based on the pipeline’s capacity available to us during the hedged periods. These hedges which were primarily entered into throughout 2017, serveserved to lock in a positive per barrel margin on our anticipated purchases of crude oil at Midland and subsequent anticipated sales to customers in the Houston areaarea.  The mark-to-market gain for periods extending predominantly into 2019 and minimally through 2020. At September 30,the third quarter of 2018 these hedges representedreflected a weighted average of approximately 32% of the pipeline’s expected uncommitted capacity through 2020 at an average positive margin of $2.66 per barrel. The year-to-date mark-to-market loss of $237.3 million reflects a widening ofdecrease in the basis spread between the Midland and Houston markets from June 30, 2018 to September 30, 2018 to an average of $13.13 $13.13 per barrel through 2020 relative to our average hedged amount of $2.66 $2.66 per barrel across these same periods as ofthrough 2020.  At September 30, 2018. The mark-to-market gain recognized for the third quarter2019, there were a limited number of 2018 reflects the reversal of previously recognized mark-to-market losses for these hedges upon cash settlement of the underlying instruments as well as a narrowing of the basis spreads between the Midland and Houston markets during the quarter.

Basis swaps, in all but very limited circumstances, do not qualify for cash flow hedge accounting despite being highly effective at hedging the price risk inherent in the underlying physical transactions.  The volume hedged through 2020 varies from quarter-to-quarter and year-to-year, however the hedge levels generally correspond to pipeline capacity currently expected to be available to us during the first three years of the pipeline’s operations as customer commitment volumes ramp up to peak levels.

If the basis spreads underlying these hedges widen from the levels at September 30, 2018, we would be exposed to additional temporary non-cash mark-to-market losses.  Conversely, if basis spreads narrow in the future reverting back towards or below the average $2.66 per barrel spread we have locked in at September 30, 2018, then we would recognize temporary non-cash mark-to-market gains in future periods.  When the forecasted physical receipts and deliveries of crude oil ultimately occur in the future, we will realize a physical gross margin at then prevailing commodity price spreads; however the realized settlement of the associated financial hedges would convert that physical margin to the average $2.66 per barrel spread of the financial hedges.  At that time, the unrealized mark-to-market loss recognized for the nine months ended September 30, 2018 and in future periods until the physical deliveries occur will be reversed, thus eliminating their impact to cumulative earnings recognized over the entire life-to-date period of the hedge.

The basis spread between the Midland and Houston markets continues to fluctuate.  We also have uncommitted capacity on the pipeline that could provide us with potential upside to widening or downside to narrowing market spreads.  outstanding. For information regarding the impact of these spreads on our crude oil marketing hedging portfolio, see Part I, Item 3, Quantitative and Qualitative Disclosures about Market Risk.  For general information regarding our derivative instruments andcommodity hedging activities, see Note 1413 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.


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

Gross operating margin from our equity investment in the Seaway Pipeline increased $25.0 million quarter-to-quarter primarily due to higher transportation volumes, which accounted for a $27.4 million increase, and higher transportation fees, which accounted for an additional $12.5 million increase, partially offset by higher operating costs, which accounted for a $10.6 million decrease. Transportation volumes on the Seaway Pipeline increased 130 MBPD quarter-to-quarter (net to our interest) primarily due to an expansion of the Longhaul System that was completed in the first quarter of 2019.

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Lastly, gross operating margin from crude oil activities at EHT increased $32.4 million quarter-to-quarter primarily due to higher net export volumes of 252 MBPD.

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

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

Other crude oil pipelines, terminals and related marketing results
Third Quarter of 2018 Comparedincreased 47 MBPD period-to-period (net to Third Quarter of 2017.  our interest). Gross operating margin from our other crude oil pipelines, terminals and related marketing activities for the third quarterMidland-to-ECHO 2 pipeline was $72.5 million on transportation volumes of 2018 increased a net $122.2 million when compared to the third quarter of 2017.195 MBPD.


Gross operating margin from other crude oil exportmarketing activities at EHT increased $19.9$115.6 million quarter-to-quarterperiod-to-period primarily due to an increase in loading volumes of 206 MBPD,higher average sales margins, which accounted for a $10.7an $82.4 million increase, and higher deficiency fee revenues,non-cash mark-to-market earnings, which accounted for an additional $8.8$34.0 million increase.

  These marketing activities benefitted from higher market price differentials for crude oil between the Permian Basin region, Cushing hub and Gulf Coast markets.  Gross operating margin from our West Texas System and equity investment in the Eagle Ford Crude Oil Pipeline System increased a combined $10.6$68.2 million quarter-to-quarterperiod-to-period primarily due to higher transportation volumes which increased 92of 70 MBPD (net to our interest).  Gross operating margin from our EFS Midstream System increased $7.2 million quarter-to-quarter primarily due to higher deficiency fee revenues, which accounted for a $4.5 million increase, and lower maintenance and other operating costs, which accounted for an additional $2.5 million increase.

Gross operating margin fromat our South Texas Crude Oil Pipeline System increased a net $6.6$14.3 million quarter-to-quarterperiod-to-period primarily due to higher firm capacity reservation revenues attributable todeficiency fees.  Transportation volumes on the Midland-to-ECHOSouth Texas Crude Oil Pipeline which accounted for $12.5 million of the increase, partially offset by lower average transportation fees, which accounted for an $8.3 million decrease.  Crude oil transportation volumes for this system increased 28System decreased 11 MBPD quarter-to-quarter.period-to-period.


Gross operating margin from our equity investment in the Seaway Pipeline decreased $5.3 million quarter-to-quarter primarily due to a decrease in long-haul transportation revenues attributable to lower transportation volumes.  Overall, transportation volumes on the Seaway Pipeline decreased 72 MBPD quarter-to-quarter (net to our interest).

Gross operating margin from our related crude oil marketing activities increased $83.7 million quarter-to-quarter primarily due to higher average sales margins, which accounted for a $46.4 million increase, and non-cash mark-to-market gains recognized in the third quarter of 2018 compared to non-cash mark-to-market losses recognized in the third quarter of 2017, which accounted for an additional $35.6 million increase. The mark-to-market gains recognized by this business in the third quarter of 2018 were related to the narrowing of crude oil commodity price differentials between the Midland, Texas and Cushing, Oklahoma markets.

Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017.  Gross operating margin from our other crude oil pipelines, terminals and related marketing activities for the nine months ended September 30, 2018 increased a net $169.8 million when compared to the nine months ended September 30, 2017.

Gross operating margin from our South Texas Crude Oil Pipeline System increased a net $67.8 million period-to-period primarily due to higher firm capacity reservation fees attributable to the Midland-to-ECHO Pipeline, which accounted for $48.6 million of the increase, higher transportation volumes, which accounted for an additional $33.2 million increase, partially offset by lower average transportation fees, which accounted for a $25.1 million decrease.  Crude oil transportation volumes for this system increased 42 MBPD period-to-period.

Gross operating margin from crude oil export activities at EHT increased $42.2 million period-to-period primarily due to higher net loading volumes, which increased 180 MBPD period-to-period.  Gross operating margin from our Midland, Texas and ECHO terminals increased a combined $21.1 million period-to-period primarily due to higher throughput volumes attributable to movements on the Midland-to-ECHO Pipeline.

Gross operating margin from our EFS Midstream System increased $18.0 million period-to-period primarily due to higher deficiency fee revenues, which accounted for a $12.9 million increase, and lower maintenance and other operating costs, which accounted for an additional $4.8 million increase. Gross operating margin from our West Texas System and equity investment in the Eagle Ford Crude Oil Pipeline System increased a combined $20.0 million period-to-period primarily due to higher transportation volumes, which increased 83 MBPD (net to our interest).

Grossaccounted for a $47.7 million increase, and higher transportation fees, which accounted for an additional $46.4 million increase, partially offset by higher operating margin from our equity investment incosts, which accounted for a $29.6 million decrease. Transportation volumes on the Seaway Pipeline decreased $18.6 million period-to-period primarily due to lower long-haul transportation revenues attributable to an increase in walk-up shipper volumes, which are charged a lower tariff.  Transportation volumes for Seaway increased 2575 MBPD period-to-period (net to our interest). Volumes at Seaway’s Texas City and Freeport marine terminals decreased a combined 36 MBPD (net to our interest) period-to-period.


71

GrossLastly, gross operating margin from our related crude oil marketing activities at EHT increased a net $16.7$65.4 million period-to-period primarily due to higher average sales margins, which accounted for a $57.9 million increase, partially offset by non-cash mark-to-market losses recognized for the nine months ended September 30, 2018 compared to non-cash mark-to-market gains recognized for the same period in 2017, which accounted for a $42.8 million decrease.  The mark-to-market losses recognized by this business in 2018 are related to the wideningnet export volumes of crude oil commodity prices differentials between the Midland, Texas and Cushing, Oklahoma markets relative to our positions outstanding during the period.258 MBPD.



Natural Gas Pipelines & Services


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


 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
 2018  2017  2018  2017  2019  2018  2019  2018 
Segment gross operating margin $216.9  $170.7  $628.2  $536.0  $258.5  $216.9  $824.6  $628.2 
                                
Selected volumetric data:                                
Natural gas pipeline transportation volumes (BBtus/d)  13,939   12,376   13,544   12,084   14,474   14,040   14,341   13,594 


Third Quarter of 20182019 Compared to Third Quarter of 2017.  2018. Gross operating margin from our Natural Gas Pipelines & Services segment for the third quarter of 20182019 increased a net $46.2$41.6 million when compared to the third quarter of 2017.2018.

Gross operating margin from our Texas Intrastate System increased $26.3 million quarter-to-quarter primarily due to higher firm capacity reservation and other fees.  Transportation volumes on our Texas Intrastate System increased 183 BBtus/d quarter-to-quarter.  Gross operating margin from our Permian Basin Gathering System increased a net $8.5 million quarter-to-quarter primarily due to a 309 BBtus/d increase in natural gas gathering volumes, which accounted for a $6.6 million increase, and higher condensate sales volumes, which accounted for an additional $4.9 million increase, partially offset by higher maintenance costs and other operating costs, which accounted for a $4.1 million decrease.  Gross operating margin from our BTA Gathering System in East Texas increased $1.7 million quarter-to-quarter primarily due to an increase in natural gas gathering volumes of 147 BBtus/d.

With respect to our Louisiana assets, gross operating margin from our Haynesville Gathering System increased $5.4 million quarter-to-quarter primarily due to higher natural gas gathering volumes of 287 BBtus/d, which accounted for a $2.7 million increase, and higher treating and other fee revenues, which accounted for an additional $2.3 million increase.  Gross operating margin from our Acadian Gas System increased $2.4 million quarter-to-quarter primarily due to an increase in firm capacity reservation revenues on the Haynesville Extension pipeline. Transportation volumes for the Acadian Gas System increased 563 BBtus/d quarter-to-quarter, with the Haynesville Extension pipeline accounting for 479 BBtus/d of the increase.

Gross operating margin from our San Juan Gathering System increased $3.0 million quarter-to-quarter primarily due to lower operating costs.  Gross operating margin from our Jonah Gathering System decreased $5.1 million quarter-to-quarter primarily due to higher maintenance and other operating costs.


Gross operating margin from our natural gas marketing activities increased $3.1$36.1 million quarter-to-quarter primarily due to higher mark-to-market earnings,average sales margins that benefited from regional natural gas price spreads across Texas.
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Gross operating margin from our Acadian Gas System increased $7.4 million quarter-to-quarter primarily due to a $10.4 million benefit recognized in the third quarter of 2019 in connection with proceeds received from a legal settlement. Gross operating margin from our Permian Basin Gathering System increased $7.0 million quarter-to-quarter primarily due to higher gathering volumes, which accounted for a $5.9$3.4 million increase, partially offset by lower averageand higher condensate sales, margins, which accounted for a $3.0an additional $3.3 million decrease.increase.  Gathering volumes for the Permian Basin system increased 315 BBtus/d quarter-to-quarter. Pipeline volumes for the remaining natural gas pipeline systems increased 138 BBtus/d quarter-to-quarter.


Nine Months Ended September 30, 20182019 Compared to Nine Months Ended September 30, 20172018.Gross operating margin from our Natural Gas Pipelines & Services segment for the nine months ended September 30, 20182019 increased a net $92.2$196.4 million when compared to the nine months ended September 30, 2017.2018.  Gross operating margin from our natural gas marketing activities increased $129.1 million period-to-period primarily due to higher average sales margins attributable to regional natural gas price spreads.



Gross operating margin from our Texas Intrastate System increased a net $45.4$57.3 million period-to-period primarily due to higher firm capacity reservation and other fees, which accounted for a $53.7 million increase, partially offset by higher maintenance and other operating costs, which accounted for a $12.4 million decrease.fees.  Transportation volumes on our Texas Intrastate System increased 98191 BBtus/d period-to-period. d.  Gross operating margin from our Acadian Gas System increased $19.9 million period-to-period primarily due to the aforementioned legal settlement, which accounted for $10.4 million of the increase, and higher capacity reservation fees on the Haynesville Extension, which accounted for an additional $9.7 million increase.

Gross operating margin from our Permian Basin Gathering System increased $18.0 million period-to-period primarily due to a 172 BBtus/d increase in natural gas gathering volumes, which accounted for a $10.9 million increase, and higher condensate sales volumes, which accounted for an additional $8.4 million increase.  Gross operating margin from our BTA Gathering System, which we acquired in April 2017, increased $9.3$13.8 million period-to-period primarily due to an increase in gathering volumes of 102 BBtus/d.

Gross operating margin from our Haynesville Gathering System increased a net $16.5 million period-to-period primarily due to higher gathering and other fee revenues,condensate sales, which accounted for an $11.2 million increase, and higher gathering volumes, of 304 BBtus/d, which accounted for an $8.4additional $10.9 million increase, partially offset by higher maintenance and other operating costs, which accounted for a $3.1an $8.9 million decrease.  Natural gas gathering volumes on the Permian Basin Gathering System increased 381 BBtus/d. Gross operating margin from our Acadian GasHaynesville Gathering System decreased a net $13.4increased $12.3 million period-to-period primarily due to $17.4 million of proceeds receiveda 237 BBtus/d increase in connection with a legal settlement in the second quarter of 2017, partially offset by higher average firm capacity reservation fees on the Haynesville Extension pipeline, which accounted for a $6.8 million increase. Transportation volumes for the Acadian Gas System increased 568 BBtus/d period-to-period, with the Haynesville Extension pipeline accounting for 469 BBtus/d of the increase.

gathering volumes.  Gross operating margin from our San Juan Gathering System increased $8.1decreased $15.6 million period-to-period primarily due to
higher condensate sales prices.  Gross operating margin from our Jonah Gathering System decreased $0.6 million period-to-period primarily due to higher maintenance and other operating expenses, which accounted for a $6.7 million105 BBtus/d decrease partially offset by a 110 BBtus/d increase in natural gas gathering volumes, which accounted for a $6.1an $8.2 million increase.decrease, and lower condensate sales, which accounted for an additional $4.0 million decrease.


Gross operating margin from our natural gas marketing activities increased $5.7 million period-to-period primarily due to higher mark-to-market earnings.


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,
 
 2018  2017  2018  2017  2019  2018  2019  2018 
Segment gross operating margin:                        
Propylene production and related activities $94.3  $44.5  $350.2  $175.1 
Butane isomerization and related operations  29.4   20.6   80.2   49.7 
Octane enhancement and related plant operations  40.3   35.1   122.2   92.6 
Propylene production and related marketing activities $130.8  $94.3  $366.8  $350.2 
Butane isomerization and related DIB operations  15.5   29.4   60.7   80.2 
Octane enhancement and related operations  54.6   40.3   131.4   122.2 
Refined products pipelines and related activities  78.1   67.6   231.1   213.8   74.4   78.1   241.6   231.1 
Marine transportation and other  7.3   4.6   19.4   11.4   13.1   7.3   35.4   19.4 
Total $249.4  $172.4  $803.1  $542.6  $288.4  $249.4  $835.9  $803.1 
                                
Selected volumetric data:                                
Propylene plant production volumes (MBPD)  93   78   97   80 
Propylene production volumes (MBPD)  105   93   99   97 
Butane isomerization volumes (MBPD)  105   110   111   106   109   105   110   111 
Standalone DIB processing volumes (MBPD)  100   82   89   82   103   100   97   89 
Octane additive and related plant production volumes (MBPD)  29   24   28   25   28   29   28   28 
Pipeline transportation volumes, primarily refined products and
 petrochemicals (MBPD)
  796   778   806   801   747   796   742   806 
Refined products and petrochemical marine terminal volumes
 (MBPD)
  289   359   336   410   297   289   344   336 



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Propylene production and related marketing activities
Third Quarter of 20182019 Compared to Third Quarter of 2017.  2018.  Gross operating margin from propylene production and related marketing activities for the third quarter of 20182019 increased $49.8$36.5 million when compared to the third quarter of 2017.2018.  Gross operating margin from our Mont Belvieu propylene fractionation plantssplitters increased $22.2$20.6 million quarter-to-quarter primarily due to higher average propylene sales margins.

volumes.  Gross operating margin from our PDH facility which completed its commissioning (or start up) phase and began full commercial operations in the second quarter of 2018, increased $25.0$17.2 million for the third quarter of 2018 when compared to the third quarter of 2017 on plant production volumes, including by-products, of 15 MBPD.  Production rates at the PDH facility were 11 MBPD lower than those achieved during the second quarter of 2018 due to an extended outage for planned maintenance in September 2018.   As a result of this outage, gross operating margin from our PDH facility for the third quarter of 2018 decreased $30.9 million when compared to the second quarter of 2018 primarily due to the lowerhigher propylene and associated by-product sales volumes.  Propylene production volumes.  Thevolumes from our splitter units and PDH facility resumed service in October 2018.increased a combined 12 MBPD quarter-to-quarter.


Nine Months Ended September 30, 20182019 Compared to Nine Months Ended September 30, 20172018.Gross operating margin from propylene production and related marketing activities for the nine months ended September 30, 20182019 increased $175.1$16.6 million when compared to the nine months ended September 30, 2017.2018.  Gross operating margin from our PDH facility, was $67.1which commenced commercial operations in April 2018, increased $39.0 million for the nine months ended September 30, 2018.  Propyleneperiod-to-period primarily due to higher propylene and associated by-product sales volumes.  Plant production volumes for the PDH facility, including by-products, averaged 19 MBPD for the nine months ended September 30, 2018, which includes volumes for the first quarter of 2018 when the facility was still in its commissioning phase.  by-products, increased 5 MBPD period-to-period.  Gross operating margin from our Mont Belvieu propylene fractionation plants increased $79.9splitters decreased $23.9 million period-to-period primarily due to higherlower average propylene sales margins.fractionation fees, which accounted for a $14.4 million decrease, and lower propylene production volumes, which accounted for an additional $8.0 million decrease.  Propylene production volumes from our splitter units decreased 3 MBPD (net to our interest).


Butane isomerization and related DIB operations
Third Quarter of 20182019 Compared to Third Quarter of 2017.  2018.  Gross operating margin from butane isomerization and deisobutanizer (“DIB”) operations for the third quarter of 2018 increased $8.82019 decreased $13.9 million when compared to the third quarter of 20172018 primarily due to higherlower average by-product sales prices, which accounted for a $4.2$6.5 million increase, higher DIB processing fees, which accounted for a $1.6 million increase,decrease, and higher DIB processing volumes of 18 MBPD,maintenance and other operating costs at our isomerization facility, which accounted for an additional $1.2$3.1 million increase.decrease.


Nine Months Ended September 30, 20182019 Compared to Nine Months Ended September 30, 20172018.Gross operating margin from butane isomerization and DIB operations for the nine months ended September 30, 2018 increased $30.52019 decreased $19.5 million when compared to the nine months ended September 30, 2017. The increase in gross operating margin period-to-period is2018 primarily due to higherlower average by-product sales prices, which accounted for a $16.5$15.2 million increase, higher production and sales volumes, which accounted for an $8.7 million increase,decrease, and higher DIB processing fees,maintenance and other operating costs, which accounted for an additional $4.5$6.3 million increase.decrease.


Octane enhancement and related operations
Third Quarter of 20182019 Compared to Third Quarter of 2017.  2018.  Gross operating margin from our octane enhancement facility and high purity isobutylene plant for the third quarter of 20182019 increased a combined $5.2$14.3 million when compared to the third quarter of 20172018 primarily due to higher average sales volumes, which accounted for a $6.9 million increase, partially offset by higher maintenance and other operating costs, which accounted for a $2.5 million decrease.margins.


Nine Months Ended September 30, 20182019 Compared to Nine Months Ended September 30, 20172018.Gross operating margin from our octane enhancement facility and high purity isobutylene plant for the nine months ended September 30, 20182019 increased a combined $29.6$9.2 million when compared to the nine months ended September 30, 20172018 primarily due to higher average sales volumes.margins.


Refined products pipelines and related activities
Third Quarter of 20182019 Compared to Third Quarter of 2017.  2018.  Gross operating margin from refined products pipelines and related marketing activities for the third quarter of 2018 increased $10.52019 decreased $3.7 million when compared to the third quarter of 2017.2018. Gross operating margin from our TE Products Pipeline and related refined products terminals increased $10.4marine terminal located on the Neches River near Beaumont, Texas decreased $4.3 million quarter-to-quarter primarily due to higher average transportation and other fees,operating costs, which accounted for a $7.5$2.1 million increase,decrease, and higher NGL transportation volumes,lower storage fee revenues, which accounted for an additional $5.7$1.4 million increase.  NGL and refined product transportation volumes on our TE Products Pipeline increased a combined 18 MBPD, while petrochemical transportation volumes decreased 12 MBPD quarter-to-quarter.decrease.

Nine Months Ended September 30, 20182019 Compared to Nine Months Ended September 30, 20172018.Gross operating margin from refined products pipelines and related marketing activities for the nine months ended September 30, 20182019 increased $17.3$10.5 million when compared to the nine months ended September 30, 2017.

2018. Gross operating margin from our TE Products Pipeline and related refined products terminalsmarketing activities increased a net $23.4$9.3 million period-to-period primarily due to higher average transportation and other fees, which accounted for a $21.0 increase, and higher NGL transportation volumes, which accounted for an additional $17.6 million increase, partially offset by higher maintenance and other operating costs, which accounted for a $15.2 million decrease.  NGL transportation volumes on our TE Products Pipeline increased 16 MBPD, while refined product and petrochemical transportation volumes decreased a combined 33 MBPD period-to-period.sales margins.


Gross operating margin from our Houston Ship Channel and Beaumont refined products marine terminals decreased a combined $8.9 million period-to-period primarily due to lower storage revenues.
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Marine transportation and other
Third Quarter of 20182019 Compared to Third Quarter of 2017.  2018.  Gross operating margin from marine transportation for the third quarter of 20182019 increased $2.7$5.8 million when compared to the third quarter of 20172018 primarily due to higher marine vessel utilization.barge fees quarter-to-quarter.


Nine Months Ended September 30, 20182019 Compared to Nine Months Ended September 30, 20172018.Gross operating margin from marine transportation and other services for the nine months ended September 30, 20182019 increased $8.0$16.0 million when compared to the nine months ended September 30, 20172018 primarily due to higher marine vessel utilization barge fees period-to-period, which accounted for a $4.1$23.5 million of the increase, and lowerpartially offset by higher operating costs, which accounted for an additional $4.0$8.0 million increase.decrease.



Liquidity and Capital Resources


Based on current market conditions (as of the filing date of this quarterly report), we believe we will have sufficient liquidity, cash flow from operations and access to capital markets to fund our capital expenditures and working capital needs for the reasonably foreseeable future.  At September 30, 2018,2019, we had $3.32 $6.21 billion of consolidated liquidity, which was comprised of $3.29 $5.0 billion of available borrowing capacity under EPO’s revolving credit facilities and $30.2 million$1.21 billion of unrestricted cash on hand. On October 15, 2019, we repaid $800.0 million principal amount of EPO’s Senior Notes LL at their maturity using unrestricted cash.


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


Common Unit Repurchases under 2019 Buyback Program

In January 2019, the Board approved the 2019 Buyback Program, which authorized the partnership to repurchase up to $2.0 billion of EPD’s common units.  For additional information regarding the 2019 Buyback Program, see “Significant Recent Developments” within this Part I, Item 2.  No repurchases of common units were made under this program during the third quarter of 2019.

Consolidated Debt


The following table presents scheduled maturities of our consolidated debt obligations outstanding at September 30, 20182019 for the years indicated (dollars in millions):


     Scheduled Maturities of Debt 
  Total  
Remainder
of 2018
  2019  2020  2021  2022  Thereafter 
Commercial Paper Notes $2,707.6  $2,707.6  $--  $--  $--  $--  $-- 
Senior Notes  20,750.0   --   1,500.0   1,500.0   1,325.0   650.0   15,775.0 
Junior Subordinated Notes  2,670.6   --   --   --   --   --   2,670.6 
Total $26,128.2  $2,707.6  $1,500.0  $1,500.0  $1,325.0  $650.0  $18,445.6 
     Scheduled Maturities of Debt 
  Total  
Remainder
of 2019
  2020  2021  2022  2023  Thereafter 
Principal amount of senior and junior debt obligations at
    September 30, 2019
 $28,196.4  $800.0  $1,500.0  $1,325.0  $1,400.0  $1,250.0  $21,921.4 


Issuance of $3.0 Billion of Senior Notes in October 2018
In October 2018, EPO issued $3.0 billion aggregate principal amount of senior notes comprised of (i) $7502019, we repaid $800.0 million principal amount of senior notes due February 2022 (“EPO’s Senior Notes VV”), (ii) $1.0 billion principal amount of senior notes due October 2028 (“Senior Notes WW”) and (iii) $1.25 billion principal amount of senior notes due February 2049 (“Senior Notes XX”).  Net proceeds from this offering were used by EPO for the temporary repayment of amounts outstanding under its commercial paper program and general company purposes, including for growth capital expenditures.LL at their maturity using unrestricted cash on hand.

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Senior Notes VV were issued at 99.985% of their principal amount and have a fixed-rate interest rate of 3.50% per year.  Senior Notes WW were issued at 99.764% of their principal amount and have a fixed-rate interest rate of 4.15% per year.  Senior Notes XX were issued at 99.390% of their principal amount and have a fixed-rate interest rate of 4.80% per year.  Enterprise Products Partners L.P. has guaranteed the senior notes through an unconditional guarantee on an unsecured and unsubordinated basis.

Issuance of $2.0 Billion of Senior Notes and $700 Million of Junior Subordinated Notes in February 2018Amendment to Multi-Year Revolving Credit Agreement
In February 2018,September 2019, EPO issued $2.7entered into an amendment (the “First Amendment”) to its revolving credit agreement dated September 13, 2017 (the “Multi-Year Revolving Credit Agreement”).  The First Amendment reduces the borrowing capacity under the Multi-Year Revolving Credit Agreement from $4.0 billion aggregateto $3.5 billion (which may be increased by up to $500 million to $4.0 billion at EPO’s election provided certain conditions are met) and extends the maturity date to September 10, 2024, although the maturity date may be extended further at EPO’s request by up to two years, with the consent of required lenders as set forth under the credit agreement.  Borrowings under this revolving credit agreement may be used for working capital, capital expenditures, acquisitions and general company purposes.  There are currently no principal amount of notes comprised of (i) $750 million principal amount of senior notes due February 2021 (“Senior Notes TT”), (ii) $1.25 billion principal amount of senior notes due February 2048 (“Senior Notes UU”) and (iii) $700 million principal amount of junior subordinated notes due February  2078 (“Junior Subordinated Notes F”).  Net proceeds from these offerings were used by EPO for the temporary repayment of amounts outstanding under its commercial paper program, general company purposes, and the redemptionthis revolving credit agreement.

Renewal of all $682.7 million outstanding aggregate principal amount of its Junior Subordinated Notes B.

Senior Notes TT were issued at 99.946% of their principal amount and have a fixed-rate interest rate of 2.80% per year.  Senior Notes UU were issued at 99.865% of their principal amount and have a fixed-rate interest rate of 4.25% per year.  Enterprise Products Partners L.P. has guaranteed the senior notes through an unconditional guarantee on an unsecured and unsubordinated basis.

The Junior Subordinated Notes F are redeemable at EPO’s option, in whole or in part, on one or more occasions, on or after February 15, 2028 at 100% of their principal amount, plus any accrued and unpaid interest thereon, and bear interest at a fixed rate of 5.375% per year through February 14, 2028.  Beginning February 15, 2028, the Junior Subordinated Notes F will bear interest at a floating rate based on a three-month LIBOR plus 2.57%, reset quarterly.  Enterprise Products Partners L.P. has guaranteed the Junior Subordinated Notes F through an unconditional guarantee on an unsecured and subordinated basis.

Redemption of Junior Subordinated Notes
In March 2018, EPO redeemed all of the $682.7 million outstanding aggregate principal amount of its Junior Subordinated Notes B at a price equal to 100% of the principal amount of the notes being redeemed, plus all accrued and unpaid interest thereon to, but not including, the redemption date.  This redemption was funded by EPO’s issuance of senior notes and junior subordinated notes in February 2018.

In August 2018, EPO redeemed all of the $521.1 million outstanding aggregate principal amount of its Junior Subordinated Notes A at a price equal to 100% of the principal amount of the notes being redeemed, plus all accrued and unpaid interest thereon to, but not including, the redemption date.  This redemption was funded by the issuance of short-term notes under EPO’s commercial paper program.

364-Day Revolving Credit Agreement
In September 2018,2019, EPO entered into a 364-Day Revolving Credit Agreement that replaced its prior 364-day credit facility.  The new 364-Day Revolving Credit Agreement matures in September 2019. There are currently no principal amounts outstanding under this revolving credit agreement.

2020. Under the terms of the new 364-Day Revolving Credit Agreement, EPO may borrow up to $2.0$1.5 billion (which may be increased by up to $200 million to $2.2$1.7 billion at EPO’s election, provided certain conditions are met) at a variable interest rate for a term of up to 364 days, subject to the terms and conditions set forth therein.  To the extent that principal amounts are outstanding at the maturity date, EPO may elect to have the entire principal balance then outstanding continued as a non-revolving term loanloans for a period of one additional year, payable in September 2020.2021. Borrowings under this revolving credit agreement may be used for working capital, capital expenditures, acquisitions and general company purposes.

The new 364-Day Revolving Credit Agreement contains customary representations, warranties, covenants (affirmative and negative) and events of default, the occurrence of which would permit the lenders to accelerate the maturity date of any  There are currently no principal amounts borrowedoutstanding under this revolving credit agreement.  The credit agreement also restricts EPO’s ability to pay cash distributions to its parent, Enterprise Products Partners L.P., if an event

Issuance of default (as defined$2.5 Billion of Senior Notes in the credit agreement) has occurred and is continuing at the time such distribution is scheduled to be paid or would result therefrom.July 2019
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EPO’s obligations under the new 364-Day Revolving Credit Agreement are not secured by any collateral; however, they are guaranteed by Enterprise Products Partners L.P.

Increase in Amount Authorized under Commercial Paper Program
In June 2018,July 2019, EPO increased theissued $2.5 billion aggregate principal amount of short-termsenior notes that it could issue (and have outstanding at any time) under its commercial paper program from $2.5comprised of $1.25 billion to $3.0 billion.  The commercial paper program enables us to access typically lower short-term interest rates, which allows us to manage working capital and our overall cost of capital. As a back-stop to the commercial paper program, we intend to maintain a minimum available borrowing capacity under EPO’s Multi-Year Revolving Credit Facility equal to the outstanding aggregate principal amount of EPO’s commercial paper notes.  All commercial papersenior notes due July 2029 (“Senior Notes YY”) and $1.25 billion principal amount of senior notes due January 2050 (“Senior Notes ZZ”).  Net proceeds from this offering were used by EPO for the repayment of debt and for general company purposes, including for growth capital expenditures.

Senior Notes YY were issued under the program are senior unsecured obligationsat 99.955% of EPO that are unconditionally guaranteed by Enterprise Products Partners L.P.their principal amount and have a fixed interest rate of 3.125% per year.  Senior Notes ZZ were issued at 99.792% of their principal amount and have a fixed interest rate of 4.20% per year.


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


Credit Ratings


At November 1, 2018,8, 2019, the investment-grade credit ratings of EPO’s long-term senior unsecured debt securities were BBB+ from Standard and Poor’s, Baa1 from Moody’s and BBB+ from Fitch Ratings.  In addition, the credit ratings of EPO’s short-term senior unsecured debt securities were A-2 from Standard and Poor’s, P-2 from Moody’s and F-2 from Fitch Ratings.

EPO’s credit ratings reflect only the view of a rating agency and should not be interpreted as a recommendation to buy, sell or hold any of our securities.  A credit rating can be revised upward or downward or withdrawn at any time by a rating agency, if it determines that circumstances warrant such a change.  A credit rating from one rating agency should be evaluated independently of credit ratings from other rating agencies.


Issuance of Common Units under DRIP and EUPP


The following table summarizes the issuance ofEPD issued and delivered a combined 2,897,990 common units in the six months ended June 30, 2019 in connection with ourits distribution reinvestment plan (“DRIP”) and employee unit purchase plan (“EUPP”) for.  In total, the nine months ended September 30, 2018 (dollarsnet cash proceeds EPD received from these issuances was $82.2 million.

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In July 2019, EPD announced that, beginning with the quarterly distribution payment paid in millions, number ofAugust 2019, it would use common units issued as shown):

  
Number of
Common
Units Issued
  
Net Cash
Proceeds
Received
 
Three months ended March 31, 2018:      
Common units issued in connection with DRIP and EUPP  6,642,286  $177.0 
Three months ended June 30, 2018:        
Common units issued in connection with DRIP and EUPP  3,234,804   84.0 
Three months ended September 30, 2018:        
Common units issued in connection with DRIP and EUPP  6,600,486   188.4 
   Total common units issued during the nine months ended September 30, 2018  16,477,576  $449.4 

purchased on the open market, rather than issuing new common units, to satisfy its delivery obligations under the DRIP and EUPP
We haveEUPP.  This election is subject to change in future quarters depending on the partnership’s need for equity capital.   In August 2019, a registration statementtotal of 1,410,020 common units were purchased on file with the SECopen market and delivered to participants in connection with our DRIP.  The DRIP provides unitholders of record and beneficial owners of our common units a voluntary means by which they can increase the number of our common units they own by reinvesting the quarterly cash distributions they receive from us into the purchase of additional new common units.  After taking into account the number of common units issued under the DRIP through September 30, 2018, we have the capacity to issue an additional 64,643,166 common units under this plan.

Pursuantand EUPP.  Other than amounts tied to the plan discount available to all participants in the EUPP, the funds used to effect these purchases were sourced entirely from the DRIP privately held affiliates of EPCO purchased $100 million of our common unitsand 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 paid in February 2018 and an additional $106 million of our common units in connection with the distributionexpected to be paid on August 8, 2018.November 12, 2019.

In addition to the DRIP, we have registration statements on file with the SEC in connection with our EUPP.  After taking into account the number of common units issued under the EUPP through September 30, 2018, we have the capacity to issue an additional 5,357,209 common units under this plan.

ATM Program
We have a registration statement on file with the SEC covering the issuance of up to $2.54 billion of our common units in amounts, at prices and on terms to be determined by market conditions and other factors at the time of such offerings in connection with our at-the-market (“ATM”) program.  No sales were made under this program during the nine months ended September 30, 2018.  After taking into account the aggregate sales price of common units sold under the ATM program in periods prior to fiscal 2018, we have the capacity to issue additional common units under the ATM program up to an aggregate sales price of $2.54 billion.

Use of Proceeds
The net cash proceeds we received from the issuance of common units during the nine months ended September 30, 2018 were used to temporarily reduce amounts outstanding under EPO’s commercial paper program and for general company purposes.


For additional information regarding ourEPD’s issuance of common units under the DRIP and relatedEUPP registration statements, see Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

Restricted Cash

Restricted cash represents amounts held in segregated bank accounts by our clearing brokers as margin in support of our commodity derivative instruments portfolio and related physical purchases and sales of natural gas, NGLs, crude oil and refined products.  At September 30, 2018 and December 31, 2017, our restricted cash amounts were $248.9 million and $65.2 million, respectively.

Additional cash may be restricted to maintain our commodity derivative instruments portfolio as prices fluctuate or margin requirements change.  For information regarding our derivative instruments and hedging activities, see Note 14 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.  In addition, see Part I, Item 3, Quantitative and Qualitative Disclosures about Market Risk.

Cash Flows from Operating, Investing and Financing Activities


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,
 
 2018  2017  2019  2018 
Net cash flows provided by operating activities $4,275.3  $2,819.9  $4,826.2  $4,275.3 
Cash used in investing activities  3,182.8   2,303.9   3,372.8   3,182.8 
Cash used in financing activities  883.7   833.9   655.7   883.7 



Net cash flows provided by operating activities are largely dependent on earnings from our consolidated business activities. We operateChanges in energy commodity prices may impact the midstream energy industry, which includes gathering, transporting, processing, fractionating and storingdemand for natural gas, NGLs, crude oil, petrochemical and refined products.  As such, changes in the pricesproducts, which could impact sales of hydrocarbonour products and in the relative price levels among hydrocarbon products could have a material adverse effect ondemand for our financial position, results of operations and cash flows.midstream services. Changes in prices may impact demand for hydrocarbonour products which in turn may impact production, demand and the volumes of products for which we provide services.  In addition, decreases in demandservices may be caused by other factors, including prevailing economic conditions, reduced demand by consumers for the end products made with hydrocarbon products, increased competition, adverse weather conditions and government regulations affecting prices and production levels.  We may also incur credit and price risk to the extent customers do not fulfill their obligations to us in connection with our marketing of natural gas, NGLs, propylene, refined products and/or crude oilactivities 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” under Part I, Item 1A of our 2017the 2018 Form 10-K.

Comparison of Nine Months Ended September 30, 2018 with Nine Months Ended September 30, 2017
The following information highlights significantprimary drivers of the period-to-period fluctuations in our consolidated cash flow amounts:


Operating activities.  activities
Net cash flows provided by operating activities for the nine months ended September 30, 20182019 increased $1.46 billiona net $550.9 million when compared to the same period in 2017.  The increase in cash provided by operating activities was primarily due to:

§a $1.18 billion increase in cash resulting from higher partnership earnings in the nine months ended September 30, 2018 primarily due to:

•
a $612.5 million period-to-period increase resulting from higher year-to-date partnership earnings in 2019 when compared to the same nine month period in 2017 (after2018 (determined by adjusting our $875.0$628.4 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 $250.2 million period-to-period increase in cash primarily due to the timing of cash receipts and payments related to operations; and

§a $29.5 an $85.5 million period-to-period increase in cash distributions received on earnings from unconsolidated affiliates primarily due to our investments in NGLcrude oil pipeline joint ventures.businesses; partially offset by


•
a $147.1 million period-to-period decrease primarily due to the timing of cash receipts and payments related to operations.

For information regarding significant period-to-period changes in our consolidated net income and underlying segment results, see “Results of Operations” within this Part I, Item 2.

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Investing activities.  activities
Cash used forin investing activities infor the nine months ended September 30, 2019 increased a net $190.0 million when compared to the nine months ended September 30, 2018 increased $878.9 million when compared to the same period in 2017 primarily due to:


§•an $886.0
a $297.9 million period-to-period increase in spendingexpenditures for consolidated property, plant and equipment (see “Capital Spending”Investments” within this Part I, Item 2 for additional information regarding our capital spending program)information); andpartially offset by


§•
a $62.3$150.6 million decrease period-to-period increase in investments in unconsolidated affiliates primarily related to our NGL pipeline and crude oil joint ventures; partially offset by

§a $48.1 million period-to-period decrease in net cash used for business combinations.  During the nine months ended September 30,In March 2018, we used $150.6 paid $150.6 million to acquire the remaininga 50% equity interest in Delaware Processing.   For the same period in 2017, we used $191.4 million to acquire the BTA Gathering System and related assets.

79Financing activities

Financing activities.  Cash used in financing activities for the nine months ended September 30, 2018 increased $49.8 2019 decreased $228.0 million when compared to the same period in 2017nine months ended September 30, 2018 primarily due to:


§•
a $427.8net $430.1 million period-to-period decreaseincrease in net cash proceedsinflows from debt.  In the issuance of common units.  We issued an aggregate 16,477,576 common units, which generated $449.4 million of net cash proceeds, in connection with our DRIP and EUPP during the nine months ended September 30, 2018.  This compares to an aggregate 32,518,315 common units2019, we issued in connection with our ATM, DRIP$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 EUPP duringjunior subordinated notes.  In the nine months ended September 30, 2017, which collectively generated $877.22018, we issued $2.7 billion aggregate principal amount of senior notes and junior subordinated notes and $950.2 million of net cash proceeds; and

§a $122.5 million period-to-period increase in cash distributions paid to limited partners during the nine months ended September 30, 2018 when compared to the nine months ended September 30, 2017.  The increase in cash distributions is due to increases in both the number of distribution-bearing common units outstanding and the quarterly cash distribution rates per unit; partially offset by

§
a net $327.0 million increase in net cash inflows attributable to debt issuances, which was comprised of an $832.9 million increase in net issuances of short-term notes under EPO’s commercial paper program, partially offset by a  $505.9 million period-to-period decrease in net cash inflows due to the issuancerepayment of $2.7$2.3 billion in principal amount of senior and junior subordinated notes offset by the repayment or redemption of $2.3 billion in principal amount of senior and junior subordinated notes during the nine months ended September 30, 2018 compared to the issuance of $1.7 billion in principal amount of junior subordinated notes and repayment of $800.0 million in principal amount of senior notes during the nine months ended September 30, 2017; and


§•
a $221.6$368.8 million period-to-period increase in cash contributions from noncontrolling interests.  In July 2019, Altus acquired a noncontrolling 33% equity interest in our consolidated subsidiary that owns the Shin Oak pipeline for an initial payment of $440.7 million.  In June 2019, an affiliate of American Midstream, LP acquired a noncontrolling 25% equity interest in our consolidated subsidiary that owns the Pascagoula natural gas processing plant for $36.0 million in cash.  In June 2018, an affiliate of Western acquired a noncontrolling 20% equity interest in our consolidated subsidiary that owns the Midland-to-ECHO Pipeline1 pipeline for $189.6 million in cash.  In addition, cash contributions from noncontrolling interests in connection with the construction of our ethylene export facility increased $47.0 million period-to-period; partially offset by


Sale of Red River System in October 2018
•
a $367.2 million period-to-period decrease in net cash proceeds from the issuance of common units in connection with our DRIP and EUPP.  As noted previously, EPD announced in July 2019 that, beginning with the quarterly distribution payment paid in August 2019, it would use common units purchased on the open market, rather than issuing new common units, to satisfy its delivery obligations under the DRIP and EUPP;
On October 1, 2018, we closed on the sale of our Red River System and associated crude oil linefill for approximately $135 million, of which $10.5 million was received as a deposit in the third quarter of 2018.   The Red River System gathers and transports crude oil from North Texas and southern Oklahoma for delivery to local refineries and pipeline interconnects for further transportation to the Cushing hub and Gulf Coast.   As of September 30, 2018, the carrying value of these assets totaled $109.6 million, which was classified as held-for-sale primarily within other current assets on our Unaudited Consolidated Balance Sheet.

•
an $88.2 million period-to-period increase in cash distributions paid to limited partners primarily due to an increase in the quarterly cash distribution rate per unit; and

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

Non-GAAP Cash Distributions to Limited PartnersFlow Measures


Distributable Cash Flow
Our partnership agreement requires us to make quarterly distributions to our unitholders of all available cash, after any cash reserves established by Enterprise GP in its sole discretion.  Cash reserves include those for the proper conduct of our business, including for example, those for capital expenditures, debt service, working capital, operating expenses, common unit repurchases, commitments and contingencies and other significant 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 “distributabledistributable cash flow” (“DCF”), which is a non-GAAP liquiditycash flow measure.  Distributable cash flowDCF is an important non-GAAP financial measure for our limited partners since it serves as an indicator of our success in providing a cash return on investment.  Specifically, this financial measure indicates to investors whether or not we are generating cash flows at a level that can sustain or support an increase in our declared quarterly cash distributions.  Distributable cash flowDCF is also a
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quantitative standard used by the investment community with respect to publicly traded partnerships becausesince 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 distributable cash flowDCF we generate to the cash distributions we expect to pay our partners.  Using this metric, management computes our distribution coverage ratio.  Our calculation of DCF may or may not be comparable to similarly titled measures used by other companies.



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


Our use of distributable cash flowDCF for the limited purposes described above and in this report is not a substitute for net cash flows provided by operating activities, which is the most comparable GAAP measure. For a discussion of net cash flows provided by operating activities, see the previous section titled “Cash Flows from Operating, Investing and Financing Activities” within this Part I, Item 2.


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


  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2018  2017  2018  2017 
Net income attributable to limited partners (1) $1,313.2  $610.9  $2,887.7  $2,025.3 
Adjustments to GAAP net income attributable to limited partners to derive non-GAAP distributable cash flow:                
Add depreciation, amortization and accretion expenses  471.2   412.6   1,360.5   1,221.4 
Add non-cash asset impairment and related charges  4.6   10.0   21.4   35.2 
Subtract net gains attributable to asset sales  (6.7)  (1.1)  (8.1)  (1.1)
Add cash proceeds from asset sales  21.5   3.0   24.1   6.2 
Subtract gain on step acquisition of unconsolidated affiliate  --   --   (39.4)  -- 
Add changes in fair value of Liquidity Option Agreement (2)  18.5   8.9   34.9   33.0 
Add or subtract changes in fair market value of derivative instruments  (204.1)  29.7   254.9   (14.2)
Add cash distributions received from unconsolidated affiliates (3)  139.2   123.1   392.7   353.0 
Add monetization of interest rate derivative instruments accounted for as cash flow hedges  --   30.6   1.5   30.6 
Subtract equity in income of unconsolidated affiliates  (112.0)  (113.4)  (350.0)  (315.2)
Subtract sustaining capital expenditures (4)  (76.2)  (53.8)  (215.3)  (164.1)
Add deferred income tax expense or subtract benefit, as applicable  (0.7)  0.4   9.3   1.1 
Other, net  12.2   4.0   27.9   34.2 
Distributable cash flow $1,580.7  $1,064.9  $4,402.1  $3,245.4 
                 
Total cash distributions paid to limited partners with respect to period $948.5  $913.4  $2,822.2  $2,712.8 
                 
Cash distributions per unit declared by Enterprise GP with respect to period (5) $0.4325  $0.4225  $1.2900  $1.2575 
                 
Total distributable cash flow retained by partnership with respect to period (6) $632.2  $151.5  $1,579.9  $532.6 
                 
Distribution coverage ratio (7)  1.7x   1.2x   1.6x   1.2x 
  
(1)   For a discussion of significant changes in our comparative income statement amounts underlying net income attributable to limited partners, along with the primary drivers of such changes, see “Consolidated Income Statements Highlights” within this Part I, Item 2.
(2)   For information regarding the Liquidity Option Agreement, see Note 16 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.
(3)   Reflects both distributions received on earnings from unconsolidated affiliates and those attributable to a return of capital from unconsolidated affiliates. For information regarding our unconsolidated affiliates, see Note 5 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.
(4)   Sustaining capital expenditures include cash payments and accruals applicable to the period.
(5)   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 periods presented.
(6)   At the sole discretion of Enterprise GP, cash retained by the partnership with respect to each of these periods was primarily reinvested in our growth capital spending program, which reduced our reliance on the equity and debt capital markets to fund such major expenditures.
(7)   Distribution coverage ratio is determined by dividing distributable cash flow by total cash distributions paid to limited partners and in connection with distribution equivalent rights with respect to the period.
 
  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2019  2018  2019  2018 
Net income attributable to limited partners (GAAP) (1) $1,019.2  $1,313.2  $3,494.4  $2,887.7 
Adjustments to net income attributable to limited partners to derive DCF
   (addition or subtraction indicated by sign):
                
Depreciation, amortization and accretion expenses  493.6   457.0   1,456.7   1,330.8 
Cash distributions received from unconsolidated affiliates (2)  170.6   139.2   485.1   392.7 
Equity in income of unconsolidated affiliates  (139.3)  (112.0)  (431.3)  (350.0)
Change in fair market value of derivative instruments  85.8   (204.1)  2.0   254.9 
Change in fair value of Liquidity Option Agreement  38.7   18.5   123.1   34.9 
Gain on step acquisition of unconsolidated affiliate  –   –   –   (39.4)
Sustaining capital expenditures (3)  (90.8)  (76.2)  (232.5)  (215.3)
Other, net  61.0   9.4   76.0   50.5 
Subtotal DCF, before proceeds from asset sales and monetization of interest rate derivative instruments accounted for as cash flow hedges $1,638.8  $1,545.0  $4,973.5  $4,346.8 
Proceeds from asset sales  0.7   21.5   16.8   24.1 
Monetization of interest rate derivative instruments accounted
    for as cash flow hedges
  –   –   –   1.5 
 DCF (non-GAAP) $1,639.5  $1,566.5  $4,990.3  $4,372.4 
                 
Cash distributions paid to limited partners with respect to period $974.4  $948.5  $2,907.0  $2,822.2 
                 
Cash distribution per unit declared by Enterprise GP with respect to period $0.4425  $0.4325  $1.3200  $1.2900 
                 
Total DCF retained by partnership with respect to period (4) $665.1  $618.0  $2,083.3  $1,550.2 
                 
Distribution coverage ratio (5)  1.68x  1.65x  1.72x  1.55x


(1)For a discussion of the primary drivers of changes in our comparative income statement amounts, see “Income Statements Highlights” within this Part I, Item 2.
(2)Reflects both distributions received on earnings from unconsolidated affiliates and those attributable to a return of capital from unconsolidated affiliates.
(3)Sustaining capital expenditures include cash payments and accruals applicable to the period.
(4)
At the sole discretion of Enterprise GP, cash retained by the partnership with respect to each of these periods was primarily reinvested in growth capital projects.  This retainage of cash substantially reduced our reliance on the equity capital markets to fund such expenditures.
(5)Distribution coverage ratio is determined by dividing DCF by total cash distributions paid to limited partners and in connection with distribution equivalent rights with respect to the period.

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


  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2018  2017  2018  2017 
Net cash flows provided by operating activities $1,577.5  $485.0  $4,275.3  $2,819.9 
Adjustments to reconcile net cash flows provided by operating activities
   to distributable cash flow:
                
      Subtract sustaining capital expenditures  (76.2)  (53.8)  (215.3)  (164.1)
      Add cash proceeds from asset sales  21.5   3.0   24.1   6.2 
      Add monetization of interest rate derivative instruments accounted
         for as cash flow hedges
  --   30.6   1.5   30.6 
      Net effect of changes in operating accounts  33.4   594.2   261.9   512.1 
      Other, net  24.5   5.9   54.6   40.7 
Distributable cash flow $1,580.7  $1,064.9  $4,402.1  $3,245.4 
 
 
 
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2019  2018  2019  2018 
Net cash flows provided by operating activities (GAAP) $1,642.5  $1,577.5  $4,826.2  $4,275.3 
Adjustments to reconcile net cash flows provided by operating activities to DCF (addition or subtraction indicated by sign):
                
      Net effect of changes in operating accounts  77.0   33.4   409.0   261.9 
      Sustaining capital expenditures  (90.8)  (76.2)  (232.5)  (215.3)
      Other, net  10.8   31.8   (12.4)  50.5 
DCF (non-GAAP) $1,639.5  $1,566.5  $4,990.3  $4,372.4 

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

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

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

FCF fluctuates based on our earnings, the level of investing activities we undertake each period, and the timing of operating cash receipts and payments.  In addition to providing the quarterly amounts presented below, we also provide a calculation of aggregate FCF over the twelve months ended September 30, 2019 in order to measure FCF over a longer term. The following table summarizes our calculation of FCF for the periods indicated (dollars in millions):

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

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


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Capital SpendingInvestments


We currently have approximately $6.0$9.1 billion of growth capital projects scheduled to be completed by mid-2020 including:the end of 2023 including the following major projects:


§joint venture-owned dock infrastructure in Corpus Christi designed to accommodate crude oil volumes (first quarter of 2019);
our iBDH facility (fourth quarter of 2019),


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


§the third processing train at our Orla natural gas processing facility (second quarter of 2019);
our ethylene export terminal and related infrastructure (fourth quarter of 2019 through the fourth quarter of 2020),


§expansions of our Front Range and Texas Express NGL pipelines (third quarter of 2019);
two new NGL fractionators in Chambers County, Texas (“Frac X” in the fourth quarter of 2019 and “Frac XI” in the first half of 2020),


§our isobutane dehydrogenation (“iBDH”) unit (fourth quarter of 2019);
our Mentone cryogenic natural gas processing plant and related infrastructure (first quarter of 2020),


§our ethylene export terminal (fourth quarter of 2019);
increase in LPG loading capacity at EHT (fourth quarter of 2020),


§a new NGL fractionation facility at Mont Belvieu (first half of 2020);
expansion projects involving our crude oil system between the Permian Basin and our ECHO terminal (third quarter of 2020),


§our Mentone cryogenic natural gas processing plant (first quarter of 2020); and
our Midland-to-ECHO 3 and 4 pipelines (third quarter of 2020 and first half of 2021, respectively),


§a 150 MBPD expansion of NGL fractionation capacity at our Mont Belvieu complex (second quarter of 2020).
expansion of our PGP export capabilities and an eighth deep-water ship dock at EHT for loading crude oil (both projects scheduled for fourth quarter of 2020),


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

expansion of our ATEX pipeline (fiscal 2022), and

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

Based on information currently available, we expect our total capital investments for 2019 to approximate a net $4.3 billion, which reflects growth capital spendingexpenditures of $4.5 billion, $350 million for 2018 to approximate $4.2 billion, which includes the $150.6 million we invested to acquire the remaining 50% equity interest in Delaware Processing.  We expect our sustaining capital expenditures for 2018and $0.6 billion of cash contributions from noncontrolling interests.  We currently expect growth capital investments to approximate $315 million, of which $221.5 million was spent$3.0 billion to $4.0 billion in the nine months ended September 30, 2018.2020.


Our forecast of capital spendinginvestments for 20182019 and 2020 is based on our 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 spendinginvestments due to factors beyond our control, such as adverse economic conditions, weather relatedweather-related issues and changes in supplier prices.  Furthermore, our forecast of capital spendinginvestments may change as a result ofdue to decisions made by management at a later date, which may include unforeseen acquisition opportunities.


Our success in raising capital, including the formation of joint venturespartnering 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 expendituresinvestments noted above, we may adjust the timing and amounts of projected expenditures in response to changes in capital market conditions.

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


 
For the Nine Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
 2018  2017  2019  2018 
Capital spending for property, plant and equipment: (1)
      
Capital investments for property, plant and equipment: (1)
      
Growth capital projects (2) $2,782.7  $1,953.8  $3,072.4  $2,782.7 
Sustaining capital projects (3)  221.5   164.4   229.7   221.5 
Total capital spending $3,004.2  $2,118.2 
Total $3,302.1  $3,004.2 
                
Cash used for business combinations, net (4)
 $150.6  $198.7  $–  $150.6 
                
Investments in unconsolidated affiliates $95.1  $32.8  $100.1  $95.1 
 
(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.
(4) Amount presented for the nine months ended September 30, 2018 represents the acquisition of the remaining 50% ownership interest in our Delaware Processing joint venture, which closed on March 29, 2018.
 


(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.

Fluctuations in our spending forinvestments in growth capital projects and investments in unconsolidated affiliates are explained in large part by increases or decreases in spending onexpenditures for major expansion projects. Our most significant growth capital expendituresinvestments for the nine months ended September 30, 2018 involved2019 involve projects to supportat our Mont Belvieu complex, crude oil natural gaspipelines in Texas and NGL production from the Permian Basin, export activities atexpansion projects involving our Gulf Coast terminal and spending on our iBDH unit.export terminals. Fluctuations in spending forinvestments in sustaining capital projects are explained in large part by the timing and cost of pipeline integrity and similar projects.


Comparison of Nine Months Ended September 30, 20182019 with Nine Months Ended September 30, 20172018
Total
Investments in growth capital spendingprojects at our Mont Belvieu complex increased a net $900.2$403.1 million period-to-period primarily due to construction activities surrounding Frac X and Frac XI, which accounted for a combined $425.5 million increase, our iBDH facility, which accounted for a $68.9 million increase, and expansion projects involving our DIBs, which accounted for an additional $62.9 million increase, partially offset by lower expenditures attributable to our PDH facility and ninth Mont Belvieu-area NGL fractionator (“Frac IX”), which accounted for a combined $182.8 million decrease.  Our PDH facility and Frac IX were both placed into service during the following:second quarter of 2018.


§Growth capital spending for projects to support Permian Basin production increased $585.6Investments in growth capital projects for ethylene-related pipelines, storage facilities and export assets increased $199.8 million period-to-period.  We are in various stages of completion on multiple projects to support crude oil, natural gas and NGL production in the Permian Basin, including our Orla natural gas processing facility and related pipelines and the Shin Oak NGL Pipeline.


§Growth capital spending on our iBDH unit increased $241.8 million period-to-period.
Investments in growth capital projects in support of Permian Basin production decreased $315.2 million period-to-period primarily due to lower expenditures at our Orla natural gas processing facility, which accounted for a $314.3 million decrease, and for our Shin Oak NGL Pipeline, which accounted for an additional $235.5 million decrease, partially offset by increased expenditures at our Mentone natural gas processing plant, which accounted for a $194.4 million increase.  The third processing train at our Orla natural gas processing facility was placed into service in July 2019.


§Growth capital spending for projects to expand and support export activities at EHT increased $210.3 million period-to-period.  This amount includes $55.2 million of cash paid in April 2018 to acquire a 65-acre waterfront site located on the Houston Ship Channel that will serve as the next phase of expansion at EHT.
Net cash used for business combinations during the nine months ended September 30, 2018 reflects our acquisition of the remaining 50% member interest in Delaware Processing in March 2018.


§Growth capital spending to expand refined products capabilities at our Beaumont terminal increased $68.6 million period-to-period.



§Investments in unconsolidated affiliates increased $62.3 million period-to-period primarily due to spending on our Front Range and Texas Express expansion projects, which accounted for $33.7 million of the increase, and our joint venture dock infrastructure at Corpus Christi, which accounted for an additional $15.3 million increase.


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§Growth capital spending at our Mont Belvieu complex for the PDH facility and ninth NGL fractionator decreased $314.3 million period-to-period.

§Net cash used for business combinations decreased $48.1 million period-to-period.  During the nine months ended September 30, 2018, we invested $150.6 million to acquire the remaining 50% equity interest in Delaware Processing.  For the same period in 2017, we used $191.4 million to acquire the BTA Gathering System and related assets.

Pipeline Integrity Program

Our pipelines operate under safety regulations administered by the U.S. Department of Transportation (“DOT”) that require pipeline integrity management programs for hazardous liquid and natural gas pipelines.  In general, these regulations require companies to assess the condition of their pipelines in certain high consequence areas (as defined by the regulation) and to perform any necessary repairs.

The following table summarizes our pipeline integrity costs, including those attributable to DOT regulations, for the periods presented (dollars in millions):

  
For the Three Months
Ended September 30,
  
For the Nine Months
Ended September 30,
 
  2018  2017  2018  2017 
Recognized in operating costs and expenses $13.3  $8.7  $57.6  $41.0 
Reflected as a component of sustaining capital expenditures  14.2   11.2   34.8   32.5 
     Total $27.5  $19.9  $92.4  $73.5 



Critical Accounting Policies and Estimates


A discussion of our critical accounting policies and estimates is included in our 20172018 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;
depreciation methods and estimated useful lives of property, plant and equipment;


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


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


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


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


Contractual Obligations


OurThe principal amount of our consolidated principal debt obligations were $28.2 billion at September 30, 2018 were approximately $26.13 billion2019 compared to $24.78$26.42 billion at December 31, 2017.2018.  For information regarding the scheduled maturities of such debt, see “Liquidity and Capital Resources – Consolidated Debt” within this Part I, Item 2.  See Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements under Part I, Item 1 of this quarterly report for additional information regarding our consolidated debt obligations.


During the first nine months ofSince December 31, 2018, we have entered into additional long-term product purchase commitments for crude oilNGLs with third party suppliers in order to meet future physical delivery obligations on our various systems.third-party suppliers.  On a combined basis, these new agreements increased our estimated long-term purchase obligations by approximately $1.2 $3.6 billion, with $1.3 billion committed over the next five years and $1.8$2.3 billion overall.  Apart from these new agreements, there have been no other material changes inthereafter.  At September 30, 2019, our consolidatedestimated long-term purchase obligations sincetotaled $12.7 billion after reflecting the agreements added during the first nine months of 2019 and those reported incommitments that expired during the year.  At December 31, 2018, our 2017 Form 10-K.estimated long-term purchase obligations totaled $10.8 billion.


Off-Balance Sheet Arrangements


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


Recent Accounting Developments


For information regarding recent developments involving changes in our accounting policies for revenue recognition, the presentation of restricted cash on the cash flow statement, and our work involving the new lease accounting standard,leases, see Note 2 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.


Related Party Transactions


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




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ItemITEM 3.  Quantitative and Qualitative Disclosures About Market Risk.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

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§the hedged forecasted transaction occurs within the expected time period.
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 1413 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report for additional information regarding our derivative instruments and hedging activities.


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Commodity Hedging Activities


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

The following table summarizes our portfolio of commodity derivative instruments outstanding at September 30, 20182019 (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 (Bcf)11.2n/aCash flow hedge
Forecasted sales of NGLs (MMBbls)0.20.1Cash flow hedge
Forecasted natural gas purchases for plant thermal reduction (billion cubic feet (“Bcf”))15.2n/aCash flow hedge
Forecasted sales of NGLs (million barrels (“MMBbls”))
1.8n/aCash flow hedge
Octane enhancement:      
Forecasted purchase of NGLs (MMBbls)1.10.2Cash flow hedge1.0n/aCash flow hedge
Forecasted sales of octane enhancement products (MMBbls)2.30.4Cash flow hedge8.11.6Cash flow hedge
Natural gas marketing:      
Natural gas storage inventory management activities (Bcf)2.0n/aFair value hedge3.2n/aFair value hedge
NGL marketing:      
Forecasted purchases of NGLs and related hydrocarbon products (MMBbls)36.80.2Cash flow hedge100.01.5Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products (MMBbls)60.00.2Cash flow hedge121.71.2Cash flow hedge
NGLs inventory management activities (MMBbls)0.2n/aFair value hedge0.3n/aFair value hedge
Refined products marketing:      
Forecasted purchase of refined products (MMBbls)0.6n/aCash flow hedge
Forecasted purchases of refined products (MMBbls)0.9n/aCash flow hedge
Forecasted sales of refined products (MMBbls)0.5n/aCash flow hedge0.9n/aCash flow hedge
Refined products inventory management activities (MMBbls)0.7n/aFair value hedge
Crude oil marketing:      
Forecasted purchases of crude oil (MMBbls)13.74.1Cash flow hedge10.4n/aCash flow hedge
Forecasted sales of crude oil (MMBbls)20.24.1Cash flow hedge13.8n/aCash flow hedge
Propylene marketing:   
Forecasted sales of NGLs for propylene marketing activities (MMBbls)0.3n/aCash flow hedge
Derivatives not designated as hedging instruments:
      
Natural gas risk management activities (Bcf) (3,4)89.72.5Mark-to-market
NGL risk management activities (MMBbls) (4)1.90.2Mark-to-market
Refined products risk management activities (MMBbls) (4)1.9n/aMark-to-market
Crude oil risk management activities (MMBbls) (4)54.217.7Mark-to-market
(1) Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes.
(2) The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is December 2020, March 2019 and December 2020, respectively.
(3) Current volumes include 33.3 Bcf of physical derivative instruments that are predominantly priced at a market-based index plus a premium or minus a discount related to location differences.
(4) Reflects the use of derivative instruments to manage risks associated with transportation, processing and storage assets.
Natural gas risk management activities (Bcf) (3)38.20.6Mark-to-market
NGL risk management activities (MMBbls) (3)2.4n/aMark-to-market
Refined products risk management activities (MMBbls) (3)7.6n/aMark-to-market
Crude oil risk management activities (MMBbls) (3)22.26.1Mark-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 January 2021, December 2019 and December 2022, respectively.
(3)Reflects the use of derivative instruments to manage risks associated with transportation, processing and storage assets.

At September 30, 2018,2019, our predominant commodity hedging strategies consisted of (i) hedging anticipated future purchases and sales of commodity products associated with transportation, storage and blending activities, (ii) hedging natural gas processing margins and (iii) hedging the fair value of commodity products held in inventory.  

§The objective of our anticipated future commodity purchases and sales hedging program is to hedge the margins of certain transportation, storage, blending and operational activities by locking in purchase and sale prices through the use of derivative instruments and related contracts.

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§The objective of our natural gas processing hedging program is to hedge an amount of earnings associated with these activities.  We achieve this objective by executing fixed-price sales for a portion of our expected equity NGL production using derivative instruments and related contracts.  For certain natural gas processing contracts, the hedging of expected equity NGL production also involves the purchase of natural gas for shrinkage, which is hedged using derivative instruments and related contracts.
Sensitivity Analysis

§The objective of our inventory hedging program is to hedge the fair value of commodity products currently held in inventory by locking in the sales price of the inventory through the use of derivative instruments and related contracts.


The following table showstables show the effect of hypothetical price movements (a sensitivity analysis) on the estimated economic valuefair values of our natural gas marketing portfolio at the dates indicated (dollars in millions):

   Portfolio Fair Value at 
Scenario
Resulting
Classification
December 31,
2017
 
September 30,
2018
 
October 15,
2018
 
Fair value assuming no change in underlying commodity pricesAsset (Liability) $(13.9) $(3.1) $(8.6)
Fair value assuming 10% increase in underlying commodity pricesAsset (Liability)  (16.9)  (3.8)  (10.2)
Fair value assuming 10% decrease in underlying commodity pricesAsset (Liability)  (10.8)  (2.3)  (7.0)

The following table shows the effect of hypothetical price movements (a sensitivity analysis) on the estimated economic value of our NGL marketing, refined products marketing and octane enhancementprincipal commodity derivative instrument portfolios at the dates indicated (dollars in millions):.

   Portfolio Fair Value at 
Scenario
Resulting
Classification
December 31,
2017
 
September 30,
2018
 
October 15,
2018
 
Fair value assuming no change in underlying commodity pricesAsset (Liability) $(76.4) $(244.8) $(159.4)
Fair value assuming 10% increase in underlying commodity pricesAsset (Liability)  (126.1)  (331.2)  (251.0)
Fair value assuming 10% decrease in underlying commodity pricesAsset (Liability)  (26.8)  (158.4)  (67.9)


The following table showsfair value information presented in the effectsensitivity analysis tables excludes the impact of hypotheticalapplying 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 movements (a sensitivity analysis)fluctuations until they are settled in accordance with their contractual terms. Derivative transactions cleared on exchanges other than the estimated economic value of our crudeCME (e.g., the Intercontinental Exchange or ICE) continue to be reported on a gross basis.

Natural gas marketing portfolio
   Portfolio Fair Value at 
Scenario
Resulting
Classification
December 31,
2018
 
September 30,
2019
 
October 15,
2019
 
Fair value assuming no change in underlying commodity pricesAsset (Liability) $7.8  $2.5  $3.1 
Fair value assuming 10% increase in underlying commodity pricesAsset (Liability)  8.0   0.2   1.5 
Fair value assuming 10% decrease in underlying commodity pricesAsset (Liability)  7.7   4.7   4.7 

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

Crude oil marketing portfolio at the dates indicated (dollars in millions):
   Portfolio Fair Value at 
Scenario
Resulting
Classification
December 31,
2018
 
September 30,
2019
 
October 15,
2019
 
Fair value assuming no change in underlying commodity pricesAsset (Liability) $(26.5) $27.4  $31.0 
Fair value assuming 10% increase in underlying commodity pricesAsset (Liability)  (88.6)  (0.2)  1.8 
Fair value assuming 10% decrease in underlying commodity pricesAsset (Liability)  35.6   55.0   60.2 


   Portfolio Fair Value at 
Scenario
Resulting
Classification
December 31,
2017
 
September 30,
2018
 
October 15,
2018
 
Fair value assuming no change in underlying commodity pricesAsset (Liability) $(65.5) $(336.2) $(323.4)
Fair value assuming 10% increase in underlying commodity pricesAsset (Liability)  (109.4)  (419.1)  (409.0)
Fair value assuming 10% decrease in underlying commodity pricesAsset (Liability)  (21.6)  (253.4)  (237.8)


The derivative liability for our crude oil marketing hedges increased from $65.5 million at December 31, 2017 to $336.2 million at September 30, 2018, which resulted in a $270.7 million decrease in the fair value of the crude oil marketing portfolio for the nine months ended September 30, 2018. The derivative liability for the portfolio improved to $323.4 million at October 15, 2018 primarily due to lower crude oil futures prices as well as a narrowing of the crude oil basis spreads since September 30, 2018.  As noted in our discussion of results for the Crude Oil Pipelines & Services segment within Part I, Item 2 of this quarterly report, we entered into hedges of the crude oil commodity price differentials between the Midland and Houston markets and the Midland and Cushing markets.


Assuming no changes subsequent to September 30, 2018 in the variables used to determine the portfolio’s fair value, the derivative liability of $336.2 million at September 30, 2018 would be reversed upon cash settlement of the underlying hedges, which would create unrealized mark-to-market gains in net income and other comprehensive income as follows for the periods indicated (dollars in millions):

Fourth quarter of 2018 $167.0 
Calendar year 2019  131.6 
Calendar year 2020  5.0 
Total mark-to-market gains $303.6 
Total other comprehensive income  32.6 
Total comprehensive income $336.2 

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As the non-cash, mark-to-market gains attributable to the financial hedges are recognized in earnings, the corresponding actual losses on the financial hedges and related gains on the physical transactions will be simultaneously realized.

At September 30, 2018, approximately 68% of the Midland-to-ECHO Pipeline’s uncommitted capacity available to us through 2020 was not hedged, thereby providing us with potential upside to widening or downside to narrowing market spreads.   The value of this unhedged capacity was approximately $439.8 million assuming that we hedged all such capacity at the prevailing crude oil commodity price differentials between Midland and Houston as of September 30, 2018.

The posting of additional cash may be required to maintain our commodity derivative instruments portfolio as prices fluctuate or margin requirements change.  Our restricted cash balance decreased from $248.9 million at September 30, 2018 to $235.0 million at October 15, 2018.  In addition, we posted $211.7 million of cash and $100.0 million under stand-by letters of credit in connection with margin requirements on the Chicago Mercantile Exchange through October 15, 2018. The decrease in restricted cash and other cash postings since September 30, 2018 is primarily due to changes in the initial margin requirements and fair value of our crude oil marketing transportation hedges.


Interest Rate Hedging Activities


We may utilize interest rate swaps, forward startingforward-starting swaps, options to enter into forward-starting swaps (“swaptions”),  and similar derivative instruments to manage our exposure to changes in interest rates charged on borrowings under certain consolidated debt agreements.  This strategy may be used in controlling our overall cost of capital associated with such borrowings.  The composition of our derivative instrument portfolios may change depending on our hedging requirements. We have no

Sensitivity Analysis

With respect to the tabular data below, the portfolio’s estimated economic value at a given date is based on a number of factors, including the number and types of derivatives outstanding at that date, the notional value of the swaps and
associated interest rates.

At September 30, 2019, our interest rate hedging instruments outstanding asportfolio consisted of 12 forward-starting swaps, which hedge the filing dateexpected underlying benchmark interest rates related to future issuances of debt.  The following table summarizes our portfolio of these swaps at September 30, 2019 (dollars in millions).

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

(1)These swaps were entered into in May 2019.
(2)These swaps were entered into in September 2019 as a result of a swaption exercise.  See “Interest Rate Hedging Activities” under Note 13 of the Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report for additional information regarding the swaption exercise and related loss at inception.

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

   
Forward-Starting Swap
Portfolio Fair Value at
 
Scenario
Resulting
Classification
December 31,
2018
 
September 30,
2019
 
November 7,
2019
 
Fair value assuming no change in underlying interest ratesAsset (Liability) $–  $(118.6) $(37.1)
Fair value assuming 10% increase in underlying interest ratesAsset (Liability)  –   (71.7)  5.0 
Fair value assuming 10% decrease in underlying interest ratesAsset (Liability)  –   (168.0)  (79.2)

The $81.5 million change in the fair value of this quarterly report.portfolio from September 30, 2019 to November 7, 2019 was due to an increase in the underlying 30-year variable interest rates relative to the fixed interest rates stated in the associated swap agreements.





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ItemITEM 4.  Controls and Procedures.CONTROLS AND PROCEDURES.


Disclosure Controls and Procedures


As of the end of the period covered by this quarterly report, our management carried out an evaluation, with the participation of (i) A. James Teague, our general partner’s Chief Executive Officer and (ii) W. Randall Fowler, our general partner’s President and Chief Financial Officer, 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 principal executive officer and Mr. Fowler is 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 2018,2019, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting. 


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.
ITEM 1.  LEGAL PROCEEDINGS.


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


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

For additional information regarding our litigation matters, see “Litigation” under Note 1615 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report, which subsection is incorporated by reference into this Part II, Item 1.




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ItemITEM 1A.  Risk Factors.RISK FACTORS.


An investment in our securities involves certain risks. Security holders and potential investors in our securities should carefully consider the risks described under “Risk Factors” set forth in Part I, Item 1A of our 20172018 Form 10-K, in addition to other information in such annual report.  The risk factors set forth in our 20172018 Form 10-K 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.




ItemITEM 2.  Unregistered Sales of Equity Securities and Use of Proceeds.UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.


Issuer Purchases of Equity Securities


The following table summarizes our equity repurchase activity during the nine months ended September 30, 2018 in connection with the vestingthird quarter of phantom unit awards:2019:


Period 
Total Number
of Units
Purchased
  
Average
Price Paid
per Unit
  
Total Number of
Units Purchased
as Part of Publicly
Announced Plans
  
Maximum
Number of Units
That May Yet
Be Purchased
Under the Plans
 
   January 2018 (1)  2,559  $27.73   --   -- 
   February 2018 (2)  945,409  $26.40   --   -- 
   March 2018 (3)  1,810  $25.68   --   -- 
   May 2018 (4)  34,827  $26.85   --   -- 
   August 2018 (5)  41,756  $29.35   --   -- 
  
(1)   Of the 8,000 phantom unit awards that vested in January 2018 and converted to common units, 2,559 units were sold back to us by employees to cover related withholding tax requirements.
(2)   Of the 3,156,811 phantom unit awards that vested in February 2018 and converted to common units, 945,409 units were sold back to us by employees to cover related withholding tax requirements.
(3)   Of the 6,050 phantom unit awards that vested in March 2018 and converted to common units, 1,810 units were sold back to us by employees to cover related withholding tax requirements.
(4)   Of the 115,115 phantom unit awards that vested in May 2018 and converted to common units, 34,827 units were sold back to us by employees to cover related withholding tax requirements.
(5)   Of the 151,692 phantom unit awards that vested in August 2018 and converted to common units, 41,756 units were sold back to us by employees to cover related withholding tax requirements.
 
Period 
Total Number
of Units
Purchased
  
Average
Price Paid
per Unit
  
Total
Number
Of Units
Purchased
as Part of
2019 Buyback
Program
  
Remaining
Dollar Amount
of Units
That May
Be Purchased
Under the 2019 Buyback
Program
($ thousands)
 
2019 Buyback Program: (1)            
   July 2019  –  $–   –  $1,923,165 
   August 2019  –  $–   –  $1,923,165 
   September 2019  –  $–   –  $1,923,165 
Vesting of phantom unit awards:                
   July 2019  –  $–   n/a   n/a 
   August 2019 (2)  85,412  $28.82   n/a   n/a 
   September 2019  –  $–   n/a   n/a 


(1)In January 2019, we announced the 2019 Buyback Program, which authorized the repurchase of up to $2 billion of EPD’s common units.  See “Significant Recent Developments” under Part I, Item 2 of this quarterly report for additional information.  The repurchased units were cancelled immediately upon acquisition.
(2)
Of the 248,962 phantom unit awards that vested in August 2019 and converted to common units, 85,412 units were sold back to us by employees to cover related withholding tax requirements.  These repurchases are not part of any announced program.  We cancelled these units immediately upon acquisition.



ItemITEM 3.  Defaults Upon Senior Securities.DEFAULTS UPON SENIOR SECURITIES.


None.


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Table of Contents
ITEM 4.  MINE SAFETY DISCLOSURES.
Item 4.
Mine Safety Disclosures.


Not applicable.




ItemITEM 5.  Other Information.OTHER INFORMATION.


None.On November 6, 2019, Dan Duncan LLC executed Amendment No. 2 to Enterprise GP’s Fifth Amended and Restated Limited Liability Company Agreement in response to changes to the Internal Revenue Code enacted by the Bipartisan Budget Act of 2015 relating to partnership audit and adjustment procedures.  The foregoing description of the amendment is qualified in its entirety by reference to the full text thereof, which is filed as Exhibit 3.12 hereto and incorporated by reference herein.



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ItemITEM 6.  Exhibits.EXHIBITS.



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

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2.13
Agreement and Plan of Merger, dated as of November 11, 2014, by and among Enterprise Products Partners L.P., Enterprise Products Holdings LLC, EPOT MergerCo LLC, Oiltanking Partners, L.P. and OTLP GP, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed November 12, 2014).
2.14
Amendment No. 1 dated as of June 6, 2018 to Contribution and Purchase Agreement, by and among Enterprise Products Partners L.P., Oiltanking Holding Americas, Inc., Enterprise Products Holdings LLC and Marquard & Bahls, AG (incorporated by reference to Exhibit 2.2 to Form 8-K filed June 12, 2018).
3.1
Certificate of Limited Partnership of Enterprise Products Partners L.P. (incorporated by reference to Exhibit 3.6 to Form 10-Q filed November 9, 2007).
3.2
Certificate of Amendment to Certificate of Limited Partnership of Enterprise Products Partners L.P., filed on November 22, 2010 with the Delaware Secretary of State (incorporated by reference to Exhibit 3.6 to Form 8-K filed November 23, 2010).
3.3
Sixth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated November 22, 2010 (incorporated by reference to Exhibit 3.2 to Form 8-K filed November 23, 2010).
3.4
Amendment No. 1 to Sixth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated effective as of August 11, 2011 (incorporated by reference to Exhibit 3.1 to Form 8-K filed August 16, 2011).
3.5
Amendment No. 2 to Sixth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated effective as of August 21, 2014 (incorporated by reference to Exhibit 3.1 to Form 8-K filed August 26, 2014).
3.6
Amendment No. 3 to the Sixth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated as of November 28, 2017 (incorporated by reference to Exhibit 3.1 to Form 8-K filed December 1, 2017).
3.7
Amendment No. 4 to the Sixth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated as of February 26, 2019 (incorporated by reference to Exhibit 3.7 to Form 10-K filed March 1, 2019).
3.8
Certificate of Formation of Enterprise Products Holdings LLC (formerly named EPE Holdings, LLC) (incorporated by reference to Exhibit 3.3 to Form S-1/A Registration Statement, Reg. No. 333-124320, filed by Enterprise GP Holdings L.P. on July 22, 2005).
3.83.9
Certificate of Amendment to Certificate of Formation of Enterprise Products Holdings LLC (formerly named EPE Holdings, LLC), filed on November 22, 2010 with the Delaware Secretary of State (incorporated by reference to Exhibit 3.5 to Form 8-K filed November 23, 2010).
3.93.10
Fifth Amended and Restated Limited Liability Company Agreement of Enterprise Products Holdings LLC dated effective as of September 7, 2011 (incorporated by reference to Exhibit 3.1 to Form 8-K filed September 8, 2011).
3.103.11
Amendment No. 1 to Fifth Amended and Restated Limited Liability Company Agreement of Enterprise Products Holdings LLC, dated effective as of April 26, 2017 (incorporated by reference to Exhibit 3.1 to Form 8-K filed May 2, 2017).
3.113.12#
Amendment No. 2 to Fifth Amended and Restated Limited Liability Company Agreement of Enterprise Products Holdings LLC, dated effective as of November 6, 2019.
3.13
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).
3.123.14
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).
3.133.15
Bylaws of Enterprise Products OLPGP, Inc., dated December 8, 2003 (incorporated by reference to Exhibit 3.6 to Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).
4.1
Form of Common Unit certificate (incorporated by reference to Exhibit A to Exhibit 3.1 to Form 8-K filed August 16, 2011).
4.2
Indenture, dated as of March 15, 2000, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and First Union National Bank, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed March 14, 2000).

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4.3
Second Supplemental Indenture, dated as of February 14, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 10-K filed March 31, 2003).
4.4
Third Supplemental Indenture, dated as of June 30, 2007, among Enterprise Products Operating L.P., as Original Issuer, Enterprise Products Partners L.P., as Parent Guarantor, Enterprise Products Operating LLC, as New Issuer, and U.S. Bank National Association, as successor Trustee (incorporated by reference to Exhibit 4.55 to Form 10-Q filed August 8, 2007).
4.5
Indenture, dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed October 6, 2004).
4.6
Fourth Supplemental Indenture, dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.5 to Form 8-K filed October 6, 2004).
4.7
Sixth Supplemental Indenture, dated as of March 2, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed March 3, 2005).
4.8
Amended and Restated Eighth Supplemental Indenture, dated as of August 25, 2006, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed August 25, 2006).
4.9
Ninth Supplemental Indenture, dated as of May 24, 2007, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed May 24, 2007).
4.10
Tenth Supplemental Indenture, dated as of June 30, 2007, among Enterprise Products Operating L.P., as Original Issuer, Enterprise Products Partners L.P., as Parent Guarantor, Enterprise Products Operating LLC, as New Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.54 to Form 10-Q filed August 8, 2007).
4.11
Eleventh Supplemental Indenture, dated as of September 4, 2007, 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 September 5, 2007).
4.12
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).
4.134.12
Sixteenth Supplemental Indenture, dated as of October 5, 2009, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed October 5, 2009).
4.144.13
Seventeenth Supplemental Indenture, dated as of October 27, 2009, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed October 28, 2009).
4.154.14
 
Eighteenth Supplemental Indenture, dated as of October 27, 2009, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed October 28, 2009).
4.164.15
Nineteenth Supplemental Indenture, dated as of May 20, 2010, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed May 20, 2010).


92
85


4.174.16
Twentieth Supplemental Indenture, dated as of January 13, 2011, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed January 13, 2011).
4.184.17
Twenty-First Supplemental Indenture, dated as of August 24, 2011, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed August 24, 2011).
4.194.18
Twenty-Second Supplemental Indenture, dated as of February 15, 2012, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.25 to Form 10-Q filed May 10, 2012).
4.204.19
Twenty-Third Supplemental Indenture, dated as of August 13, 2012, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed August 13, 2012).
4.214.20
Twenty-Fourth Supplemental Indenture, dated as of March 18, 2013, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed March 18, 2013).
4.224.21
Twenty-Fifth Supplemental Indenture, dated as of February 12, 2014, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed February 12, 2014).
4.234.22
Twenty-Sixth Supplemental Indenture, dated as of October 14, 2014, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed October 14, 2014).
4.244.23
Twenty-Seventh Supplemental Indenture, dated as of May 7, 2015, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee(incorporated by reference to Exhibit 4.3 to Form 8-K filed May 7, 2015).
4.254.24
Twenty-Eighth Supplemental Indenture, dated as of April 13, 2016, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed April 13, 2016).
4.264.25
Twenty-Ninth Supplemental Indenture, dated as of August 16, 2017, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed August 16, 2017).
4.274.26
Thirtieth Supplemental Indenture, dated as of February 15, 2018, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed February 15, 2018).
4.284.27
Thirty-First Supplemental Indenture, dated as of February 15, 2018, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed February 15, 2018).
4.294.28
Thirty-Second Supplemental Indenture, dated as of October 11, 2018, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed October 11, 2018).

86
93

4.29
Thirty-Third Supplemental Indenture, dated as of July 8, 2019, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed July 8, 2019).
4.30
Form of Global Note representing $499.2 million principal amount of 6.875% Series B Senior Notes due 2033 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 10-K filed March 31, 2003).
4.31
Form of Global Note representing $350.0 million principal amount of 6.65% Series B Senior Notes due 2034 with attached Guarantee (incorporated by reference to Exhibit 4.19 to Form S-3 Registration Statement, Reg. No. 333-123150, filed March 4, 2005).
4.32
Form of Global Note representing $250.0 million principal amount of 5.75% Series B Senior Notes due 2035 with attached Guarantee (incorporated by reference to Exhibit 4.32 to Form 10-Q filed November 4, 2005).
4.33
Form of Global Note representing an aggregate of $550.0 million principal amount of Junior Subordinated Notes due 2066 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.2 to Form 8-K filed August 25, 2006).
4.34
Form of Global Note representing $800.0 million principal amount of 6.30% Senior Notes due 2017 with attached Guarantee (incorporated by reference to Exhibit 4.38 to Form 10-Q filed November 9, 2007).
4.35
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).
4.364.35
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).
4.374.36
Form of Global Note representing $600.0 million principal amount of 6.125% Senior Notes due 2039 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed October 5, 2009).
4.384.37
Form of Global Note representing $349.7 million principal amount of 6.65% Senior Notes due 2018 with attached Guarantee (incorporated by reference to Exhibit D to Exhibit 4.1 to Form 8-K filed October 28, 2009).
4.394.38
Form of Global Note representing $399.6 million principal amount of 7.55% Senior Notes due 2038 with attached Guarantee (incorporated by reference to Exhibit E to Exhibit 4.1 to Form 8-K filed October 28, 2009).
4.404.39
Form of Global Note representing $285.8 million principal amount of Junior Subordinated Notes due 2067 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.2 to Form 8-K filed October 28, 2009).
4.414.40
Form of Global Note representing $1.0 billion principal amount of 5.20% Senior Notes due 2020 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed May 20, 2010).
4.424.41
Form of Global Note representing $600.0 million principal amount of 6.45% Senior Notes due 2040 with attached Guarantee (incorporated by reference to Exhibit C to Exhibit 4.3 to Form 8-K filed May 20, 2010).
4.43
Form of Global Note representing $750.0 million principal amount of 3.20% Senior Notes due 2016 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed January 13, 2011).
4.444.42
Form of Global Note representing $750.0 million principal amount of 5.95% Senior Notes due 2041 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed January 13, 2011).
4.454.43
Form of Global Note representing $650.0 million principal amount of 4.05% Senior Notes due 2022 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed August 24, 2011).
4.464.44
Form of Global Note representing $600.0 million principal amount of 5.70% Senior Notes due 2042 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed August 24, 2011).
4.474.45
Form of Global Note representing $750.0 million principal amount of 4.85% Senior Notes due 2042 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.25 to Form 10-Q filed May 10, 2012).

87
94

4.484.46
Form of Global Note representing $1.1 billion principal amount of 4.45% Senior Notes due 2043 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed August 13, 2012).
4.494.47
Form of Global Note representing $1.25 billion principal amount of 3.35% Senior Notes due 2023 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed March 18, 2013).
4.504.48
Form of Global Note representing $1.0 billion principal amount of 4.85% Senior Notes due 2044 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed March 18, 2013).
4.514.49
Form of Global Note representing $850.0 million principal amount of 3.90% Senior Notes due 2024 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed February 12, 2014).
4.524.50
Form of Global Note representing $1.15 billion principal amount of 5.10% Senior Notes due 2045 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed February 12, 2014).
4.534.51
Form of Global Note representing $800.0 million principal amount of 2.55% Senior Notes due 2019 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.4 to Form 8-K filed October 14, 2014).
4.544.52
Form of Global Note representing $1.15 billion principal amount of 3.75% Senior Notes due 2025 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.4 to Form 8-K filed October 14, 2014).
4.554.53
Form of Global Note representing $400.0 million principal amount of 4.95% Senior Notes due 2054 with attached Guarantee (incorporated by reference to Exhibit C to Exhibit 4.4 to Form 8-K filed October 14, 2014).
4.564.54
Form of Global Note representing $400.0 million principal amount of 4.85% Senior Notes due 2044 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed March 18, 2013).
4.574.55
Form of Global Note representing $750.0 million principal amount of 1.65% Senior Notes due 2018 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed May 7, 2015).
4.584.56
Form of Global Note representing $875.0 million principal amount of 3.70% Senior Notes due 2026 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed May 7, 2015).
4.594.57
Form of Global Note representing $875.0 million principal amount of 4.90% Senior Notes due 2046 with attached Guarantee (incorporated by reference to Exhibit C to Exhibit 4.3 to Form 8-K filed May 7, 2015).
4.604.58
Form of Global Note representing $575.0 million principal amount of 2.85% Senior Notes due 2021 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.4 to Form 8-K filed April 13, 2016).
4.614.59
Form of Global Note representing $575.0 million principal amount of 3.95% Senior Notes due 2027 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.4 to Form 8-K filed April 13, 2016).
4.624.60
Form of Global Note representing $100.0 million principal amount of 4.90% Senior Notes due 2046 with attached Guarantee (incorporated by reference to Exhibit C to Exhibit 4.3 to Form 8-K filed May 7, 2015).
4.634.61
Form of Global Note representing $700 million principal amount of Junior Subordinated Notes D due 2077 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed August 16, 2017).
4.644.62
Form of Global Note representing $1.0 billion principal amount of Junior Subordinated Notes E due 2077 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed August 16, 2017).

88


4.654.63
Form of Global Note representing $750.0 million principal amount of 2.80% Senior Notes due 2021 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.4 to Form 8-K filed February 15, 2018).
4.664.64
Form of Global Note representing $1.25 billion principal amount of 4.25% Senior Notes due 2048 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.4 to Form 8-K filed February 15, 2018).
4.674.65
Form of Global Note representing $700 million principal amount of Junior Subordinated Notes F due 2078 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed February 15, 2018).
4.684.66
Form of Global Note representing $750.0 million principal amount of 3.50% Senior Notes due 2022 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed October 11, 2018).
4.694.67
Form of Global Note representing $1,000.0 million principal amount of 4.15% Senior Notes due 2028 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed October 11, 2018).
4.704.68
Form of Global Note representing $1,250.0 million principal amount of 4.80% Senior Notes due 2049 with attached Guarantee (incorporated by reference to Exhibit C to Exhibit 4.3 to Form 8-K filed October 11, 2018).
4.69
Form of Global Note representing $1,250.0 million principal amount of 3.125% Senior Notes due 2029 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed July 8, 2019).
4.70
Form of Global Note representing $1,250.0 million principal amount of 4.200% Senior Notes due 2050 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed July 8, 2019).
4.71
Replacement Capital Covenant, dated July 18, 2006, executed by Enterprise Products Operating L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 99.1 to Form 8-K filed July 19, 2006).
4.72
First Amendment to Replacement Capital Covenant dated August 25, 2006, executed by Enterprise Products Operating L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 99.2 to Form 8-K filed August 25, 2006).
4.73
Replacement Capital Covenant, dated May 24, 2007, executed by Enterprise Products Operating L.P. and Enterprise Products Partners L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 99.1 to Form 8-K filed May 24, 2007).
4.74
Replacement Capital Covenant, dated October 27, 2009, executed by Enterprise Products Operating LLC and Enterprise Products Partners L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 4.9 to Form 8-K filed October 28, 2009).
4.75
Amendment to Replacement Capital Covenants, dated May 6, 2015, executed by Enterprise Products Operating LLC and Enterprise Products Partners L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 4.59 to Form 10-Q filed May 8, 2015).
4.76
Indenture, dated February 20, 2002, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as Subsidiary Guarantors, and First Union National Bank, NA, as Trustee (incorporated by reference to Exhibit 99.2 to the Form 8-K filed by TEPPCO Partners, L.P. on February 20, 2002).
4.77
Supplemental Indenture, dated June 27, 2002, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as Initial Subsidiary Guarantors, Val Verde Gas Gathering Company, L.P., as New Subsidiary Guarantor, and Wachovia Bank, National Association, formerly known as First Union National Bank, as Trustee (incorporated by reference to Exhibit 4.6 to the Form 10-Q filed by TEPPCO Partners, L.P. on August 14, 2002).
4.78
Full Release of Guarantee, dated July 31, 2006, by Wachovia Bank, National Association, as Trustee, in favor of Jonah Gas Gathering Company (incorporated by reference to Exhibit 4.8 to the Form 10-Q filed by TEPPCO Partners, L.P. on November 7, 2006).

89


4.79
Fourth Supplemental Indenture, dated June 30, 2007, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Val Verde Gas Gathering Company, L.P., TE Products Pipeline Company, LLC and TEPPCO Midstream Companies, LLC, as Subsidiary Guarantors, and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.3 to the Form 8-K filed by TE Products Pipeline Company, LLC on July 6, 2007).
4.80
Sixth Supplemental Indenture, dated March 27, 2008, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.12 to the Form 10-Q filed by TEPPCO Partners, L.P. on May 8, 2008).
4.81
Seventh Supplemental Indenture, dated March 27, 2008, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.13 to the Form 10-Q filed by TEPPCO Partners, L.P. on May 8, 2008).
4.82
Eighth Supplemental Indenture, dated October 27, 2009, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 to the Form 8-K filed by TEPPCO Partners, L.P. on October 28, 2009).
4.83
Full Release of Guarantee, dated November 23, 2009, of TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P. by U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.64 to Form 10-K filed March 1, 2010).
4.84
Indenture, dated May 14, 2007, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and The Bank of New York Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 99.1 of the Form 8-K filed by TEPPCO Partners, L.P. on May 15, 2007).
4.85
First Supplemental Indenture, dated May 18, 2007, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and The Bank of New York Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.2 to the Form 8-K filed by TEPPCO Partners, L.P. on May 18, 2007).
4.86
Second Supplemental Indenture, dated as of June 30, 2007, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Val Verde Gas Gathering Company, L.P., as Existing Subsidiary Guarantors, TE Products Pipeline Company, LLC and TEPPCO Midstream Companies, LLC, as New Subsidiary Guarantors, and The Bank of New York Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.2 to the Form 8-K filed by TE Products Pipeline Company, LLC on July 6, 2007).
4.87
Third Supplemental Indenture, dated as of October 27, 2009, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and The Bank of New York Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.2 to the Form 8-K filed by TEPPCO Partners, L.P. on October 28, 2009).
4.88
Full Release of Guarantee, dated as of November 23, 2009, of TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P. by The Bank of New York Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.70 to Form 10-K filed March 1, 2010).

90


4.89
Registration Rights Agreement by and between Enterprise Products Partners L.P. and Oiltanking Holding Americas, Inc. dated as of October 1, 2014 (incorporated by reference to Exhibit 4.1 to Form 8-K filed October 1, 2014).
10.1***
Retirement, Consulting Services and Release Agreement, dated effective as of August 16, 2019, between Enterprise Products Company and William Ordemann (incorporated by reference to Exhibit 10.1 to Form 8-K filed August 22, 2019).
10.2
364-Day Revolving Credit Agreement, dated as of September 12, 2018,10, 2019 among Enterprise Products Operating LLC, the Lenders party thereto, and Citibank, N.A. as Administrative Agent (incorporated by reference to Exhibit 10.1 to Form 8-K filed September 12, 2018)11, 2019).
10.210.3
Guaranty Agreement, dated as of September 12, 2018,10, 2019, by Enterprise Products Partners L.P. in favor of Citibank, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.2 to Form 8-K filed September 12, 2018)11, 2019).
10.3***10.4
SeparationFirst Amendment to Revolving Credit Agreement, dated effective as of September 11, 2018 by and between10, 2019, among Enterprise Products CompanyOperating LLC, the Lenders party thereto, and Bryan F. BulawaWells Fargo Bank, National Association, as Administrative Agent (incorporated by reference to Exhibit 10.3 to Form 8-K filed September 12, 2018)11, 2019).
31.1#
Sarbanes-Oxley Section 302 certification of A. James Teague for Enterprise Products Partners L.P.’s quarterly report on Form 10-Q for the nine months ended September 30, 2018.2019.
31.2#
Sarbanes-Oxley Section 302 certification of W. Randall Fowler for Enterprise Products Partners L.P.’s quarterly report on Form 10-Q for the nine months ended September 30, 2018.2019.
32.1#
Sarbanes-Oxley Section 906 certification of A. James Teague for Enterprise Products Partners L.P.’s quarterly report on Form 10-Q for the nine months ended September 30, 2018.2019.
32.2#
Sarbanes-Oxley Section 906 certification of W. Randall Fowler for Enterprise Products Partners L.P.’s quarterly report on Form 10-Q for the nine months ended September 30, 2018.2019.
101.CAL#101#
XBRL Calculation Linkbase Document
Interactive data files pursuant to Rule 405 of Regulation S-T formatted in iXBRL (Inline Extensible Business Reporting Language): (i) our Unaudited Condensed Consolidated Balance Sheets as of September 30, 2019 and December 31, 2018; (ii) our Unaudited Condensed Statements of Consolidated Operations for the three and nine months ended September 30, 2019 and 2018; (iii) our Unaudited Condensed Statements of Consolidated Comprehensive Income for the three and nine months ended September 30, 2019 and 2018; (iv) our Unaudited Condensed Statements of Consolidated Cash Flows for the nine months ended September 30, 2019 and 2018; (v) our Unaudited Condensed Statements of Consolidated Equity for the three and nine months ended September 30, 2019 and 2018; and (vi) the notes to our Unaudited Condensed Consolidated Financial Statements.
101.DEF#104#
Cover Page Interactive Data File (embedded within the Inline XBRL Definition Linkbase Document
101.INS#
XBRL Instance Document
101.LAB#
XBRL Labels Linkbase Document
101.PRE#
XBRL Presentation Linkbase Document
101.SCH#
XBRL Schema Document
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.

91





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 8, 2018.2019.


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






















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